[QUARTER-PAGE RECTANGLE SILHOUETTE
APPEARS IN UPPER-RIGHT OF COVER]
NEES achieved
its seventh consecutive
year of superior
financial results in 1995
while retaining our
position as New England's
lowest cost major
electricity provider.
Annual Report 1995
[LOGO] New England Electric System
[PHOTO OF MANCHESTER STREET STATION
APPEARS HERE]
The repowering of our Manchester Street
Station was successfully completed in 1995.
Contents
Letter to Shareholders 2
An Industry in Transition 6
The NEES Response 8
Renewing Our Assets 10
Financial Review 14
Financial Statements 23
Notes to Financial Statements 30
Report of Management 41
Report of Independent Accountants 41
Shareholder Information 42
NEES Directors and Officers -
NEES Subsidiaries 45
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The New England Electric System subsidiaries:
Massachusetts Electric Company, The Narragansett Electric Company, and Granite
State Electric Company, retail electric companies that provide electricity and
related services to 1.3 million customers in 194 communities in Massachusetts,
Rhode Island, and New Hampshire;
New England Power Company, a wholesale electric generating company that
operates five thermal generating stations, 14 hydroelectric generating
stations, a pumped storage station, and approximately 2,400 miles of
transmission lines;
New England Electric Resources, Inc., an independent project development and
consulting company that seeks investment opportunities in power plant
modernization, transmission, and environmental improvement;
New England Electric Transmission Corporation, New England Hydro-Transmission
Corporation, and New England Hydro-Transmission Electric Company, Inc.,
electric transmission companies that developed, own, and operate facilities
associated with the high voltage, direct current interconnection between New
England and Quebec;
Narragansett Energy Resources Company, a wholesale electric generating company
that owns 20 percent of the Ocean State Power generating station in Rhode
Island;
New England Energy Incorporated, an oil and gas exploration and development
company;
New England Power Service Company, a service company that provides
administrative, legal, engineering, and other support to its affiliated NEES
subsidiaries.
FINANCIAL HIGHLIGHTS
1995 1994
---- ----
Earnings per average share 3.15 $3.07
Dividends declared per share $2.345 $2.285
Book value per share year end $25.13 $24.33
Market price per share year end $39-5/8 $32-1/8
Growth in kilowatt-hour (kWh) sales
to ultimate customers 0.7% 1.6%
Cost per kWh to ultimate
customers (cents) 9.54 9.29
Return on Common Equity - 1995
New England Electric System 12.8%
Median of U.S. Electric Utilities 11.7%
Median of New England/New York Electric Utilities 10.4%
New England Electric System (NEES) is a public utility holding company
headquartered in Westborough, Massachusetts. The NEES family of companies,
described on the inside page to the left, constitutes the second largest
electric utility system in New England. Core business activities are the
generation, transmission, distribution, and sale of electric energy and the
delivery of related services, including energy efficiency improvements, to
residential, commercial, industrial, and municipal customers. Other business
activities include independent transmission projects and energy management
consultation. The NEES companies are guided by the following commitment: "We
pledge to provide our customers the highest possible value by continuously
improving electric service, managing costs, and reducing adverse environmental
impacts."
TO OUR FELLOW SHAREHOLDERS
Our financial results in 1995 highlighted the seventh good year in a row
for New England Electric System (NEES).
Earnings per share were $3.15, compared with $3.07 in 1994.
Return on common equity was 12.8 percent, placing NEES in the top-third
of major electric utilities in the nation. Our returns on equity have been in
the top-third of utilities in the Northeast in each of the last seven years.
The total return on NEES shares met our target of top-third performance
among U.S. electric utilities on a rolling five-year basis.
Bond ratings were maintained at A+ or higher in 1995, above national
averages and the best among major New England utilities.
Your quarterly dividend was increased again in May 1995 and now stands
at an annual level of $2.36 per share, an increase of 16 percent over the past
five years.
Our average retail rate of 9.5 cents per kilowatt-hour remained the
lowest among major utilities in New England. Our average rates have increased
only 1.5 percent per year since 1991, approximately half the increase in both
the average rate of other regional utilities and of the Consumer Price Index.
Most important, we held our regional cost advantage while maintaining
reliability and expanding services to customers.
Manchester Street repowering
The repowering of our Manchester Street Station in Providence, Rhode
Island was completed ahead of schedule and under budget. This 489 megawatt,
$450 million facility is now the cleanest and most efficient fossil-fueled
power plant in New England and, in 1995 dollars, represents the lowest
construction cost per kilowatt of any major plant recently built in our
region.
Forging a "new" industry
While our performance in 1995 and previous years has created many
strengths to carry us forward, we, like other utilities, face challenging
times as our industry is restructured. In last year's annual report, we
described how the laws and regulations governing utilities are being changed
to increase competition. New regulations permitting competitors to use utility
transmission and distribution systems to reach customers may alter the
structure, operations, and financial position of much of our industry.
[PHOTO OF JOAN BOK APPEARS HERE]
Joan T. Bok,
Chairman of the Board
At NEES, we believe that we can best protect our investors and serve
customers by working to make such regulations fair and practical, rather than
by opposing competition. While much remains to be worked out, our efforts to
date have helped to bring about preliminary orders of several state utility
commissions that respect the rights of utility shareholders, as is described
more fully later in this report.
Responding to the requirements of our regulators, our Massachusetts
retail subsidiary in February 1996 submitted our Choice: New England plan to
the Commonwealth's Department of Public Utilities. The plan is summarized on
page 9. We hope to test elements of the plan through pilot programs in
Massachusetts and New Hampshire.
In Rhode Island, legislation was filed by the leadership of the state's
House of Representatives in February 1996 that would phase in retail
competition over a four-year period beginning in 1998. It parallels many of
the features of Choice: New England.
Savings to Rhode Island customers would be substantial. The NEES
companies would recover their sunk investments in power plants and contracts
with independent power producers through a transition charge. Although the
bill would attain these savings by reducing our return on the assets covered
by the transition charge and by placing substantial competitive pressure on
our future revenues and operating costs, we consider it to be a sensible and
practical compromise and are supporting its enactment.
Focus on financial performance
As we enter the new world of competition, our employees are committed to
shareholder value. Approximately 90 percent are owners of NEES shares through
various investment programs. Employee ownership equals 8 percent of the total
shares outstanding. In 1995, the NEES Board of Directors adopted share
ownership targets for senior managers.
In addition, a significant percentage of our employees' compensation -
ranging from 14 percent to nearly 60 percent depending on the person's
position and length of service in the organization - will hinge on NEES
meeting annual targets for earnings and customer costs.
[PHOTO OF JOHN W. ROWE APPEARS HERE]
Jown W. Rowe, President
and Chief Executive Officer
Management changes
Two members of the NEES senior management team retired on December 31,
1995. Frederic E. Greenman, senior vice president, general counsel, and
secretary, retired with 26 years of service. His outstanding judgment and
counsel have helped NEES meet the challenges of the past decades and prepared
it to thrive in the industry of the future. John W. Newsham, vice president,
retired with 45 years of service to the NEES companies. Mr. Newsham provided
invaluable leadership in such areas as the Manchester Street Station
repowering project, hydro relicensing, labor relations, and employee safety.
Joining our senior management is Cheryl A. LaFleur, who was elected NEES
vice president, general counsel, and secretary. Ms. LaFleur's responsibilities
include legal and governmental affairs as well as corporate communications.
She has held a number of legal and management positions with the NEES
companies, most recently vice president of retail marketing for Massachusetts
Electric.
The future
In 1996, we have two principal goals. First, we will strive to reach
final resolution of restructuring plans with our three states and our federal
regulators that protect the interests of our shareholders and give us an
opportunity to grow and prosper in the future. Second, we will seek to develop
new business opportunities and market products that will meet our customers'
energy needs and help us compete successfully in a restructured industry. We
have the people, the attitude, and the assets to meet these challenges.
On behalf of all employees of the NEES companies, we thank you for your
continued confidence and investment in New England Electric System.
s/ Joan T. Bok
Joan T. Bok
Chairman of the Board
s/ John W. Rowe
John W. Rowe
President and Chief Executive Officer
March 1, 1996
All Five of NEES's
Key Financial Goals were
Achieved in 1995
-------------------------
Dividend Growth exceeded
average of electric
utilities on rolling 5-year
average.
Return on Equity in
top one-third of major
New York and
New England utilities.
Cash Flow coverage
of dividend in top
one-third of major electric utilities.
Investment Quality
Auditors' reports not
qualified and
bond ratings A+.
Total Return in top
one-third of major U.S.
Electric utilities on rolling
5-year average.
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Shaping Change
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Opening
the door to
competition
AN INDUSTRY IN TRANSITION
With the passage of the Energy Policy Act of 1992, the Federal Energy
Regulatory Commission (FERC) began to develop policies to foster a competitive
wholesale market for electricity. Today, a number of states are advocating
that retail sales of electricity also be competitive. Retail competition would
enable all retail customers - including residential customers - to choose who
supplies their electricity.
Large differences in electricity prices, both between neighboring
utilities and across the U.S., are behind the call for changing the way that
electricity is sold. While rates in the Northeast and California are 50
percent higher than in some other parts of the country, NEES's cost per kWh is
the lowest of any major New England utility, with an advantage in most cases
of 10 to 30 percent.
In 1994, the California Public Utilities Commission announced a plan to
begin retail competition. Since that announcement, many legislators and
regulators have advocated more retail competition, with the expectation that
it will lower prices and enhance the business climate in their respective
states.
Restructuring the electric industry will not mean deregulation of
utilities. Our most valuable assets - transmission and distribution systems -
would continue to be regulated and would be used by our competitors. In other
words, we would be required to permit third parties to use our wires at
regulated rates so that they may compete against us to supply electricity to
customers.
The generating capacity that electric utilities own or have contracted
for was built in accordance with state requirements to meet expected demand,
including demand on the hottest and coldest days of the year. We are required
to maintain reserve generating capacity to cover contingencies. Utilities also
have been required to make generation commitments 10 to 20 years into the
future, based on forecasts of economic growth that haven't always been
realized. The result is excess capacity in New England's generating plants,
some of which the utilities can sell to others at wholesale, but at a price
that often doesn't reflect the total price of production.
Under these circumstances, if utility wires were simply thrown open to
competitors at historic cost rather than at their real value, the market price
of electricity would fall to a level approaching the fuel cost of operating
our power plants. Utilities would not collect sufficient revenues to cover all
of their other operating costs or the fixed costs of the plants they built
under a regulated regime. Competition on these terms would leave us with large
fixed costs for generating electricity that would be unrecoverable, or
"stranded."
The FERC has recognized that existing investments should not be stranded
by open access, stating: "Industry restructuring must go forward so that a
competitive marketplace will become a reality. But we cannot expect the
utilities to be willing participants unless we ensure that their prudently
incurred costs are recovered. That is the only fair way to proceed."
[PHOTO CAPTION]
Opening utility wires
to competition will require
an access or transition
charge to assure
[PHOTO OF POWER PLANT APPEARS HERE]
recover of utility
investments in generation
and independent power
production contracts.
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Defining a
restructuring
strategy
THE NEES RESPONSE
During the first half of 1995, the NEES companies negotiated with a
variety of stakeholders to agree upon interdependent principles to guide the
introduction of retail competition in New England. The principles support
retail competition, the integrity of contracts with independent power
producers, recovery of stranded investments, and continued environmental
improvement.
Both the Massachusetts and Rhode Island commissions issued orders in
August 1995 requiring utilities to file plans to introduce retail competition.
Both orders substantially reflect the interdependent principles. The
Massachusetts order stated: "Utilities should have a reasonable opportunity to
recover net, non-mitigatable, stranded costs associated with commitments
previously incurred pursuant to their legal obligations to provide electric
service..."
Earlier in 1995, the Rhode Island legislature had passed bills that
would have introduced retail competition without provisions for stranded cost
recovery. The Governor vetoed these bills, subject in part to the requirement
that our subsidiary Narragansett Electric file a retail competition plan
within one year.
On February 7, 1996, the leadership of the Rhode Island House of
Representatives introduced legislation containing a detailed approach to
retail competition. The bill phases in customer choice beginning in 1998 for
large manufacturers and new commercial and industrial customers, and choice
for all by 2001. If choice comes into play more quickly in other New England
states and 50 percent or more customers have choice, the Rhode Island dates
would advance. The bill protects all customers by allowing them to stay with
their existing utility under a capped rate if they so choose. We believe it to
be the most decisive and equitable legislation proposed anywhere and have
given it our support.
On February 16, 1996, our Massachusetts retail subsidiary, Massachusetts
Electric, submitted our plan for introducing competition. Entitled Choice: New
England, the plan foresees competitive markets for electricity generation and
regulated transmission and distribution, and would allow customers to choose
electricity suppliers beginning January 1, 1998. Customers could choose to
obtain power through their current supplier or contract directly with a
market-based supplier. As in the Rhode Island legislation, utilities would
recover stranded costs through an access or transition charge.
In New Hampshire, where our subsidiary Granite State Electric has 36,000
customers, the Governor, Legislature, and Public Utilities Commission have
moved to introduce retail competition for electricity suppliers, because rates
in most of the state are among the nation's highest. The PUC proposed a retail
pilot program in response to legislation enacted in 1995. All New Hampshire
utilities including Granite State Electric have challenged aspects of this
proposal, especially the provision that only 50 percent of stranded costs
would be recovered. Hearings before the PUC will be held in March 1996.
[PHOTO CAPTION]
Through consensus
building and persuasive
advocacy, the NEES
[PHOTO OF INDIVIDUAL MAKING PRESENTATION APPEARS HERE]
companies helped to
set a direction for electric
industry restructuring.
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Skilled
people reinforce
our assets
RENEWING OUR ASSETS
While sober about the challenges facing our business, we are also
optimistic because we bring many strengths to the competitive world.
Dollars & sense
Our relatively strong balance sheet will permit us to recover
potentially stranded costs in a reasonable time frame, therefore enhancing our
relative competitiveness compared with other utilities in our region.
Cost control, conservative accounting, avoidance of deferrals, and
comparatively low nuclear ownership all strengthen our balance sheet. Cost
control measures implemented in 1995 include the completion of the Manchester
Street repowering project more than $130 million under budget and the launch
of a supply chain management process to reduce our expenditures for goods and
services.
Profitable relationships
Our customer relationships go far beyond reliable delivery of
electricity at the region's lowest prices. Our continuous service improvements
- - such as energy conservation programs, fast restoration of outages,
consolidated billing for customers with multiple sites, and power quality
programs - are building the strong customer relationships that will endure in
the competitive marketplace.
When we open our new Customer Services Center in 1996 with
around-the-clock hours and up-to-date computers and communications
technologies, customers will find it even easier and faster to deal with us.
Physical assets
Our transmission and distribution network consists of 2,700 miles of
transmission lines and more than 20,000 miles of distribution lines. These
lines and associated facilities and rights-of-way would be very expensive,
difficult, and time-consuming to permit and build today and are necessary for
an efficient competitive system.
The repowering of Manchester Street Station represents the
cost-effective use of a valuable piece of developed property. The project was
the largest construction project in Rhode Island's history. Entering service
in late 1995, the plant is the cleanest and most efficient fossil-fueled plant
in New England and is competitive with independent power facilities.
We use a variety of fuels and power sources to run our plants, and some
of our generating units run on more than one fuel. The mix of coal, natural
gas, nuclear, hydro, oil, and renewables is to our advantage when we negotiate
fuel prices, and provides some protection from large fluctuations in the price
of any one fuel.
People
Constant training and retraining of our employees is key to implementing
new technologies, setting higher standards, promoting safety, and changing the
way we work to meet the challenges of competition.
[PHOTO CAPTION]
Our employees
will make the
NEES companies
[PHOTO OF HIGH-TENSION LINES AND LINE ENGINEERS APPEARS HERE]
formidable competitors
in a restructured electric
utility industry.
In 1995, nearly 25 percent of our employees participated in one or more
sessions at our training center in Millbury, Massachusetts. Programs include
indoor and outdoor skills instruction as well as computer, management, and
leadership training.
Reinforcing our efforts to prepare for competition are new four-year
labor agreements reached in May 1995 with our three labor unions. The
contracts include performance-based bonuses tied to earnings per share and to
individual employee performance. We believe they are the first utility/union
contracts in the U.S. that incorporate these performance-based measures.
Environment
We have achieved many "firsts" that demonstrate our commitment to
environmentally responsible and progressive operations.
For example, we are the first utility in Massachusetts to sell nitrogen
oxide credits which were earned by reducing emissions at our plants ahead of
regulatory deadlines, and are the first electric utility to receive America's
Corporate Conscience Award for Environmental Stewardship from the Council on
Economic Priorities. We are also the only utility in New England that is
recycling high-carbon flyash from coal-fired power plants into saleable
products.
Reputation
Reputations grow slowly and require constant attention to endure.
Growing ours took years of superior public service and hard work.
We believe we have earned the reputation of being a company that
provides reliable electricity, does so at a lower price than its neighbors,
gets involved in the communities it serves, and goes the extra mile to help
customers get the most for their energy dollars. What matters is the
day-to-day work we do and accomplishments such as the quick return of power to
2,000 customers after a tornado tore a wide path of destruction last May in
rural Great Barrington, Massachusetts.
Meeting new challenges
These assets have helped us to weather past challenges and emerge a
winner in the regulated world. The same assets - a strong financial position,
hardworking employees who are able to meet new challenges, environmentally
responsible operations, and a strong reputation - are basic ingredients for
continued success in the brave new world of competitive electricity markets.
[PHOTO CAPTION]
Our relationships with
customers are
[PHOTO OF CUSTOMERS WORKING AT BOTTLING PLANT]
sustained by continuous
service improvements.
Financial Report
Financial Review 14
Financial Statements 23
Selected Financial Data 23
Consolidated Income Statements 24
Consolidated Retained Earnings
Statements 24
Consolidated Balance Sheets 25
Consolidated Cash Flow Statements 26
Consolidated Capitalization Statements 27
Notes to Consolidated Financial
Statements 28
Report of Management 41
Report of Independent Accountants 41
Shareholder Information 42
FINANCIAL REVIEW
[GRAPH APPEARS HERE]
Overview
Earnings in 1995 were $3.15 per share compared with $3.07 and $2.93 per
share in 1994 and 1993, respectively. The 1995 return on common equity was
12.8 percent.
The increase in 1995 earnings reflects slightly higher kilowatt-hour
(kWh) sales to ultimate customers, decreased depreciation and amortization
expense, and decreased operation and maintenance expenses, partially offset by
higher purchased power and interest expenses.
The increase in 1994 earnings over 1993 was attributable to increased
kWh sales to ultimate customers, decreased purchased power and interest
expenses, and the amortization of unbilled revenues. In addition, earnings in
1993 were reduced by the one-time effects of an early retirement program and
the establishment of additional gas waste reserves. These factors were
partially offset by increased operation and maintenance expenses and a
temporary rate reduction in 1994.
In 1995, kWh sales to ultimate customers increased less than 1 percent.
This increase was primarily due to a return to more normal weather in the
fourth quarter of 1995, along with a warmer summer in 1995, partially offset
by lower sales in the first quarter of 1995 due to unusually mild weather. In
1994, kWh sales to ultimate customers increased 1.6 percent over 1993,
reflecting an improved regional economy.
In May 1995, the annual dividend rate was raised to $2.36, which
represents a $.06 per share increase on an annual basis. In 1994, the annual
dividend rate was also increased $.06 per share. The market price of New
England Electric System (NEES) common shares at the end of 1995 was $39-5/8
per share compared with $32-1/8 per share and $39-1/8 per share at the end of
1994 and 1993, respectively.
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 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 NEES companies derive approximately 70 percent, 23 percent, and 3
percent of their electric sales revenues from ultimate customers in
Massachusetts, Rhode Island, and New Hampshire, respectively. Each of the NEES
retail subsidiaries purchases electricity on behalf of their customers under
wholesale all-requirements contracts with NEES's wholesale generating
subsidiary, New England Power Company (NEP).
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.
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, the pricing of which would be
approved in advance by 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. However, the plan
proposes that cost of service pricing of distribution rates would be
supplemented by a system that would reward or penalize distribution utilities
for their performance relative to benchmarks established by regulators.
[GRAPH APPEARS HERE]
Choice: New England proposes that the cost of NEP's past generation
commitments that are at risk due to competition be recovered through a wires
access or transition charge. Those generation 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. Under Choice: New England, the access
charge would be set at three cents per kWh for the first three years.
Thereafter, the access charge would vary, but is expected to decline.
Choice: New England was formally filed by Massachusetts Electric Company
(Massachusetts Electric) with the MDPU in February 1996. Massachusetts
Electric also announced that it will request the MDPU to allow the
implementation of two pilot programs to test the plan. The first would allow
high technology customers 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
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 be required to divest their generating
assets, either through sale or spinoff. The NEES companies are opposed to
mandatory divestiture of generation assets. The timetable for consideration of
the various plans by the MDPU is uncertain. The transition access charges
proposed in Choice: New England are also subject to approval by the Federal
Energy Regulatory Commission (FERC).
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 The Narragansett Electric
Company's (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 transmission and distribution wires. The legislation divides those
past commitments in the same manner as Choice: New England. The principal
difference between the legislation and Choice: New England is that the
legislation proposes a 12-year recovery period for utility generation
commitments and regulatory assets.
[GRAPH APPEARS HERE]
The legislation also establishes performance-based rates for
distribution utilities, including Narragansett. Under the legislation,
Narragansett would be entitled to annually increase its distribution rates by
approximately $10 million per year, for the period 1997 to 1999, less any
increases in wholesale base rates passed on to Narragansett by NEP. For those
three years, Narragansett's return on equity would be subject to a floor of 6
percent and a ceiling of 11 percent. Earnings over the ceiling would be shared
equally between customers and shareholders up to an absolute cap on return on
equity of 12.5 percent. To the extent that earnings fall below the floor,
Narragansett would be authorized to surcharge customers for the shortfall.
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 (see "Retail rate
activity" section) and to submit, by July 1, 1996, 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. In the event that the Rhode Island
Legislature does not enact the 1996 proposed legislation discussed above, the
commitment to submit a specific proposal on open access is expected to be met
by Narragansett through the filing of Choice: New England with the RIPUC.
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 Senate.
In January 1996, Granite State Electric Company (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 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. 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.
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, which is under appeal, did not set a precedent for
stranded cost recovery as part of industry restructuring.
In March 1995, the FERC issued a notice of proposed rulemaking in which
it stated that it is appropriate that legitimate and verifiable stranded costs
be recovered from departing customers as a result of wholesale competition.
The FERC also indicated that costs stranded as a result of retail competition
would be subject to state commission review if the necessary statutory
authority exists and subject to FERC review if the state commission does not
have such authority. A final decision is expected during 1996.
[GRAPH APPEARS HERE]
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 NEES companies. First, there can be no
assurance that a final restructuring plan ordered by regulatory bodies, 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, NEES 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. NEES expects this situation to
continue in a retail market. Third, revenues will also be affected by the NEES
companies' 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 NEES companies 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 operations
of its subsidiaries 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, NEES had
consolidated pre-tax regulatory assets (net of regulatory liabilities) of
approximately $600 million, of which about $500 million is related to its
subsidiaries' generation business (including approximately $200 million
related to oil and gas properties regulated as part of the generation
business), and about $100 million is related to its subsidiaries' transmission
and distribution businesses. If competitive or regulatory change should cause
a substantial revenue loss or lead to the permanent shutdown of any generating
facilities, a substantial 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 NEES and its subsidiaries 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 NEES's subsidiaries operate. 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.
[GRAPH APPEARS HERE]
Wholesale rate activity
In February 1995, the FERC approved a rate agreement filed by NEP. Under
the agreement, which became effective January 1995, NEP's base rates are
frozen through 1996. Before this rate agreement, NEP's rate structure
contained two surcharges that were recovering the costs of a coal conversion
project and a portion of NEP'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 postretirement benefits other than
pensions (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 NEP'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. The FERC's approval of this rate agreement
applies to all of NEP'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.)
Retail rate activity
The MDPU approved a $31 million increase to base rates for Massachusetts
Electric effective October 1, 1995.
The RIPUC approved a settlement agreement that provides for a $15
million increase to base rates for Narragansett effective December 1, 1995.
The RIPUC also approved $3 million of new discounts for manufacturing
customers, the costs of which are not being recovered from other customers.
In July 1995, Granite State filed a $2.6 million rate increase request
with the NHPUC. On October 31, 1995, Granite State received approval to
collect an interim increase of $0.9 million, effective November 1, 1995,
subject to refund or surcharge pending the final outcome of the full case. The
NHPUC staff is recommending a rate decrease of approximately $0.3 million. A
final decision is expected in 1996.
The retail companies have received approval from their respective
regulatory agencies to recover demand-side management (DSM) program
expenditures in rates on a current basis. These expenditures were $64 million,
$70 million, and $62 million in 1995, 1994, and 1993, respectively. Since
1990, the retail companies have been allowed to earn incentives based on the
results of their DSM programs and have recorded before-tax incentives of $5.7
million, $7.7 million, and $7.3 million in 1995, 1994, and 1993, respectively.
[GRAPH APPEARS HERE]
Operating revenue
Operating revenue increased $29 million in 1995 compared with 1994. This
increase reflects sales growth of less than 1 percent, increased fuel
revenues, the November 1994 expiration of Massachusetts Electric's temporary
rate decrease, and the October 1995 Massachusetts Electric rate increase.
These increases were partially offset by a decrease in the amortization of
unbilled revenues in 1995.
Operating revenue increased $9 million in 1994, reflecting increased
sales and amortization of unbilled revenues by retail subsidiaries, partially
offset by the temporary rate reduction at Massachusetts Electric. In 1994, kWh
sales to ultimate customers increased 1.6 percent over 1993, reflecting an
improved regional economy.
Operating expenses
Total operating expenses increased $2 million in 1995 compared with
1994, reflecting increased purchased power and fuel expenses. The increase in
purchased power expense reflects overhauls and refueling shutdowns at
partially-owned nuclear power facilities, including costs to repair steam
generator tubes at the Maine Yankee nuclear power plant (Maine Yankee), in
which NEP has a 20 percent interest. Maine Yankee returned to service at 90
percent capacity in January 1996. The increase in purchased power expense also
includes the amortization of previously deferred purchased power contract
termination costs.
The increase in fuel costs, including the fuel portion of purchased
power expense, reflects decreased nuclear generation due to overhauls and
decreased hydro production resulting from low water levels.
Depreciation and amortization expense decreased in 1995 due to reduced
amortization of Seabrook 1 in accordance with NEP's 1995 rate agreement, the
completion of the amortization of the costs of certain coal conversion
facilities in the first half of 1995, and decreased oil and gas amortization
due to decreased production. Partially offsetting these decreases were
increased depreciation rates approved in NEP's 1995 rate agreement, increased
charges associated with the dismantlement of a retired generating facility,
and depreciation of new plant expenditures, including the Manchester Street
Station, which began commercial operation in the second half of 1995.
The decrease in maintenance expenses reflects lower overhaul costs at
wholly-owned generating units, primarily in the fourth quarter of 1995.
The increase in taxes, other than income taxes, is due to increased
municipal property taxes.
Total operating expenses increased $15 million in 1994 over 1993,
reflecting increases in overhaul costs of wholly-owned generating units, in
part to achieve compliance with the Clean Air Act. Operating expenses in 1994
also reflected cost increases in DSM, computer system development, pension and
other retiree benefits, and general increases in other areas. These increases
were partially offset by decreases in fuel and purchased power expense due to
overhauls and refueling shutdowns of partially-owned nuclear power suppliers
in 1993. In addition, 1993 operating expenses included a net amount of $30
million associated with an early retirement and special severance program and
the establishment of additional gas waste reserves, partially offset by the
effects of a rate settlement that allowed recovery of previously charged
expenses.
Depreciation and amortization increased $4 million in 1994, reflecting
increased amortization of Seabrook 1, increased charges for dismantlement of a
previously retired generating station, and depreciation of new plant
expenditures. These increases were partially offset by decreased oil and gas
amortization due to decreased production.
Taxes charged to operations in 1994 increased approximately $12 million,
reflecting increased income taxes and municipal property taxes.
Under the existing terms of certain purchased power contracts with other
utilities, NEP will reduce its power purchases by $19 million in 1996.
Interest expense
Interest expense increased $23 million in 1995 due to an increase in
combined long-term and short-term debt balances and higher interest rates
earlier in 1995. Interest expense decreased $6 million in 1994, due to
significant refinancings of corporate debt at lower interest rates.
Allowance for funds used during construction (AFDC)
AFDC increased $4 million and $11 million in 1995 and 1994,
respectively, 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 "Liquidity and capital resources" 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.
NEES and/or its subsidiaries have been named as potentially responsible
parties (PRPs) by either the U.S. Environmental Protection Agency (EPA) or the
Massachusetts Department of Environmental Protection for 22 sites at which
hazardous waste is alleged to have been disposed. Private parties have also
contacted or initiated legal proceedings against NEES and certain subsidiaries
regarding hazardous waste cleanup. The most prevalent types of hazardous waste
sites with which NEES and its subsidiaries have been associated are
manufactured gas locations. (Until the early 1970s, NEES was a combined
electric and gas holding company system.) NEES is aware of approximately 40
such locations (including eight of the 22 locations for which NEES companies
are PRPs) mostly located in Massachusetts. NEES and its subsidiaries are
currently aware of other sites, and may in the future become aware of
additional sites, that they may be held responsible for remediating.
NEES has been notified by the EPA that it is one of several PRPs for
cleanup of the Pine Street Canal Superfund site in Burlington, Vermont, where
coal tar and other materials were deposited. Between 1931 and 1951, NEES and
its predecessor owned all of the common stock of Green Mountain Power
Corporation (GMP). Prior to, during, and after that time, gas was manufactured
at the Pine Street Canal site by GMP. In 1989, NEES was one of 14 parties
required to pay the EPA's past response costs related to this site. NEES
remains a PRP for ongoing and future response costs. In November 1992, the EPA
proposed a cleanup plan estimated by the EPA to cost $50 million. In June
1993, the EPA withdrew this cleanup plan in response to public concern about
the plan and its cost. The cost of any cleanup plan and NEES's share of such
cost are uncertain at this time. NEES has been involved in settlement
negotiations, which it expects to conclude in 1996, to determine NEES's
apportioned share of these costs. NEES believes it has adequate reserves for
this site.
In 1993, the MDPU approved a Massachusetts Electric rate agreement that
allows for remediation costs of former manufactured gas sites and certain
other hazardous waste sites located in Massachusetts to be met from a
non-rate-recoverable, interest-bearing fund of $30 million established on
Massachusetts Electric's books in 1993. Rate-recoverable contributions of $3
million, adjusted for inflation, are added to the fund annually in accordance
with the agreement. Any shortfalls in the fund would be paid by Massachusetts
Electric and be recovered through rates over seven years.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
NEES or its subsidiaries. Where appropriate, the NEES companies intend to seek
recovery from their insurers and from other PRPs, but it is uncertain whether,
and to what extent, such efforts will be successful. At December 31, 1995,
NEES had total reserves for environmental response costs of $50 million and a
related regulatory asset of $19 million. NEES believes that hazardous waste
liabilities for all sites of which it is aware, and which are not covered by a
rate agreement, are not material to its financial position.
Electric and magnetic fields (EMF)
Concerns have been raised about whether EMF, which occur near
transmission and distribution lines as well as near household wiring and
appliances, cause or contribute to adverse health effects. Numerous studies on
the effects of these fields, some of them sponsored by electric utilities
(including NEES companies), have been conducted and are continuing. Some of
the studies have suggested associations between certain EMF and health
effects, including various types of cancer, while other studies have not
substantiated such associations. It is impossible to predict the ultimate
impact on NEES subsidiaries 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 NEES companies believe that they currently have 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
NEES companies would be if this cause of action is recognized in the states in
which NEES companies operate and in contexts other than condemnation cases.
Purchased power contract dispute
In October 1994, NEP was sued by MPLP, a venture of Enron Corporation
and Jones Capital that owns a 149 megawatt (MW) gas-fired power plant in
Milford, Massachusetts. NEP purchases 56 percent of the power output of the
facility under a long-term contract with MPLP. The suit alleges that NEP 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 NEP 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 NEP deliberately misled regulatory bodies concerning the
Manchester Street Station repowering project. MPLP seeks compensatory damages
in an unspecified amount, as well as treble damages. NEP believes that the
allegations of wrongdoing are without merit. NEP 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 NEP'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.
Liquidity and capital resources Capital requirements for 1995 and
projections for 1996 are shown below:
Year ended December 31 (millions of dollars) 1995 1996
---- ----
Cash expenditures for utility plant:
Manchester Street Station repowering project $ 98 $ 20
All other 231 225
Oil and gas exploration and development 18 15
---- ----
Total capital expenditures $347 $260
Maturing debt and prepayment requirements 66 24
---- ----
Total capital requirements $413 $284
---- ----
Cash from utility operations after
payment of dividends $261 $265
---- ----
Cash from oil and gas operations 52 35
---- ----
Total cash from operations after
payment of dividends $313 $300
The long-term financing activities of the NEES subsidiaries for 1995 and
projected long-term financings for 1996 are summarized as follows:
1995 Actual 1996 Projected
----------- --------------
(millions of dollars) IssuesRetirements Issues Retirements
----------------- ------ -----------
NEP $ 60 $ 10 $ 40 $ 50
Massachusetts Electric 88 35 20
Narragansett 38 16 12 2
Granite State 5 3 1
Hydro-Transmission Companies 12 12
New England Energy
Incorporated (NEEI) 202 236 35
Narragansett Energy
Resources Company 32 1
----- ----- ---- ----
$425 $312 $ 72 $101
Interest rates on long-term debt issued in 1995 range from 6.69 percent
to 8.46 percent. NEP and the retail subsidiaries have issued $42 million of
variable and fixed rate long-term debt to date in 1996 to refinance a like
amount of outstanding debt.
Net cash from operating activities provided all of the funds necessary
for oil and gas expenditures in 1995 and is projected to provide all of the
funds necessary in 1996. NEEI's 1995 oil and gas exploration and development
costs included $10 million of capitalized interest costs.
In 1995, NEP and Narragansett completed the 489 MW repowering of
Manchester Street Station. NEP 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 were placed in service in
September 1994 at a cost of approximately $60 million.
At December 31, 1995, NEES and its consolidated subsidiaries had lines
of credit and standby bond purchase facilities with banks totaling $683
million. These lines and facilities were used at December 31, 1995 for
liquidity support for $203 million of commercial paper borrowings and $342
million of NEP mortgage bonds in tax-exempt commercial paper mode. Fees are
paid on the lines and facilities in lieu of compensating balances.
New England Electric System and Subsidiaries
Selected Financial Data
Year Ended December 31 (millions of dollars, except per share data)
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Operating revenue:
Electric sales (excluding
fuel cost recovery) $1,521 $1,518 $1,488 $1,424 $1,358
Fuel cost recovery 600 568 582 597 585
Other utility revenue 121 117 117 118 114
Oil and gas sales 30 40 47 43 37
------ ------ ------ ------ ------
Total operating revenue $2,272 $2,243 $2,234 $2,182 $2,094
Net income $ 205 $ 199 $ 190 $ 185 $ 180
Average common shares
(000's) 64,944 64,970 64,970 64,970 64,917
Per share data:
Net income $3.15 $3.07 $ 2.93 $ 2.85 $ 2.77
Dividends declared $2.345 $2.285 $ 2.22 $ 2.14 $ 2.07
Return on average
common equity 12.8% 12.7% 12.6% 12.6% 12.6%
Total assets $5,191 $5,085 $4,796 $4,585 $4,450
Capitalization:
Common share equity $1,632 $1,581 $1,530 $1,487 $1,441
Minority interests 49 55 56 61 63
Cumulative preferred stock 147 147 147 162 162
Long-term debt 1,675 1,520 1,512 1,533 1,548
------ ------ ------ ------ ------
Total capitalization $3,503 $3,303 $3,245 $3,243 $3,214
Sales to ultimate
customers (millions
of kWh) 21,311 21,155 20,832 20,554 20,470
Cost per kWh to ultimate
customers (cents) 9.54 9.29 9.50 9.43 8.99
System maximum
demand (MW) 4,381 4,385 4,081 3,964 4,250
Electric capability
(MW net)-year end 5,482 5,533 5,362 5,479 5,645
Number of employees 4,832 4,990 4,969 5,415 5,533
Number of customers 1,313,811 1,300,198 1,288,184 1,277,281 1,257,213
New England Electric System and Subsidiaries
Statements of Consolidated Income
Year ended December 31 (thousands of dollars, except per share data)
1995 1994 1993
---------- ---------- ----------
Operating revenue $2,271,712 $2,243,029 $2,233,978
---------- ---------- ----------
Operating expenses:
Fuel for generation 237,498 220,956 227,182
Purchased electric energy 548,370 514,143 527,307
Other operation 500,721 494,741 492,079
Maintenance 136,058 161,473 146,219
Depreciation and amortization 264,666 301,123 296,631
Taxes, other than income taxes 132,631 125,840 120,493
Income taxes 128,340 128,257 121,124
---------- ---------- ----------
Total operating expenses 1,948,284 1,946,533 1,931,035
---------- ---------- ----------
Operating income 323,428 296,496 302,943
Other income:
Allowance for equity funds used
during construction 7,852 10,169 3,795
Equity in income of generating
companies 10,552 9,758 11,016
Other income (expense), net (6,306) (3,856) (1,154)
---------- ---------- ----------
Operating and other income 335,526 312,567 316,600
---------- ---------- ----------
Interest:
Interest on long-term debt 108,365 93,500 100,777
Other interest 19,826 11,298 9,809
Allowance for borrowed funds used
during construction (14,016) (7,793) (2,816)
---------- ---------- ----------
Total interest 114,175 97,005 107,770
---------- ---------- ----------
Income after interest 221,351 215,562 208,830
Preferred dividends of subsidiaries 8,690 8,697 10,585
Minority interests 7,904 7,439 8,022
---------- ---------- ----------
Net income $ 204,757 $ 199,426 $ 190,223
---------- ---------- ----------
Average common shares 64,944,187 64,969,652 64,969,652
Per share data:
Net income $ 3.15 $ 3.07 $ 2.93
Dividends declared $ 2.345 $ 2.285 $ 2.22
Statements of Consolidated Retained Earnings
Year ended December 31 (thousands of dollars)
1995 1994 1993
---------- ---------- ----------
Retained earnings at beginning
of year $ 779,045 $ 728,075 $ 684,132
Net income 204,757 199,426 190,223
Dividends declared on common
shares (152,273) (148,456) (144,233)
Premium on redemption of
preferred stock of
subsidiaries (2,047)
---------- ---------- ----------
Retained earnings at end of year $ 831,529 $ 779,045 $ 728,075
The accompanying notes are an integral part of these consolidated financial
statements.
New England Electric System and Subsidiaries
Consolidated Balance Sheets
At December 31 (thousands of dollars)
Assets 1995 1994
---------- ----------
Utility plant, at original cost $5,480,001 $4,914,807
Less accumulated provisions for depreciation and
amortization 1,710,991 1,610,378
---------- ----------
3,769,010 3,304,429
Net investment in Seabrook 1 under rate
settlement (Note A) 15,210 38,283
Construction work in progress 71,682 374,009
---------- ----------
Net utility plant 3,855,902 3,716,721
---------- ----------
Oil and gas properties, at full cost (Note A) 1,266,290 1,248,343
Less accumulated provision for amortization 1,032,777 964,069
---------- ----------
Net oil and gas properties 233,513 284,274
---------- ----------
Investments:
Nuclear power companies, at equity (Note D) 47,056 46,349
Other subsidiaries, at equity 40,259 42,195
Other investments 87,992 50,895
---------- ----------
Total investments 175,307 139,439
---------- ----------
Current assets:
Cash 7,064 3,047
Accounts receivable, less reserves of $18,308
and $15,095 284,033 295,627
Unbilled revenues (Note A) 66,300 55,900
Fuel, materials, and supplies, at average cost 73,724 94,431
Prepaid and other current assets 77,673 76,718
---------- ----------
Total current assets 508,794 525,723
---------- ----------
Deferred charges and other assets (Note B) 417,360 418,684
---------- ----------
$5,190,876 $5,084,841
========== ==========
Capitalization and Liabilities
Capitalization (see accompanying statements):
Common share equity $1,631,779 $1,580,838
Minority interests in consolidated subsidiaries 48,912 55,066
Cumulative preferred stock of subsidiaries 147,016 147,016
Long-term debt 1,675,170 1,520,488
---------- ----------
Total capitalization 3,502,877 3,303,408
---------- ----------
Current liabilities:
Long-term debt due within one year 23,960 65,920
Short-term debt 203,250 233,970
Accounts payable 157,486 168,937
Accrued taxes 15,894 11,002
Accrued interest 27,455 25,193
Dividends payable 38,683 37,154
Other current liabilities (Note F) 73,104 93,251
---------- ----------
Total current liabilities 539,832 635,427
---------- ----------
Deferred federal and state income taxes 780,451 751,855
Unamortized investment tax credits 93,408 94,930
Other reserves and deferred credits 274,308 299,221
Commitments and contingencies (Note D)
---------- ----------
$5,190,876 $5,084,841
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
New England Electric System and Subsidiaries
Consolidated Statements of Cash Flows
Year ended December 31 (thousands of dollars)
1995 1994 1993
--------- --------- ---------
Operating activities
Net income $ 204,757 $ 199,426 $ 190,223
Adjustments to reconcile net
income to net cash provided by
operating activities:
Depreciation and amortization 270,292 305,908 300,444
Deferred income taxes and
investment tax credits, net 24,056 41,741 4,105
Allowance for funds used during
construction (21,868) (17,962) (6,611)
Amortization of unbilled revenues (8,209) (38,458) (2,700)
Minority interests 7,904 7,439 8,022
Early retirement program 23,922
Decrease (increase) in accounts
receivable, net and unbilled
revenues 1,194 (33,107) (27,503)
Decrease (increase) in fuel,
materials, and supplies 20,707 (20,117) 13,786
Decrease (increase) in prepaid
and other current assets (955) (7,714) 5,904
Increase (decrease) in accounts
payable (11,451) 40,595 (42,967)
Increase (decrease) in other
current liabilities (4,784) (25,676) 64,658
Other, net (11,790) (34,109) (32,632)
--------- --------- ---------
Net cash provided by
operating activities $ 469,853 $ 417,966 $ 498,651
--------- --------- ---------
Investing activities
Plant expenditures, excluding
allowance for funds used
during construction $(329,385) $(438,016) $(304,659)
Oil and gas exploration and
development (17,947) (28,233) (18,965)
Other investing activities (32,460) (18,830) (107)
--------- --------- ---------
Net cash used in investing
activities $(379,792) $(485,079) $(323,731)
--------- --------- ---------
Financing activities
Dividends paid to minority interests $ (12,159) $ (8,416) $ (10,622)
Dividends paid on NEES common shares (151,335) (148,063) (142,352)
Short-term debt (30,720) 162,195 29,525
Long-term debt-issues 425,000 97,000 372,500
Long-term debt-retirements (311,920) (34,920) (395,820)
Preferred stock-issues 55,000
Preferred stock-retirements (512) (70,000)
Premium on reacquisition of
long-term debt (2,003) (10,996)
Premium on redemption of
preferred stock (2,047)
Return of capital to minority
interests and related premium (1,364)
Repurchase of common shares (1,543)
--------- --------- ---------
Net cash provided by (used in)
financing activities $ (86,044) $ 67,284 $(174,812)
--------- --------- ---------
Net increase in cash and cash
equivalents $ 4,017 $ 171 $ 108
Cash and cash equivalents at
beginning of year 3,047 2,876 2,768
--------- --------- ---------
Cash and cash equivalents at
end of year $ 7,064 $ 3,047 $ 2,876
--------- --------- ---------
Supplementary information
Interest paid less amounts capitalized $ 105,459 $ 90,500 $ 97,518
--------- --------- ---------
Federal and state income taxes paid $ 68,312 $ 114,597 $ 124,853
--------- --------- ---------
Dividends received from investments
at equity $ 14,748 $ 15,350 $ 14,404
The accompanying notes are an integral part of these consolidated financial
statements.
New England Electric System and Subsidiaries
Consolidated Statements of Capitalization
At December 31 (thousands of dollars)
Common share equity 1995 1994
---------- ----------
Common shares, par value $1 per share
Authorized-150,000,000 shares
Issued-64,969,652 shares $ 64,970 $ 64,970
Outstanding-64,923,721 and
64,969,652 shares, respectively
Paid-in capital 736,823 736,823
Retained earnings 831,529 779,045
Treasury stock-45,931 shares (1,543)
---------- ----------
Total common share equity $1,631,779 $1,580,838
Shares outstanding
Cumulative preferred stock
of subsidiaries 1995 1994 1995 1994
-------- -------- -------- --------
$100 Par value-
4.44% to 4.76% 430,140 430,140 $ 43,014 $ 43,014
6.00% to 7.24% 525,020 525,020 52,502 52,502
$50 Par value-
4.50% to 6.95% 730,000 730,000 36,500 36,500
$25 Par value-
6.84% 600,000 600,000 15,000 15,000
-------- -------- -------- --------
Total cumulative preferred
stock of subsidiaries
(annual dividend requirement
of $8,690 for 1995 and 1994) 2,285,160 2,285,160 $147,016 $147,016
Long-term debt (Note G) Maturity Rate 1995 1994
------------------------------ --------- ---------
Mortgage bonds* 1995 through 19994.730% 8.280% $ 183,500 $ 203,500
2000 through 20046.240% 8.520% 243,500 187,500
2005 through 20146.110% 8.450% 74,000 35,000
2015 through 20257.050% 9.125% 472,550 422,550
2018 through 2022 Variable 342,000 342,000
Notes
Granite State Electric Company1996 through 2025 7.370% 12.550% 16,000 14,400
New England Energy Incorporated 2002 Variable 182,000 216,000
Hydro-Transmission Companies 2001 through 20158.820% 9.410% 159,530 171,050
Narragansett Energy Resources
Company 2010 7.250% 32,000
Unamortized discounts and premiums, net (5,950) (5,592)
--------- ---------
Total long-term debt 1,699,130 1,586,408
--------- ---------
Long-term debt due in one year (23,960) (65,920)
--------- ---------
$1,675,170 $1,520,488
<FN>
*Includes $392,350 issued to secure tax-exempt pollution control and solid waste disposal
revenue bonds issued by state agencies on behalf of New England Power Company.
</FN>
The accompanying notes are an integral part of these consolidated financial statements.
New England Electric System and Subsidiaries
Notes to Consolidated Financial Statements
Note A - Significant accounting policies
1. Nature of operations
New England Electric System (NEES) is a public utility holding company.
NEES and its subsidiaries constitute the second largest electric utility
system in New England. Its core business activities are the generation,
transmission, distribution, and sale of electric energy and the delivery of
related services, including energy efficiency improvements, to residential,
commercial, industrial, and municipal customers. Other business activities
include independent transmission projects, energy management consultation, and
rate-regulated domestic oil and gas operations.
2. Basis of consolidation and financial statement presentation
The consolidated financial statements include the accounts of NEES and all
subsidiaries except New England Electric Transmission Corporation, which is
recorded under the equity method. Presentation of this subsidiary on the
equity basis is not material to the consolidated financial statements. New
England Power Company (NEP) has a minority interest in four regional nuclear
generating companies (Yankees). Narragansett Energy Resources Company (NERC)
has a 20 percent general partnership interest in the Ocean State Power (OSP)
generating facility. NEP and NERC account for these ownership interests under
the equity method.
NEES owns 50.4 percent of the outstanding common stock of both New England
Hydro-Transmission Electric Company, Inc. and New England Hydro-Transmission
Corporation (Hydro-Transmission Companies). The consolidated financial
statements include 100 percent of the assets, liabilities, and earnings of the
Hydro-Transmission Companies. Minority interests, which represent the minority
stockholders' proportionate share of the equity and income of the
Hydro-Transmission Companies, have been separately disclosed on the NEES
consolidated balance sheets and income statements.
NEP is also a 12 percent and 10 percent joint owner, respectively, of the
Millstone 3 and Seabrook 1 nuclear generating units, each 1,150 megawatts
(MW). NEP's net investment in Millstone 3, included in "Net utility plant", is
approximately $392 million. NEP's unamortized pre-1988 investment in Seabrook
1, is approximately $15 million and is shown separately on the consolidated
balance sheets. It will be fully amortized in 1996, pursuant to a settlement
agreement. NEP's net investment in Seabrook 1 since January 1, 1988, which is
approximately $54 million, is included in "Utility plant" on the consolidated
balance sheets. It is being depreciated over the term of Seabrook 1's
operating license. NEP's share of expenses for these units is included in
"Operating expenses".
The accounts of NEES and its utility subsidiaries are maintained in
accordance with the Uniform System of Accounts prescribed by regulatory bodies
having jurisdiction. All significant intercompany transactions between
consolidated subsidiaries have been eliminated.
In preparing the financial statements, management is required to make
estimates that affect the reported amounts of assets and liabilities and
disclosures of asset recovery and contingent liabilities as of the date of the
balance sheets and revenues and expenses for the period. These estimates may
differ from actual amounts if future circumstances cause a change in the
assumptions used to calculate these estimates.
3. Electric sales revenue
Massachusetts Electric Company (Massachusetts Electric) and The
Narragansett Electric Company (Narragansett), pursuant to rate agreements that
went into effect in 1993 and 1994, respectively, began accruing revenues for
electricity delivered but not yet billed (unbilled revenues). Unbilled
revenues at December 31, 1995, 1994, and 1993 were $66 million, $56 million,
and $43 million, respectively, of which $18 million, $37 million, and $11
million were recognized in income in the respective years. Included in these
income amounts are $8 million, $38 million, and $3 million, respectively,
which represent amortization of the initial effect of recording unbilled
revenues, in accordance with the retail rate agreements. Accrued revenues are
also recorded in accordance with rate adjustment mechanisms.
4. Allowance for funds used during construction (AFDC)
The utility subsidiaries capitalize 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 $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 7.3 percent, 7.6 percent, and 7.4
percent, in 1995, 1994, and 1993, respectively.
5. Depreciation and amortization
The depreciation and amortization expense included in the statements of
consolidated income is composed of the following:
Year ended December 31 (thousands of dollars) 1995 1994 1993
------ ----- -----
Depreciation $159,510 $136,746 $127,428
Nuclear decommissioning costs (Note D-4) 2,629 1,951 1,951
Amortization:
Oil and gas properties (Note A-6) 68,708 79,232 90,399
Investment in Seabrook 1 under
rate settlement (Note A-2) 23,073 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 $264,666 $301,123 $296,631
Depreciation is provided annually on a straight-line basis. The provision
for depreciation as a percentage of weighted average depreciable property was
3.3 percent in 1995, 3.1 percent in 1994, and 3.0 percent in 1993. The Oil
Conservation Adjustment was designed to recover expenditures for coal
conversion facilities at NEP's Salem Harbor Station. These costs were fully
amortized at December 31, 1995.
6. Oil and gas operations
New England Energy Incorporated (NEEI) participates in a rate-regulated
domestic oil and gas exploration, development, and production program through
a partnership with a non-affiliated oil company. This program consists of
prospects acquired prior to December 31, 1983. No new prospects will be
acquired under this program. However, NEEI continues to incur costs in
connection with existing prospects.
Losses from this program are passed on to NEP and, ultimately, to retail
customers under an intercompany pricing policy (Pricing Policy) approved by
the Securities and Exchange Commission (SEC). NEEI has incurred operating
losses since 1986 due to low oil and gas prices, and expects to incur
substantial additional losses in the future. Such losses were $44 million, $40
million, and $46 million in 1995, 1994, and 1993, respectively. NEP's ability
to pass these losses on to its customers was favorably resolved in NEP's 1988
Federal Energy Regulatory Commission (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.
NEEI follows the full cost method of accounting for its oil and gas
operations, under which capitalized costs (including interest paid to banks)
relating to wells and leases, determined to be either commercial or
non-commercial, are amortized using the unit of production method. The Pricing
Policy has allowed NEEI to capitalize all costs incurred in connection with
fuel exploration activities of its rate-regulated program, including interest
paid to banks, of which $10 million was capitalized in 1995 and 1994, and $9
million in 1993, respectively. 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.
7. Cash
NEES and its subsidiaries classify short-term investments with a maturity
of 90 days or less 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 filed a plan, Choice: New England,
with Massachusetts regulators, which would allow all customers of electric
utilities in Massachusetts to choose their power supplier beginning in 1998.
Under Choice: New England, pricing of generation would be deregulated while
transmission and distribution rates would remain regulated, although subject
to greater rewards and penalties based on performance. Choice: New England
proposes that the cost of past commitments to serve customers be recovered
through a wires access charge. Those past commitments, currently estimated at
approximately $4 billion on a present value basis, include generating plant
commitments, regulatory assets, 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 operations
of its subsidiaries 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 substantial write-down of plant
assets could be required pursuant to FAS 121. At December 31, 1995, NEES had
consolidated net plant investments totaling approximately $3.9 billion, of
which approximately $1.6 billion relates to its subsidiaries' generation
business and approximately $2.3 billion relates to its subsidiaries'
transmission and distribution businesses. 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 NEES and its subsidiaries 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
NEES's subsidiaries operate. 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 (thousands of dollars) 1995 1994
-------- --------
Oil and gas properties:
in excess of SEC "Ceiling Test" (see Note A-6) $178,200 $190,100
-------- --------
Regulatory assets included in current assets
and liabilities:
Accrued NEEI losses (see Note A-6) 43,731 39,794
Rate adjustment mechanisms (see Note F) (6,720) (14,334)
Unamortized unbilled revenues (see Note A-3) (8,209)
-------- --------
37,011 17,251
-------- --------
Regulatory assets included in deferred charges:
Accrued Yankee Atomic costs (see Note D-4) 67,566 122,452
Unamortized losses on reacquired debt 54,583 56,249
Deferred SFAS No. 106 costs (see Note E-2) 38,669 41,009
Deferred SFAS No. 109 costs (see Note C) 74,083 74,423
Purchased power contract termination costs 23,494 29,012
Deferred gas pipeline charges (see Note D-2) 62,873 37,562
Environmental response costs (see Note D-3) 19,276 13,167
Deferred storm costs 8,259 10,822
Unamortized property losses 12,044 7,373
Other 24,109 5,111
-------- --------
384,956 397,180
-------- --------
$600,167 $604,531
Approximately $500 million of the regulatory assets in the table above
relate to NEES subsidiaries' generation business and the remaining $100
million relate to NEES subsidiaries' transmission and distribution businesses.
Approximately $350 to $400 million of the regulatory assets at December 31,
1995 listed above are expected to be recovered within the next five years.
Additional deferred charges included in "Deferred charges and other assets" on
the consolidated balance sheets, that do not represent regulatory assets,
totaled $32,404,000 and $21,504,000 at December 31, 1995 and 1994,
respectively.
Note C - Income taxes
Total income taxes in the statements of consolidated income are as follows:
Year ended December 31 (thousands of dollars) 1995 1994 1993
------- ------- -------
Income taxes charged to operations $128,340 $128,257 $121,124
Income taxes charged to "Other income" 762 779 3,147
------- ------- -------
Total income taxes $129,102 $129,036 $124,271
Total income taxes, as shown above, consist of the following components:
Year ended December 31 (thousands of dollars) 1995 1994 1993
-------- ------- -------
Current income taxes $105,046 $ 87,295 $120,167
Deferred income taxes 25,578 46,166 7,756
Investment tax credits, net (1,522) (4,425) (3,652)
-------- ------- -------
Total income taxes $129,102 $129,036 $124,271
Total income taxes, as shown on previous page, consist of federal and state
components as follows:
Year ended December 31 (thousands of dollars) 1995 1994 1993
------- ------- -------
Federal income taxes $103,503 $104,136 $ 98,529
State income taxes 25,599 24,900 25,742
------- ------- -------
Total income taxes $129,102 $129,036 $124,271
Investment tax credits of subsidiaries are deferred and amortized over the
estimated lives of the property giving rise to the credits. Although
investment tax credits were generally eliminated by the Tax Reform Act of
1986, additional carryforward amounts continue to be recognized.
With regulatory approval, the subsidiaries have 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 (thousands of dollars) 1995 1994 1993
------- ------- -------
Computed tax at statutory rate $119,892 $118,006 $113,778
Increases (reductions) in tax resulting from:
Reversal of deferred taxes recorded
at a higher rate (3,306) (4,230) (5,099)
Amortization of investment tax credits (4,443) (5,272) (4,697)
State income tax, net of federal income
tax benefit 16,639 16,185 16,732
All other differences 320 4,347 3,557
------- ------- -------
Total income taxes $129,102 $129,036 $124,271
The following table identifies the major components of total deferred
income taxes:
At December 31 (millions of dollars) 1995 1994
----- -----
Deferred tax asset:
Plant related $ 104 $ 107
Investment tax credits 38 38
All other 122 108
----- -----
264 253
----- -----
Deferred tax liability:
Plant related (788) (777)
Equity AFDC (56) (52)
All other (200) (176)
----- -----
(1,044) (1,005)
----- -----
Net deferred tax liability $ (780) $ (752)
There were no valuation allowances for deferred tax assets deemed
necessary.
Federal income tax returns for NEES and its subsidiaries 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.
Note D - Commitments and contingencies
1. Plant expenditures
The NEES subsidiaries' utility plant expenditures are estimated to be $245
million in 1996. At December 31, 1995, substantial commitments had been made
relative to future planned expenditures.
2. Natural gas pipeline capacity
In connection with serving NEP's gas-burning electric generation
facilities, NEP 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, NEP 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
NEP 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, NEP 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 on to customers through NEP's
fuel clause. These proceeds have been included in "Fuel for generation" in
NEP'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.
3. 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.
NEES and/or its subsidiaries have been named as potentially responsible
parties (PRPs) by either the U.S. Environmental Protection Agency (EPA) or the
Massachusetts Department of Environmental Protection for 22 sites at which
hazardous waste is alleged to have been disposed. Private parties have also
contacted or initiated legal proceedings against NEES and certain subsidiaries
regarding hazardous waste cleanup. The most prevalent types of hazardous waste
sites with which NEES and its subsidiaries have been associated are
manufactured gas locations. (Until the early 1970s, NEES was a combined
electric and gas holding company system.) NEES is aware of approximately 40
such locations (including eight of the 22 locations for which NEES companies
are PRPs) mostly located in Massachusetts. NEES and its subsidiaries are
currently aware of other sites, and may in the future become aware of
additional sites, that they may be held responsible for remediating.
NEES has been notified by the EPA that it is one of several PRPs for
cleanup of the Pine Street Canal Superfund site in Burlington, Vermont, where
coal tar and other materials were deposited. Between 1931 and 1951, NEES and
its predecessor owned all of the common stock of Green Mountain Power
Corporation (GMP). Prior to, during, and after that time, gas was manufactured
at the Pine Street Canal site by GMP. In 1989, NEES was one of 14 parties
required to pay the EPA's past response costs related to this site. NEES
remains a PRP for ongoing and future response costs. In November 1992, the EPA
proposed a cleanup plan estimated by the EPA to cost $50 million. In June
1993, the EPA withdrew this cleanup plan in response to public concern about
the plan and its cost. The cost of any cleanup plan and NEES's share of such
cost are uncertain at this time. NEES has been involved in settlement
negotiations, which it expects to conclude in 1996, to determine NEES's
apportioned share of these costs. NEES believes it has adequate reserves
for this site.
In 1993, the Massachusetts Department of Public Utilities approved a
Massachusetts Electric rate agreement that allows for remediation costs of
former manufactured gas sites and certain other hazardous waste sites located
in Massachusetts to be met from a non-rate-recoverable, interest-bearing fund
of $30 million established on Massachusetts Electric's books in 1993.
Rate-recoverable contributions of $3 million, adjusted for inflation, are
added to the fund annually in accordance with the agreement. Any shortfalls in
the fund would be paid by Massachusetts Electric and be recovered through
rates over seven years.
Predicting the potential costs to investigate and remediate hazardous waste
sites continues to be difficult. There are also significant uncertainties as
to the portion, if any, of the investigation and remediation costs of any
particular hazardous waste site that may ultimately be borne by NEES or its
subsidiaries. Where appropriate, the NEES companies intend to seek recovery
from their insurers and from other PRPs, but it is uncertain whether, and to
what extent, such efforts will be successful. At December 31, 1995, NEES had
total reserves for environmental response costs of $50 million and a related
regulatory asset of $19 million. NEES believes that hazardous waste
liabilities for all sites of which it is aware, and which are not covered by a
rate agreement, are not material to its financial position.
4. Nuclear plant decommissioning and nuclear fuel disposal
NEP 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. NEP records
decommissioning cost expense on its books consistent with its rate recovery.
In addition, NEP 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.
NEP has a 30 percent ownership interest in Yankee Atomic Electric Company
(Yankee Atomic), which owns a 185 MW nuclear generating station in Rowe,
Massachusetts. In 1992, the Yankee Atomic board of directors decided to
permanently cease power operation of, and in time decommission, the facility.
NEP 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).
Each of the operating nuclear units in which NEP 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
NEP has an ownership interest.
NEP's share of (millions of dollars)
------------------------------------
Estimated
OwnershipDecommissioning Fund License
Unit Interest Cost (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 "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 NEP to pay a fee based on its share of the net generation
from Millstone 3 and Seabrook 1. NEP 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 NEP and also recovered from
customers through NEP's fuel clause.
5. 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. NEP's
current interest in the Yankees (excluding Yankee Atomic), Millstone 3, and
Seabrook 1 would subject NEP to a $58 million maximum assessment per incident.
NEP'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 NEP 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. NEP's maximum potential exposure for these assessments, either
directly, or indirectly through purchased power payments to the Yankees, is
approximately $18 million per year.
6. Long-term contracts for the purchase of electricity
NEP 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 NEP to make minimum fixed payments, even
when the supplier is unable to deliver power, to cover NEP'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-4) and OSP, entities in
which NEES subsidiaries hold ownership interests.
NEP's other contracts, principally with non-utility generators, require NEP
to make payments only if power supply capacity and energy are deliverable from
such suppliers. NEP's payments under these contracts amounted to $245 million
in 1995, and $210 million in 1994 and 1993, respectively.
7. Purchased power contract dispute
In October 1994, NEP 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. NEP purchases 56 percent of the power
output of the facility under a long-term contract with MPLP. The suit alleges
that NEP 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 NEP 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 NEP deliberately misled regulatory bodies concerning the
Manchester Street Station repowering project. MPLP seeks compensatory damages
in an unspecified amount, as well as treble damages. NEP believes that the
allegations of wrongdoing are without merit. NEP 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 NEP'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 E - Employee benefits
1. Pension plans
The NEES companies' retirement plans are noncontributory defined-benefit
plans covering substantially all employees. The plans provide pension benefits
based on the employee's compensation during the five years prior to
retirement. The NEES companies' 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 (thousands of dollars) 1995 1994 1993
------- ------- -------
Service cost-benefits earned during the period $ 14,167 $13,715 $11,160
Plus (less):
Interest cost on projected benefit obligation 54,821 49,067 49,346
Return on plan assets at expected
long-term rate (49,691) (47,281) (45,032)
Amortization 5,589 5,781 1,364
------- ------- -------
Net pension cost $ 24,886 $21,282 $16,838
------- ------- -------
Actual return on plan assets $130,979 $ 4,384 $69,208
Year ended December 31
(thousands of dollars) 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 $28 million of costs incurred in
connection with an early retirement and special severance program offered by
the NEES subsidiaries in that year. The increase in 1995 costs reflects
additional amounts recorded in the fourth quarter related to certain
supplemental benefit changes.
The following table sets forth the plans' funded status at December 31 (millions of
dollars):
-----------------------------------------------------------
Retirement Plans
-----------------------------------------------------------
1995 1994
-----------------------------------------------------------
Union Non-UnionSupple- Union Non-UnionSupple-
Employee Employee mental Employee Employee mental
Plans Plans Plans Plans Plans Plans
Benefits earned
Actuarial present value
of accumulated benefit
liability:
Vested $293 $343 $60 $251 $308 $38
Non-vested 8 10 - 8 9 -
--- --- --- --- --- ---
Total $301 $353 $60 $259 $317 $38
-----------------------------------------------------------
Retirement Plans
-----------------------------------------------------------
1995 1994
-----------------------------------------------------------
Union Non-Union Supple- UnionNon-Union Supple-
EmployeeEmployee mental Employee Employee mental
Plans Plans Plans Plans Plans Plans
Reconciliation of funded
status
Actuarial present value
of projected benefit
liability $346 $402 $73 $303 $355 $44
Unrecognized prior service
costs (7) (4) (16) (8) (4) (5)
Unrecognized transition
liability - (1) (4) - (1) (5)
Unrecognized net gain (loss) (1) (23) (7) (13) (33) 2
Additional minimum liability
recognized - - 14 - - 5
--- --- --- --- --- ---
338 374 60 282 317 41
--- --- --- --- --- ---
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) $60 $ 2 $ (6) $41
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 NEES subsidiaries provide 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 (thousands of dollars) 1995 1994 1993
------- ------- -------
Service cost-benefits earned during the period $ 7,137 $ 8,575 $ 8,160
Plus (less):
Interest cost on accumulated benefit obligation 29,377 27,813 30,457
Return on plan assets at expected long-term rate(9,742) (7,821) (5,089)
Amortization 16,204 18,273 18,418
------- ------- -------
Net postretirement benefit cost $42,976 $46,840 $51,946
------- ------- -------
Actual return on plan assets $29,054 $ 185 $ 5,249
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 (millions of dollars) 1995 1994
------ ------
Accumulated postretirement benefit obligation:
Retirees $230 $226
Fully eligible active plan participants 23 42
Other active plan participants 121 95
------ ------
Total benefits earned 374 363
Unrecognized prior service costs (1) -
Unrecognized transition obligation (313) (331)
Net gain not yet recognized 71 43
------ ------
131 75
------ ------
Plan assets at fair value 160 109
Prepaid postretirement benefit costs
recorded on books $ 29 $ 34
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 $45 million and the net periodic cost for the year 1995
by approximately $6 million.
The NEES subsidiaries fund the annual tax deductible contributions. Plan
assets are invested in equity and debt securities and cash equivalents.
Note F - Short-term borrowings and other current liabilities
At December 31, 1995, NEES and its consolidated subsidiaries had lines of
credit and standby bond purchase facilities with banks totaling $683 million.
These lines and facilities were used at December 31, 1995 for liquidity
support for $203 million of commercial paper borrowings and $342 million of
NEP mortgage bonds in tax-exempt commercial paper mode (see Note G). Fees are
paid on the lines and facilities in lieu of compensating balances. The
weighted average rate on outstanding short-term borrowings was 5.92 percent at
December 31, 1995. The fair value of the NEES subsidiaries' short-term debt
equals carrying value.
The components of other current liabilities are as follows:
At December 31 (thousands of dollars) 1995 1994
------ ------
Accrued wages and benefits $30,222 $26,035
Deferred unbilled revenues 8,209
Rate adjustment mechanisms 19,772 31,311
Customer deposits 10,993 10,951
Other 12,117 16,745
------ ------
$73,104 $93,251
Note G - Long-term debt
Substantially all the properties of NEP, Massachusetts Electric, and
Narragansett are subject to the lien of mortgage indentures under which
mortgage bonds have been issued.
The aggregate payments to retire maturing long-term debt are as follows:
(thousands of dollars) 1996 1997 1998 1999 2000
------- ------- ------- ------- -------
Maturing long-term debt $10,000 $65,500 $ 75,000 $33,000 $ 91,000
Mandatory prepayments:
Hydro-Transmission Companies 11,520 11,520 11,520 11,520 11,520
Granite State Electric Company 1,000
NEEI 17,000 30,000 30,000 30,000
NERC 1,440 1,920 1,920 2,280 2,280
------- ------- ------- ------- -------
Total $23,960 $95,940 $118,440 $76,800 $134,800
The terms of $342 million of variable rate pollution control revenue bonds
collateralized by NEP mortgage bonds at December 31, 1995 require NEP to
reacquire the bonds under certain limited circumstances. At December 31, 1995,
interest rates on NEP's variable rate bonds ranged from 3.35 percent to 6.00
percent. Also, at December 31, 1995, interest rates on NEEI's debt ranged from
5.92 percent to 6.17 percent. NEP has issued $40 million of long-term debt to
date in 1996. This debt represents variable rate pollution control revenue
bonds collateralized by NEP mortgage bonds which require NEP to reacquire the
bonds under certain limited circumstances. NEP used the proceeds to refinance
$10 million of variable rate debt in early 1996. The remaining proceeds will
be used to refinance $30 million of fixed rate debt later in 1996.
Narragansett has also refinanced $2 million of long-term debt to date in 1996
at 7.24 percent.
At December 31, 1995, the NEES subsidiaries' long-term debt had a carrying
value of approximately $1,699,000,000 and a fair value of approximately
$1,800,000,000. The fair value of debt that reprices frequently at market
rates approximates carrying value. The fair market value of the NEES
subsidiaries' long-term debt was estimated based on the quoted prices for
similar issues or on the current rates offered to the NEES companies for debt
of the same remaining maturity.
Note H - Selected quarterly financial information (unaudited)
1995 Quarter Ended
(In thousands, except ------------------
per share amounts) Mar. 31 June 30 Sept. 30 Dec. 31*
-------- -------- -------- --------
Operating revenue $558,316 $533,547 $599,126 $580,723
Operating income $ 73,385 $ 59,881 $102,321 $ 87,841
Net income $ 47,662 $ 33,531 $ 73,820 $ 49,744
Net income per average share $ .73 $ .52 $ 1.14 $ .76
1994 Quarter Ended
(In thousands, except ------------------
per share amounts) Mar. 31 June 30 Sept. 30 Dec. 31
-------- -------- -------- --------
Operating revenue $576,906 $517,078 $591,633 $557,412
Operating income $ 91,862 $ 57,716 $ 84,354 $ 62,564
Net income $ 69,273 $ 33,584 $ 58,851 $ 37,718
Net income per average share $ 1.07 $ .51 $ .91 $ .58
*See Note E
REPORT OF MANAGEMENT
The management of New England Electric System is responsible for the
integrity of the consolidated financial statements included in this Annual
Report. The financial statements were prepared in accordance with generally
accepted accounting principles using management's informed best estimates and
judgments where appropriate to fairly present the financial condition of the
NEES companies and their results of operations. The information included
elsewhere in this report is consistent with the financial statements.
The NEES companies maintain an accounting system and system of internal
controls which are designed to provide reasonable assurance as to the
reliability of the financial records, the protection of assets, and the
prevention of any material misstatement of the financial statements. The NEES
companies' accounting controls have been designed to provide reasonable
assurance that errors or irregularities, which could be material to the
financial statements, are prevented or detected by employees within a timely
period as they perform their assigned functions. The NEES companies' internal
auditing staff independently assesses the effectiveness of internal controls
and recommends improvements when appropriate.
Coopers & Lybrand L.L.P., the NEES companies' independent accountants, are
engaged to audit and express their opinion on the financial statements. Their
audit includes a review of internal controls to the extent required by
generally accepted auditing standards.
The Audit Committee, composed solely of outside directors, meets
periodically with management, the internal auditor, and the independent
accountants to ensure that each is carrying out its responsibilities and to
discuss auditing, internal accounting control, and financial reporting
matters. Both the internal auditor and the independent accountants have free
access to the Audit Committee, without management present, to discuss the
results of their audit work.
/s/ John W. Rowe /s/Alfred D. Houston
John W. Rowe Alfred D. Houston
President and Executive Vice President
Chief Executive Officer and Chief Financial Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of New England Electric System:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of New England Electric System and
subsidiaries (the Company) as of December 31, 1995 and 1994 and the related
consolidated 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 consolidated financial position of the Company
as of December 31, 1995 and 1994, and the consolidated 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 /s/COOPERS & LYBRAND L.L.P.
March 1, 1996
SHAREHOLDER INFORMATION
For shareholder information and assistance, write to or call Shareholder
Services at:
New England Electric System Toll-free number: 1-800-466-7215
Shareholder Services Local number: (508) 389-4900
P.O. Box 770 Fax: (508) 836-0276
Westborough, MA 01581 E-mail: shrser@neesnet.com
Dividend reinvestment plan
Shareholders of New England Electric System common shares who hold their
shares in registered form are eligible to participate in the Dividend
Reinvestment and Common Share Purchase Plan. The Plan provides participants
the opportunity to reinvest their dividends and send in optional cash payments
to purchase additional common shares, which, at the discretion of the Company,
will be newly issued shares or shares purchased in the open market, without
payment of any brokerage commission or service charges. For more information
on the Plan, please contact the Shareholder Services office on our toll-free
number listed above.
Direct deposit of dividends
Shareholders who hold New England Electric System common shares in their
own name may request to have their dividends directly deposited into their
checking or savings account. This service is provided without fees. If you
participate in Direct Deposit you will receive a credit advice for your
records. To sign up for this service, please call Shareholder Services on our
toll-free number listed above to request an authorization form.
Change of address
Please contact Shareholder Services on our toll-free number to let us know
if your address changes.
Form 10-K
Copies of the Annual Report on Form 10-K to the Securities and Exchange
Commission for 1995 are available upon request at no charge.
Annual meeting
The annual meeting of New England Electric System will be held at the Great
Hall, located at Faneuil Hall in Boston, Massachusetts on April 23, 1996 at
10:30 a.m.
Stock exchange listings
New England Electric System common stock is listed on the New York Stock
Exchange and the Boston Stock Exchange under the symbol NES.
Transfer agent
Certificates for transfer should be mailed Boston EquiServe
to our transfer agent Boston EquiServe P.O. Box 644
(a Bank of Boston joint venture) at: Boston, MA 02102
Phone: (617) 575-3120
New England Electric System common shares
1995 1994
------------------------------------------------------------
Price range Price range
------------------ Dividend ------------------ Dividend
High Low declared High Lowdeclared
------- ------- -------- ------- ---------------
First quarter $34.250 $30.625 $.575 $39.000 $35.125 $.560
Second quarter $35.250 $29.625 $.590 $37.625 $31.500 $.575
Third quarter $37.250 $32.875 $.590 $34.000 $28.875 $.575
Fourth quarter $40.000 $37.000 $.590 $32.875 $29.500 $.575
The total number of shareholders at December 31, 1995 was 51,097.
The name "New England Electric System" means the trustee or trustees for
the time being (as trustee or trustees but not personally) under an Agreement
and Declaration of Trust dated January 2, 1926, as amended, which is hereby
referred to, and a copy of which, as amended, has been filed with the
Secretary of The Commonwealth of Massachusetts. Any agreement, obligation, or
liability made, entered into, or incurred by or on behalf of New England
Electric System binds only its trust estate, and no shareholder, director,
trustee, officer, or agent thereof assumes or shall be held to any liability
therefor.
This report is not to be considered as an offer to sell or buy or
solicitation of an offer to sell or buy any security.
NEES OFFICERS AND RETAIL SUBSIDIARY PRESIDENTS
[PHOTO OF JOHN W. ROWE APPEARS HERE]
John W. Rowe
President &
Chief Executive Officer
[PHOTO OF ALFRED D. HOUSTON APPEARS HERE]
Alfred D. Houston
Executive Vice President
& Chief Financial Officer
[PHOTO OF FREDERIC E. GREENMAN APPEARS HERE]
Frederic E. Greenman
Senior Vice President,
General Counsel & Secretary (retired 12/31/95)
[PHOTO OF CHERYL A LAFLEUR APPEARS HERE]
Cheryl A. LaFleur
Vice President,
General Counsel & Secretary
(effective 12/31/95)
[PHOTO OF JOHN W. NEWSHAM APPEARS HERE]
John W. Newsham
Vice President
(retired 12/31/95)
[PHOTO OF RICHARD P. SERGEL APPEARS HERE]
Richard P. Sergel
Vice President
[PHOTO OF JEFFREY D. TRANEN APPEARS HERE]
Jeffrey D. Tranen
Vice President
[PHOTO OF MICHAEL E. JESANIS APPEARS HERE]
Michael E. Jesanis
Treasurer
[PHOTO OF JOHN H. DICKSON APPEARS HERE]
John H. Dickson
President,
Massachusetts Electric
[PHOTO OF ROBERT L. MCCABE APPEARS HERE]
Robert L. McCabe
President,
Narragansett Electric
[PHOTO OF LYDIA M. PASTUSZEK APPEARS HERE]
Lydia M. Pastuszek
President,
Granite State Electric
NEES DIRECTORS
[PHOTO OF JOAN T. BOK APPEARS HERE]
Joan T. Bok
[PHOTO OF PAUL L. JOSKOW APPEARS HERE]
Paul L. Joskow
[PHOTO OF JOHN M. KUCHARSKI APPEARS HERE]
John M. Kucharski
[PHOTO OF JOSHUA A. MCCLURE APPEARS HERE]
Joshua A. McClure
[PHOTO OF JOHN W. ROWE APPEARS HERE]
John W. Rowe
[PHOTO OF GEORGE M. SAGE APPEARS HERE]
George M. Sage
[PHOTO OF CHARLES E. SOULE APPEARS HERE]
Charles E. Soule
[PHOTO OF ANNE WEXLER APPEARS HERE]
Anne Wexler
[PHOTO OF JAMES Q. WILSON APPEARS HERE]
James Q. Wilson
[PHOTO OF JAMES R. WINOKER APPEARS HERE]
James R. Winoker
Edward H. Ladd not available for photo.
NEES DIRECTORS
As of December 31, 1995
Joan T. Bok
Chairman of the Board,
New England Electric System,
Westborough, Massachusetts
Corporate Responsibility Committee
Executive Committee
Paul L. Joskow
Professor of Economics and Management,
Massachusetts Institute of Technology,
Cambridge, Massachusetts
Audit Committee
John M. Kucharski
Chairman, President, and Chief Executive Officer,
EG&G, Inc.,
Wellesley, Massachusetts
Compensation Committee
Edward H. Ladd
Chairman,
Standish, Ayer & Wood, Inc., Investment counselors,
Boston, Massachusetts
Executive Committee
Joshua A. McClure
Former President,
American Custom
Kitchens, Inc.,
Providence, Rhode Island
Corporate Responsibility Committee
John W. Rowe
President and Chief Executive Officer,
New England Electric System,
Westborough, Massachusetts
Corporate Responsibility Committee
Executive Committee
George M. Sage
President and Treasurer,
Bonanza Bus Lines, Inc.,
Providence, Rhode Island
Compensation Committee
Executive Committee
Charles E. Soule
President and Chief Executive Officer,
Paul Revere Insurance Group,
Worcester, Massachusetts
Audit Committee
Anne Wexler
Chairman,
The Wexler Group, Management consultants,
Washington, D. C.
Corporate Responsibility Committee
Executive Committee
James Q. Wilson
Professor of Management,
University of California at Los Angeles
Corporate Responsibility Committee
James R. Winoker
Chief Executive Officer,
Belvoir Properties, Inc.,
Providence, Rhode Island
Audit Committee
Compensation Committee
NEES OFFICERS
As of December 31, 1995
John W. Rowe
President and
Chief Executive Officer
Alfred D. Houston
Executive Vice President and Chief Financial Officer
Frederic E. Greenman*
Senior Vice President,
General Counsel, and Secretary
John W. Newsham*
Vice President
Richard P. Sergel
Vice President
Jeffrey D. Tranen
Vice President
Michael E. Jesanis
Treasurer
Cheryl A. LaFleur**
Vice President, General Counsel, and Secretary
*Retired December 31, 1995
**Elected effective December 31, 1995
NEES SUBSIDIARIES
As of December 31, 1995
Massachusetts Electric Company
25 Research Drive, Westborough, Massachusetts 01582
John H. Dickson, President
The Narragansett Electric Company
280 Melrose Street, Providence, Rhode Island 02901
Robert L. McCabe, President
Granite State Electric Company
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766
Lydia M. Pastuszek, President
New England Power Company
25 Research Drive, Westborough, Massachusetts 01582
Narragansett Energy Resources Company
280 Melrose Street, Providence, Rhode Island 02901
New England Electric Resources, Inc.
25 Research Drive, Westborough, Massachusetts 01582
John L. Levett, President
New England Electric Transmission Corporation
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766
New England Energy Incorporated
25 Research Drive, Westborough, Massachusetts 01582
New England Hydro-Transmission Corporation
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766
New England Hydro-Transmission Electric Company, Inc.
25 Research Drive, Westborough, Massachusetts 01582
New England Power Service Company
25 Research Drive, Westborough, Massachusetts 01582
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