[ART WORK APPEARS HERE]
Annual Report 1994
[LOGO] NEW ENGLAND ELECTRIC SYSTEM
In 1994, NEES delivered its sixth consecutive year of superior earnings,
and did so in an increasingly competitive environment, with electric rates
that were the lowest among major electric utility systems in New England.
[ART WORK APPEARS HERE]
New England Electric System
The NEES subsidiaries include:
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 197 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 the affiliated NEES
subsidiaries.
Financial Highlights
1994 1993
---- ----
Earnings per average share $ 3.07 $ 2.93
Dividends declared per share $2.285 $ 2.22
Book value per share-year end $24.33 $ 23.55
Market price per share-year end $32-1/8 $39-1/8
Growth in kilowatthour (KWH) sales
billed to ultimate customers 1.6% 1.4%
Cost per KWH to ultimate customers (cents) 9.29 9.50
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."
Contents
Letter to Shareholders 2
Winning in A Changing Business 4
Improving Our Competitive Position 5
Financial Review 16
Financial Statements 25
Notes to Financial Statements 30
Report of Management 43
Report of Independent Accountants 43
Shareholder Information 44
System Directors and Officers -
System Subsidiaries 45
Return on Common Equity - 1994
New England Electric System 12.7%
Median of U.S. Electric Utilities 11.4%
Median of New England/New York Electric Utilities 11.4%
To Our Fellow Shareholders
The year 1994 was another good one for the New England Electric System
(NEES). Among our accomplishments:
Earnings per common share increased to $3.07 compared with $2.93 in 1993.
Return on equity was 12.7 percent, placing us in the top one-third of major
electric utility systems in New England and New York for the sixth consecutive
year. This is a record unmatched by any other electric utility in the region
Our return on equity also places us in the top quartile of major electric
utilities across the nation.
Bond ratings for NEES subsidiaries were A+ or higher, reflecting our attention
to the balance sheet as well as the income statement.
Your dividend was increased to $2.30 per share in May 1994. Dividend growth
over the past five years has exceeded both the regional and national averages
for major electric utilities.
Our fossil-fueled power plants set new records for availability and our
demand-side management programs continued to provide both profits for
shareholders and savings for customers.
While our region has higher energy costs than much of the nation, NEES
has consistently performed with superior efficiency. Our current average
retail rate of 9.3 cents per kilowatthour is the lowest among major electric
utility systems in New England, and is slightly lower than our average rate of
each of the past two years.
As you know, our share price dropped during 1994, largely as a result of
rising interest rates. However, the drop was in line with that experienced by
other utilities. Over the past five years, NEES shares have outperformed the
average electric utility stock, and our market performance, as measured by
market to book ratio, continues to lead the region.
During the past year, proposals for increased competition have affected
the structure, operations, and financial position of the electric utility
industry. While competition has been with us in various forms for many years,
the Federal Energy Regulatory Commission (FERC) is now developing ground rules
for wide-open competition in wholesale electricity markets, and many state
commissions, including those that regulate the NEES retail companies, are
evaluating proposals for competition within the traditional retail service
franchise. NEES's response to these trends has been to adapt quickly to
changing market conditions while preserving our focus on business
fundamentals: first, the cost and quality of our service; second, the quality
of our assets and the length of our financial commitments; third, the
environmental impact of our operations; and finally, the fairness of the rules
that regulate our operations. This response has allowed us to continue to
profit in a rapidly evolving regulatory environment.
[PHOTO OF JOAN BOK Joan T. Bok,
APPEARS HERE] Chairman of the Board
During 1994, we reached important agreements that reinforce our long-term
competitive position. We have signed service extension discount (SED)
contracts with 82 percent of our large commercial and industrial customers in
Massachusetts and Rhode Island. Through these contracts, customers agree to
give us three to five years notice before generating their own electricity or
changing electricity suppliers, and in exchange receive a 5 percent base rate
discount (see page 17 for details.) An agreement reached in December 1994
with certain state agencies, municipal light departments, and large commercial
and industrial customers and approved by the FERC in February 1995 will hold
our wholesale subsidiary New England Power's rates at their present level
until at least 1997. An agreement with more than a dozen environmental,
recreational, and governmental organizations, currently before the FERC for
approval, would expedite the relicensing of our hydroelectric generating
facilities along the Deerfield River, and has enhanced our reputation for
environmental commitment.
While the next few years are likely to be difficult for our industry,
NEES has a track record of prospering in difficult times. We have
continuously been one of the quickest to adapt to new public policies and one
of the most efficient in making these policies work. This flexibility has
helped us receive fair treatment from regulators. We strive to be less
costly, more profitable, more agile, and more green than our competitors. We
have hard working, hard thinking employees who want to win, who have a record
of winning, and who are determined to continue winning. With their support,
we believe our consistent and unequivocal commitment to enhancing shareholder
value will make NEES a rewarding investment in the future as it has been in
the past.
We thank you for your continued investment and confidence in the New
England Electric System.
s/ Joan T. Bok s/ John W. Rowe
Joan T. Bok John W. Rowe
Chairman of the Board President and Chief Executive Officer
February 27, 1995
NEES' Key Financial Goals - 1994 Results
Dividend Growth exceeds
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 electric utilities on rolling
5-year average.
Achieved goals in blue
Non-achieved goal in gray
John W. Rowe, President [PHOTO OF JOHN W. ROWE
and Chief Executive Officer APPEARS HERE]
Winning in a Changing Business
Unique responsibilities and commensurate rights have shaped the evolution
of the electric utility industry. In exchange for exclusive rights to supply
electricity within franchise areas, utilities have served all customers under
rates set by regulators, projected long-term needs for electricity, and built
or purchased power from facilities to meet those long-term needs.
Shareholders have backed these large capital commitments required to build the
facilities due to the promise of an opportunity to earn a fair return on their
investments.
Historically, utilities built the generating plants, transmission lines,
and distribution systems needed within their service territories. In the
early 1980s, however, operators of independent generating plants began to
compete with utilities to produce power that could be sold on the "wholesale"
market to utilities. The Energy Policy Act of 1992 established a national
policy favoring more wholesale competition; this policy has been implemented
at both the state and federal levels. As wholesale competition grows and
various states consider new forms of competition, transmission and
distribution wires are likely to remain closely regulated.
With the market for electricity and related services becoming more
competitive, the operating environment for all electric utilities will become
more complex and more risky. A decisive response to these new competitive
pressures is essential to maintain our strong financial performance and our
regional position as a high-value, low-cost provider of electricity and
related services.
Here are some examples of the steps we have taken to improve our
competitive position.
Improving Our Competitive
Position
Customer Focus 6
Competitive Marketplace 8
Environment 10
New Rules 12
A History of Responding
to Challenges 14
Customer Focus
We continue to expand the array of energy services we provide directly to
our customers. At Dartmouth College in Hanover, N.H., our programs have
resulted in energy-efficient lighting in the campus library, athletic
facilities, and student cultural center as well as computerized control of
heating, ventilation, and air conditioning in one of the science labs. At the
college's math and computer science building, we are now implementing a pilot
program in which all energy-related equipment and control processes within a
single building-not just those involving electricity-are monitored and
adjusted to make sure they are performing optimally.
A view from the customer's side of the meter led to the development of
EnergyFIT-integrated services for energy conservation, power quality,
cogeneration assessment, and electrotechnology evaluations that are customized
to meet the needs of our largest and most energy-intensive business customers.
EnergyFIT makes business customers more efficient, productive, and profitable,
and helps to strengthen our relationship with them.
EnergyFIT services encouraged Kopin Corporation, a manufacturer of active
matrix liquid crystal displays, to establish a new manufacturing facility in
Westborough, Mass.; developed ways for Nyman Mfg. Co. in East Providence, R.I.
to produce plastic dinnerware at lower energy cost; and helped a 105-year-old
firm, Crown Yarn Dye Co., Inc. in Attleboro, Mass., to continue custom dyeing
operations for companies throughout the U.S.
[ONE HALF OF MORTARBOARD PHOTO
APPEARS HERE]
In addition to serving existing customers, all of the NEES companies are
participating in efforts to attract new businesses to the region. We recognize
that many businesses are carefully weighing energy costs before choosing new
locations. The Coca-Cola Company chose Northampton, Mass. over two communities
served by other electric companies for a bottling plant for its non-carbonated
products. Massachusetts Electric created a service package that offered
economic development rates and a substantial investment in energy efficiency
as part of the pull to attract the plant and the 150 to 250 associated jobs to
Northampton. Our success and that of the region are well served by working
with customers to get the most for their energy dollars.
[ONE HALF OF MORTARBOARD PHOTO
APPEARS HERE]
Douglas Smith, senior [PHOTO OF DOUGLAS SMITH
technical representative, APPEARS HERE]
is a member of the
Massachusetts Electric
team that created a
service package to help
attract a Coca-Cola
Company bottling plant
to our service territory.
Competitive Marketplace
We are increasing our efforts to protect the share of the market that we
now serve, increase customer awareness of our new products and services, and
develop new business ventures.
One emerging market in which NEES has already established a strong
position is the construction, operation, and/or ownership of transmission
facilities outside our service territory. During the 1980s, we managed the
construction of the Hydro-Quebec Phase 1 and 2 direct current interconnection,
a large project in which most New England utilities participated. In 1994,
Nantucket Cable Electric Company, Inc., a new company established by NEES, was
selected to design, construct, and maintain a 27-mile-long undersea and
underground transmission cable linking the island of Nantucket to mainland
Massachusetts. This project is expected to be in operation in early 1997, and
will provide Nantucket residents with improved service, more stable
electricity costs, and - because it will replace diesel generators now in use
on the island - a more environmentally-friendly energy supply.
To pursue transmission projects worldwide, the NEES subsidiary New
England Electric Resources, Inc. (NEERI) is teaming up with Sweden's ABB Power
Systems, one of the world's leading suppliers of transmission equipment and
Paul Stasiuk, senior analyst, evaluates
electrotechnologies in the commercial
food-service industry for the NEES
companies. Much of his recent work
involves the electric cooking center at
Johnson & Wales University.
[PHOTO OF PAUL STASIUK APPEARS HERE]
[ONE HALF OF LIGHTHOUSE PHOTO
APPEARS HERE]
services. NEERI will help provide utility managers worldwide with innovative
options for developing and financing transmission systems. These ventures
will build on our established leadership in large-scale transmission projects.
Promoting clean and efficient electrotechnologies that replace the use of
other energy sources is another way for the NEES companies to be the energy
supplier of choice. NEES's three retail subsidiaries joined to sponsor a new
cooking center at the world's largest college of culinary arts, Johnson and
Wales University in Providence. This cooking center is the focal point for
evaluating newly developed electric cooking equipment that incorporates
features--such as quick temperature adjustment-preferred by many cooks and
readily available in competing gas equipment. Showcased as a "high tech cook-
off," the center is set up to enable detailed, side-by-side comparisons of
commercial gas and electric cooking equipment. Data are being collected to
compare the quality of the finished food, overall labor and energy efficiency,
and health benefits of food handling for competing state-of-the-art gas and
electric cooking technologies. This electric cooking center provides energy-
efficient electrotechnologies for our customer, Johnson and Wales; exposes
future chefs to the best electric cooking equipment available; and can help to
strengthen the market for our core product.
[ONE HALF OF LIGHTHOUSE PHOTO
APPEARS HERE]
Environment
Cost-effective environmental improvement will continue to be a
fundamental challenge for electric utilities. Success often requires
cooperation among many interested parties. In 1994, we advanced our efforts
to secure a 40-year federal license for New England Power's eight
hydroelectric dams on the Deerfield River with an agreement among
environmentalists, anglers, white water enthusiasts, and state and federal
resource agencies. The agreement was designed to expedite licensing and avoid
litigation. It is the culmination of more than five years of negotiation and
will enhance recreation, fisheries, and conservation in the Deerfield Valley.
New England Power has made substantial reductions in air emissions a
cornerstone of its operational goals. The company remains an industry leader
in using innovative emission controls on existing fossil-fueled power plants.
Our 1994 emissions, compared with 1990 levels, were 45 percent lower for
sulfur dioxide, 23 percent lower for nitrogen oxides, and 11 percent lower for
carbon dioxide. In February 1995, we announced a voluntary commitment to
reduce greenhouse gas emissions by 20 percent below 1990 levels by the year
2000 as part of President Clinton's Climate Challenge Program. This emissions
reduction target is among the most ambitious of the commitments made by
participating utilities.
[ONE HALF OF CANOE PHOTO
APPEARS HERE]
[ONE HALF OF CANOE PHOTO
APPEARS HERE]
The Manchester Street Station repowering project, scheduled for
completion in late 1995, will use a more efficient and
environmentally-friendly gas-fired power generating technology while more than
tripling this Rhode Island plant's output to 489 megawatts (MW). The station
is located in a densely populated urban area at the head of Narragansett Bay
and across the river from Providence's treasured historic district. Our
activities are closely coordinated with other major projects that are
revitalizing the Providence downtown and waterfront. We have considered the
needs of neighbors in every detail of the plant construction and continue to
receive their enthusiastic support.
The NEES companies' efforts to promote more sustainable energy supplies
include a planned project to produce energy from biomass fuels such as wood
and organic waste. We have also received regulatory approval for energy
purchases from seven projects that will provide 36 MW of capacity through wind
power, waste heat recovery, and the use of landfill methane and municipal
solid waste as fuels.
Paula Hamel, senior
environmental engineer, [PHOTO OF PAULA HAMEL APPEARS HERE]
works with contractors
and city, state, and
federal agencies to ensure
that Manchester Street
Station repowering activities
meet environmental and
safety requirements.
New Rules
Since non-utilities were allowed to enter the wholesale generation
market, New England Power has relied on all available options to meet its
requirements. During that time, two-thirds of New England Power's new net
generating capability has come from independent generating sources and
Hydro-Quebec. The company is now working on new rules to make wholesale
competition more efficient through reform of the New England Power Pool and
the creation of a Regional Transmission Group.
We now face various proposals to permit retail competition. A common
feature of nearly all such proposals is that utilities would be required to
open both their transmission and distribution systems to competitors and to
customers. If this happens, the goal of producing a more efficient
electricity market will best be accomplished by ensuring that all users of a
utility's wires pay their share of all of the costs committed by utilities to
build the present electric system. Along with the Conservation Law
Foundation, we have proposed a concept, called by some the "Grand Bargain," to
recover these fixed costs through a system access charge.
As part of this Bargain, the NEES companies would be willing to spin off
or sell our transmission system, invest in environmental improvement ahead of
new requirements, and continue investments in conservation and renewable
energy. The new, independent transmission company would then offer comparable
Masheed Hegi, consulting engineer,
negotiates transmission agreements [PHOTO OF MASHEED HEGI
between the NEES companies and other APPEARS HERE]
users and providers of transmission
services. She is currently participating
in the effort to develop a New England
Regional Transmission Agreement.
[ONE HALF OF PEN PHOTO
APPEARS HERE]
transmission access and pricing to all competing power suppliers. This "Grand
Bargain" would provide benefits to both customers and shareholders. In the
near term, rates could be reduced by lengthening the period over which we
recover certain costs. In the long term, rates should also be reduced by
increased customer responsibility for generation choices and increased market
pressure on suppliers. Shareholders would benefit from clear provisions for
the recovery of the cost of past commitments.
In Massachusetts, the Division of Energy Resources (DOER) recently
proposed that when new generating capacity is needed, retail customers with an
aggregate load equal to the needed capacity be allowed to bid for access to
utility wires. The winning bidders could then choose their electricity
supplier. This proposal would provide customer choice and leave NEES its
existing revenue base to pay for its past commitments. We support the DOER
proposal.
Other proposals for "retail wheeling" would permit access to utility
wires at low cost and force generating prices down to short-run operating
costs. In our view, these proposals would deny all utilities the opportunity
to recover their past commitments to which we believe they are entitled. If
retail competition is permitted, a fair system must permit utilities to charge
a fee for access to their transmission and distribution system which will
enable them to recover all of their fixed costs.
In summary, we are exerting all of our efforts to assure that new rules
are written under which New England Electric System and other well-run utility
systems have an opportunity to succeed in the competitive marketplace.
[ONE HALF OF PEN PHOTO
APPEARS HERE]
A History of Responding to Challenges
The 1960s brought about tremendous increases in the demand for
electricity, and our wholesale subsidiary expanded its capacity to meet that
demand. The 1970s brought about oil embargoes, and we diversified our fuel
mix. The late 1970s and early 1980s brought inflation and the high costs
associated with the construction of the Seabrook and Millstone 3 nuclear
plants; we responded by diversifying our power purchases and by incorporating
energy conservation into resource planning. In each of these decades, NEES
developed progressive and innovative solutions that allowed us to provide
excellent financial results for our shareholders.
Now, in the 1990s, increased competition is on the minds of executives
and shareholders in the electric utility industry. Our proven ability to
anticipate change and successfully adapt is increasingly important in meeting
today's challenges.
Financial Report
Financial Review 16
Financial Statements
Selected Financial Data 25
Consolidated Income 26
Consolidated Retained
Earnings 26
Consolidated Balance
Sheets 27
Cash Flow 28
Capitalization 29
Notes to Financial
Statements 30
Report of Management 43
Report of Independent
Accountants 43
Shareholder Information 44
Financial Review
[GRAPH APPEARS HERE]
Overview
Earnings in 1994 were $3.07 per share compared with $2.93 and $2.85 per
share in 1993 and 1992, respectively. The return on 1994 common equity was
12.7 percent.
The improvement in 1994 earnings reflects increased kilowatthour (KWH)
sales to ultimate customers, decreased purchased power expense and interest
expense, 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 (see "Retail rate activity" section).
The increase in 1993 earnings over 1992 was primarily the result of
increased KWH sales, reduced interest costs, and lower costs of scheduled
overhauls at wholly-owned thermal generating units, partially offset by the
combined effects of the one-time items described above.
KWH sales billed to ultimate customers in 1994 increased by 1.6 percent
over 1993, reflecting an improved economy. KWH sales in 1993 increased 1.4
percent over 1992 sales, reflecting more normal weather conditions in 1993
compared with 1992, partially offset by the fact that 1992 included an extra
day for leap year. New England Electric System (NEES) retail subsidiaries
currently forecast an increase in KWH sales of less than 1 percent in 1995.
The annual dividend rate was raised by 2.7 percent, or $.06 per share, in
May 1994 and is now $2.30 on an annual basis. In 1993, the annual dividend
rate was increased by 3.7 percent, or $.08 per share. The market price of NEES
common shares at year end 1994 was $32 1/8 per share, compared with $39 1/8
per share and $38 1/2 per share at the end of 1993 and 1992, respectively.
Wholesale rate activity
In February 1995, the Federal Energy Regulatory Commission (FERC)
approved a rate agreement filed by New England Power Company (NEP). Under the
agreement, which is effective January 1995, NEP's base rates will be frozen
until 1997. Before this rate agreement, NEP's rate structure contained two
surcharges which were recovering the costs of a coal conversion project and a
portion of NEP's investment in the Seabrook 1 Nuclear Unit (Seabrook 1).
Under the rate agreement, these two surcharges, which were due to expire in
mid-1995, will be rolled into base rates. The agreement also provides for the
costs resulting from the Manchester Street Station repowering project, which
is expected to be completed in late 1995, to be included in rate base, without
a rate increase (see "Liquidity and capital resources" section). In addition,
the agreement allows NEP to recover approximately $50 million of deferred
costs associated with terminated purchased power contracts and postretirement
benefits other than pensions (PBOPs) over seven years. The agreement also
provides for full current recovery of PBOP costs commencing in 1995. The
agreement further provides for the recovery over three years of $27 million of
costs related to the dismantling of a retired generating station and the
replacement of a turbine rotor at one of NEP's generating units. The
agreement also increases NEP's recovery of depreciation expense by
approximately $8 million annually to recognize costs associated with the
eventual dismantling of its Brayton Point and Salem Harbor generating plants.
Under the agreement, approximately $15 million of the $38 million in
Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988 settlement
agreement will be deferred and recovered in 1996. The agreement further allows
for deferral of additional purchased power contract termination costs and any
increases in nuclear decommissioning payments for recovery in future rates.
Yankee Atomic Electric Company, of which NEP is a 30 percent owner, recently
announced a new decommissioning cost estimate, which, if approved by the FERC,
would increase annual billings to NEP by $11 million, beginning in late 1995
and ending in July 2000.
The settlement rates provide for approximately $24 million in revenues in
1996 to complete the amortization of pre-1988 Seabrook 1 costs and the costs
associated with the cancelled Seabrook 2 nuclear unit. To the extent the
settlement rates stay in effect beyond 1996, the agreement provides that these
revenues be applied first to accelerate recovery of deferred PBOP costs, and
then to additional amortization of NEP's investment in the Millstone 3 nuclear
unit.
The FERC's approval of this rate agreement applies to all of NEP's
customers except the Town of Norwood, Massachusetts and the Milford Power
Limited Partnership (MPLP), who intervened in the rate case. A separate
hearing will be conducted to determine the appropriate rate to charge these
two parties, who represent less than 2 percent of NEP's sales.
Retail rate activity
In 1993, the Massachusetts Department of Public Utilities (MDPU) approved
a rate agreement filed by Massachusetts Electric Company (Massachusetts
Electric), the Massachusetts Attorney General, and two groups of large
commercial and industrial customers.
Under the agreement, effective December 1, 1993, Massachusetts Electric
implemented an 11 month general rate decrease of $26 million (annual basis).
This rate reduction continued in effect through October 31, 1994, at which
time rates increased to the previously approved levels. Massachusetts Electric
also agreed not to further increase its base rates before October 1, 1995.
The agreement also provided for the recognition of unbilled revenues for
accounting purposes. Unbilled revenues at September 30, 1993 of approximately
$35 million were amortized to income over 13 months commencing December 1993.
The agreement further provided for rate discounts for large commercial
and industrial customers who signed agreements to give a five-year notice to
Massachusetts Electric before they purchase power from another supplier or
generate any additional power themselves. The notice provision may be reduced
from five to three years under certain conditions. The aggregate amount of
these service extension discounts (SEDs) was $4 million during 1994 but will
increase in 1995 to approximately $10 million per year under the terms of the
agreement.
The agreement also resolved all rate recovery issues associated with
environmental remediation costs of Massachusetts manufactured gas waste sites
formerly owned by Massachusetts Electric and its affiliates, as well as
certain other Massachusetts Electric environmental cleanup costs (see
"Hazardous waste" section).
Effective October 1992, the MDPU authorized a $45.6 million annual
increase in rates for Massachusetts Electric.
In July 1994, the Rhode Island Public Utilities Commission (RIPUC)
approved a rate agreement between The Narragansett Electric Company
(Narragansett) and the Rhode Island Division of Public Utilities and Carriers
that provides for SEDs to large commercial and industrial customers under
terms similar to the Massachusetts Electric program described above. The
aggregate amount of Narragansett's discounts was $1.5 million in 1994 and is
expected to be approximately $3 million per year thereafter. The agreement
also provides for Narragansett to recognize unbilled revenues for accounting
purposes. Unbilled revenues at December 31, 1993 of approximately $14 million
are being amortized to income over a 21 month period that began in April 1994.
Each of the NEES retail subsidiaries is likely to file a rate case with
its respective state regulatory agency during 1995.
Demand-side management
The retail companies regularly file their demand-side management (DSM)
programs with their respective regulatory agencies and have received approval
to recover DSM program expenditures in rates on a current basis. These
expenditures were $70 million, $62 million, and $58 million in 1994, 1993, and
[GRAPH APPEARS HERE]
1992, respectively. Since 1990, the retail companies have been allowed to
earn incentives based on the results of their DSM programs. The retail
companies must be able to demonstrate the electricity savings produced by
their DSM programs to their respective state regulatory agencies before
incentives are recorded. The retail companies recorded before-tax incentives
of $7.7 million, $7.3 million, and $10.5 million in 1994, 1993, and 1992,
respectively. The retail companies have received regulatory orders that will
give them the opportunity to continue to earn incentives based on 1995 DSM
program results.
[GRAPH APPEARS HERE]
Operating revenue
Operating revenue increased $9 million in 1994, primarily reflecting
increased KWH sales and amortization of unbilled revenues by retail
subsidiaries, partially offset by the temporary rate reduction at
Massachusetts Electric. KWH sales billed to ultimate customers in 1994
increased by 1.6 percent over 1993, reflecting an improved economy.
Operating revenue increased by $52 million in 1993, primarily due to
increased KWH sales, retail rate increases, and beginning in the fourth
quarter of 1993, the recognition by Massachusetts Electric of unbilled
revenues. KWH sales billed to ultimate customers in 1993 increased 1.4
percent over 1992. More normal weather conditions in 1993 compared with 1992
were largely offset by the fact that 1992 included an extra day for leap year.
Operating expenses
Total operating expenses increased by $15 million in 1994 over 1993,
reflecting increases in generating plant maintenance costs associated with
overhauls 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 amounts previously charged to expense.
Depreciation and amortization increased $4 million in 1994, reflecting
increased amortization of the net investment in 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 by approximately $12
million, reflecting increased income taxes and municipal property taxes.
Total operating expenses increased by $55 million in 1993, reflecting a
$28 million charge associated with the early retirement offer referred to
above, $10 million due to the adoption of two new accounting standards for
postemployment benefits, increased computer systems development costs, and
general increases in other areas. These increases were partially offset by a
decrease in generating plant maintenance costs and reduced winter
storm-related costs.
Depreciation and amortization decreased $6 million in 1993, reflecting
reduced amortization of oil and gas properties due to decreased production.
NEP's expense also declined as a result of new lower depreciation rates
established in its 1992 rate case. These decreases were partially offset by
increased amortization of Seabrook 1 as part of NEP's 1988 rate settlement and
increased depreciation on new plant expenditures.
Taxes charged to operations in 1993 increased by approximately $17
million, reflecting higher municipal property taxes and increased income
taxes, including the effects of the increase in the federal income tax rate in
1993 from 34 percent to 35 percent.
Interest expense
Interest expense decreased $6 million and $9 million in 1994 and 1993,
respectively, due to significant refinancings of corporate debt at lower
interest rates during 1993 and 1992.
Allowance for funds used during construction (AFDC)
AFDC increased in 1994 and 1993 by $11 million and $2 million,
respectively, due to increased construction work in progress associated with
the repowering of the Manchester Street Station (see "Liquidity and capital
resources" section).
Oil and gas operations
New England Energy Incorporated (NEEI) participates in a rate-regulated
domestic oil and gas exploration, development, and production program
consisting of prospects acquired prior to December 31, 1983. NEEI is not
acquiring any new prospects. Due to precipitate declines in oil and gas
prices, NEEI has incurred operating losses since 1986, and expects to incur
substantial additional losses in the future. These losses are being passed on
to NEP under an intercompany pricing policy approved by the Securities and
Exchange Commission. NEP is allowed to recover these losses from its
customers under NEP's 1988 FERC rate settlement, which covered all costs
incurred by or resulting from commitments made by NEEI through March 1, 1988.
Other subsequent costs incurred by NEEI are subject to normal regulatory
review.
Hazardous waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. NEES
subsidiaries currently have in place an environmental audit program intended
to enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
NEES and/or its subsidiaries have been named as a potentially responsible
party (PRP) by either the U.S. Environmental Protection Agency (EPA) or the
Massachusetts Department of Environmental Protection for 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 seven 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, at
which 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. It is uncertain at this time what the cost of
any ultimate cleanup plan will be or what NEES's share of such cost will be.
In 1993, the MDPU approved a rate agreement filed by Massachusetts
Electric (see "Retail rate activity" section) that allows for remediation
costs of former manufactured gas sites and certain other hazardous waste sites
located in Massachusetts to be met from a non-rate recoverable
interest-bearing fund of $30 million established on Massachusetts Electric's
books. 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.
[GRAPH APPEARS HERE]
[GRAPH APPEARS HERE]
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 would be successful. At December 31,
1994, NEES had total reserves for environmental response costs of $45 million
and a related regulatory asset of $13 million. NEES believes that hazardous
waste liabilities for all sites of which it is aware, and which are not
covered by a rate agreement, will not be material to its financial position.
Electric and magnetic fields (EMF)
In recent years, concerns have been raised about whether EMF, which occur
near transmission and distribution lines as well as near household wiring and
appliances, cause or contribute to adverse health effects. Numerous studies
on the effects of these fields, some of them sponsored by electric utilities
(including NEES companies), have been conducted and are continuing. Some of
the studies have suggested associations between certain EMF and health
effects, including various types of cancer, while other studies have not
substantiated such associations. It is impossible to predict the ultimate
impact on 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.
Bills have been introduced unsuccessfully in the past in the Rhode Island
legislature to require that transmission lines be placed underground.
Legislation has been introduced in Massachusetts that, if passed, would
require state agencies to study existing EMF-related research and make
recommendations for further legislation.
Clean air requirements
Approximately 45 percent of NEP's electricity is produced at eight older
thermal generating units in Massachusetts. Six are fueled by coal, one by
oil, and one by oil and gas. The federal Clean Air Act requires significant
reduction in utility sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions
that result from burning fossil fuels by the year 2000 to reduce acid rain and
ground-level ozone (smog).
NEP is reducing SO2 emissions under Phase 1 of the federal acid rain
program that became effective in 1995. NEP is also subject to Massachusetts
SO2 and NOx reduction regulations taking effect in 1995. The SO2 and NOx
reductions that are being made to meet 1995 Phase 1 requirements have resulted
in one-time operation and maintenance costs of $16 million and capital costs
of $88 million through December 31, 1994. Additional expenditures in 1995 are
expected to be less than $10 million and $30 million, respectively. Depending
on fuel prices, NEP also expects to incur up to $5 million annually in
increased costs to purchase cleaner fuels to meet SO2 emission reduction
requirements.
All eight of NEP's thermal units will be subject to Phase 2 of the
federal and state acid rain regulations that become effective in 2000. NEP
believes that the SO2 controls already installed for the 1995 requirements
will satisfy the Phase 2 acid rain regulations.
In connection with the federal ozone emission requirements, state
environmental agencies in ozone non-attainment areas are developing a second
phase of NOx reduction regulations that would have to be fully implemented by
NEP no later than 1999. While the exact costs are not known, NEP estimates
that the cost of implementing these regulations would not jeopardize continued
operation of NEP's units.
The generation of electricity from fossil fuel also emits trace amounts
of certain hazardous air pollutants and fine particulates. An EPA study of
utility hazardous air pollutant emissions will be completed in 1995. The
study's conclusions could lead to new emission standards requiring costly
controls or fuel restrictions on NEP plants. At this time, NEES and its
subsidiaries cannot estimate the impact the findings of this research might
have on NEP's operations.
[GRAPH APPEARS HERE]
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
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 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 rate filing (see "Wholesale rate activity"
section).
Competitive conditions
The electric utility business is being subjected to increasing
competitive pressures, stemming from a combination of trends, including
increasing electric rates, improved technologies, and new regulations and
legislation intended to foster competition. To date, this competition has
been most prominent in the bulk power market in which non-utility generating
sources have noticeably increased their market share. For example, since
non-utilities were allowed to enter the wholesale generation market,
two-thirds of NEP's new generating capability has come from independent
generating sources and Hydro-Quebec.
Electric utilities are also facing increased competition in the retail
market. Currently, retail competition includes competition with alternative
fuel suppliers (including natural gas companies) for heating and cooling,
competition with customer-owned generation to displace purchases from electric
utilities, and direct competition among electric utilities to attract major
new facilities to their service territories. Electric utilities including the
NEES companies are under increasing pressure from large commercial and
industrial customers to discount rates or face the possibility that such
customers might relocate or seek alternate suppliers. Across the country,
including the states serviced by the NEES companies, there have been an
increasing number of proposals to allow retail customers to choose their
electricity supplier, with utilities required to deliver that electricity over
their transmission and distribution systems. In Massachusetts, the
Massachusetts Division of Energy Resources (DOER) proposed in January 1995
that the MDPU modify its regulations to allow retail utility customers to
choose a supplier and bid for access to the local utility's transmission and
distribution systems in situations where new generating capacity is needed.
The NEES companies have indicated their support for the DOER proposal. Also
in Massachusetts, the MDPU initiated a proceeding in February 1995 regarding
electric industry regulation and structure. In Rhode Island, the RIPUC has
convened a task force of utilities, commercial and industrial customers,
regulators, and other interested parties to prepare a report by May 1995
regarding restructuring the industry. In New Hampshire, the New Hampshire
Public Utilities Commission is considering the proposal of a new company to
sell electricity at retail to large customers in New Hampshire.
The impact of increased customer choice on the financial condition of
utilities is uncertain. In recent years, substantial surplus generating
capacity in the Northeast has resulted in the sale of bulk power by utilities
to other utilities at prices substantially below the total costs of owning and
operating, or contracting for, such generating capacity. Should retail
customers gain access to the bulk power market, particularly while surplus
capacity exists, it is unlikely that utilities would be able to charge power
prices which fully cover their costs. Such unrecovered costs, which could be
substantial, have been referred to by the industry as stranded costs.
[GRAPH APPEARS HERE]
Whether and to what extent utilities should be able to recover stranded
costs resulting from increased customer choice has been the subject of much
debate. In 1994, the FERC issued a notice of proposed rule-making on the
recovery of stranded costs. The NEES companies and other utilities have taken
the position that when a regulatory body changes policies which govern
customer choice and the resultant rates paid by customers, utilities must be
compensated for commitments made under the former policies. Furthermore, the
utility industry believes that recovery of stranded costs is necessary to
promote efficient competition among market participants. Previously, the FERC
ruled in 1992, in a proceeding not involving NEES subsidiaries, that a utility
may recover such stranded costs from a departing wholesale requirements
customer. On appeal, the United States Court of Appeals for the District of
Columbia Circuit has questioned whether allowing utilities to recover stranded
costs is anti-competitive and the Court remanded the case back to the FERC for
further proceedings and development of the competitive issues.
In addition to the arguments described above, the NEES companies have
taken the position that, because utility transmission and distribution assets
have a replacement value in excess of their historic costs (on which utility
rates are set), utilities should have the ability to recover stranded
generation-related costs by realizing the higher value of transmission and
distribution assets. The NEES companies have stated their willingness, in
order to assure stranded cost recovery and promote increased competition, to
consider divesting their transmission system, either through sale or spinoff.
The NEES companies are actively responding to current and anticipated
competitive pressures in a variety of ways, including cost control and a 1993
corporate reorganization into separate retail and wholesale business units.
The wholesale business unit has responded to increased competition by freezing
base rates until at least 1997 (base rates were last raised in March 1992),
terminating certain purchased power and gas pipeline contracts, shutting down
uneconomic generating stations, and accelerating the recovery of uneconomic
assets and other deferred costs. In addition, NEP's wholesale tariff requires
its wholesale customers, including NEES's retail subsidiaries, to provide
seven years notice before they may terminate the tariff.
The retail business unit's response to competition includes the EnergyFIT
program which offers comprehensive value-added services for large business
customers, intensified business development efforts, including economic
development rates and service packages to encourage businesses to locate in
the retail companies' service territories, and development of new pricing and
service options for customers. Additionally, more than 80 percent of the NEES
companies' large commercial and industrial customers have signed service
extension discount (SED)contracts providing for discounts and requiring three
to five years notice before they may change electricity suppliers (see "Retail
rate activity" section). As part of their long-term planning process, the
NEES companies are from time to time evaluating other strategies, such as
business combinations and other forms of restructuring, to better respond to
the changing competitive environment.
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These accounting
rules require regulated entities, in appropriate circumstances, to establish
regulatory assets and liabilities, which defer the income statement impact of
certain costs that are expected to be recovered in future rates. The effects
of competition could ultimately cause the operations of the NEES companies, or
a portion thereof, to cease meeting the criteria for application of these
accounting rules. In such an event, accounting standards applicable to
enterprises in general would apply and immediate write-off of any previously
deferred costs (regulatory assets) would be necessary in the year in which
these criteria were no longer applicable. In addition, if, because of
competition, utilities are unable to recover all of their costs in rates, it
may be necessary to write off those costs that are not recoverable.
[GRAPH APPEARS HERE]
Liquidity and capital resources
Capital requirements for 1994 and projections for 1995 are shown below:
Year ended December 31 (millions of dollars)1994 1995
---- ----
Cash expenditures for utility plant:
Manchester Street repowering project $176 $125
All other 262 200
Oil and gas exploration and development 28 15
---- ----
Total capital expenditures $466 $340
Maturing debt and prepayment requirements35 66
---- ----
Total capital requirements $501 $406
Cash from utility operations after
payment of dividends $285 $265
Cash from oil and gas operations 57 50
---- ----
Total cash from operations after the
payment of dividends $342 $315
The funds necessary for utility plant expenditures in 1994 were primarily
provided by net cash from operating activities, after the payment of
dividends, and the proceeds of short-term and long-term borrowings.
The financing activities of the NEES subsidiaries for 1994 are summarized
as follows:
Long-term debt
----------------------------
(millions of dollars) Issues Retirements
------ -----------
NEP $28
Massachusetts Electric 36
Narragansett 33
Granite State Electric Company $ 1
Hydro-Transmission Companies 12
NEEI 22
---- ----
$97 $35
Interest rates on the long-term debt issues shown above range from 6.91
percent to 8.85 percent.
Internally generated funds are expected to meet approximately 75 percent
of the 1995 capital expenditure requirements for utility plant. NEP and the
retail subsidiaries have issued $56 million of long-term debt to date in 1995
at interest rates ranging from 7.79 percent to 8.45 percent. These companies
plan to issue an additional $120 million of long-term debt later in 1995 to
meet maturing long-term debt obligations, reduce short-term debt and fund
capital expenditures.
Net cash from operating activities provided all of the funds necessary
for oil and gas expenditures. NEEI's 1994 oil and gas exploration and
development costs included $10 million of capitalized interest costs.
The NEES subsidiaries' major construction project is the repowering of
Manchester Street Station, a 140 MW electric generating station in Providence,
Rhode Island. Repowering will more than triple the power generation capacity
of Manchester Street Station and substantially increase the plant's thermal
efficiency. 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, scheduled to be placed in service in late 1995, is estimated to be
approximately $520 million including AFDC. At December 31, 1994, $298
million, including AFDC, had been spent on the generating station. In
addition, related transmission improvements were placed in service in
September 1994 at a cost of approximately $60 million.
At December 31, 1994, NEES and its consolidated subsidiaries had lines of
credit and standby bond purchase facilities with banks totaling $663 million.
These lines and facilities were used at December 31, 1994 for $2 million of
direct borrowings, and for liquidity support for $232 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)
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery)$1,518$1,488 $1,424 $1,358 $1,282
Fuel cost recovery 568 582 597 585 523
Other utility revenue 117 117 118 114 65
Oil and gas sales 40 47 43 37 39
------ ------ ------ ------ ------
Total operating revenue$2,243 $2,234 $2,182 $2,094 $1,909
Net income $ 199 $ 190 $ 185 $ 180 $ 262*
Average common shares
outstanding (000's) 64,970 64,970 64,970 64,917 63,818
Per share data:
Net income $3.07 $ 2.93 $ 2.85 $ 2.77 $ 4.11*
Dividends declared $2.285 $ 2.22 $ 2.14 $ 2.07 $ 2.04
Return on average
common equity 12.73% 12.64% 12.58% 12.64% 20.52%*
Total assets $5,085 $4,796 $4,585 $4,450 $4,408
Capitalization:
Common share equity $1,581 $1,530 $1,487 $1,441 $1,380
Minority interests 55 56 61 63 62
Cumulative preferred stock 147 147 162 162 162
Long-term debt 1,520 1,512 1,533 1,548 1,680
------ ------ ------ ------ ------
Total capitalization $3,303 $3,245 $3,243 $3,214 $3,284
Sales billed to ultimate
customers (millions of KWH)21,155 20,832 20,554 20,470 20,727
Cost per KWH to ultimate
customers (cents) 9.29 9.50 9.43 8.99 8.27
System maximum demand (MW)4,385 4,081 3,964 4,250 4,059
Electric capability
(MW net)-year end 5,533 5,362 5,479 5,645 5,627
Number of employees 4,990 4,969 5,415 5,533 5,666
Number of customers 1,300,1981,288,1841,277,281 1,257,2131,256,656
<FN>
*1990 includes $1.80 per share, resulting from a rate settlement related to Seabrook 1.
</FN>
New England Electric System and Subsidiaries
Statements of Consolidated Income
Year ended December 31 (thousands of dollars, except per share data)
1994 1993 1992
---------- ---------- ----------
Operating revenue: $2,243,029 $2,233,978 $2,181,676
Operating expenses:
Fuel for generation 220,956 227,182 237,161
Purchased electric energy514,143 527,307 525,655
Other operation 494,741 492,079 423,330
Maintenance 161,473 146,219 162,974
Depreciation and amortization301,123 296,631 302,217
Taxes, other than income taxes125,840120,493 114,027
Income taxes 128,257 121,124 110,761
--------- --------- ---------
Total operating expenses1,946,533 1,931,035 1,876,125
Operating income 296,496 302,943 305,551
Other income:
Allowance for equity funds used
during construction 10,169 3,795 2,732
Equity in income of generating
companies 9,758 11,016 13,052
Other income (expense)-net(3,856) (1,154) 936
--------- ---------- ---------
Operating and other income312,567 316,600 322,271
Interest:
Interest on long-term debt93,500 100,777 114,182
Other interest 11,298 9,809 5,420
Allowance for borrowed funds
used during construction (7,793) (2,816) (2,204)
--------- --------- ----------
Total interest 97,005 107,770 117,398
Income after interest 215,562 208,830 204,873
Preferred dividends of
subsidiaries 8,697 10,585 10,572
Minority interests 7,439 8,022 9,264
--------- --------- ---------
Net income $199,426 $190,223 $185,037
Common shares outstanding64,969,65264,969,65264,969,652
Per share data:
Net income $ 3.07 $ 2.93 $ 2.85
Dividends declared $ 2.285 $ 2.22 $ 2.14
Statements of Consolidated Retained Earnings
Year ended December 31 (thousands of dollars)
1994 1993 1992
---------- ---------- ----------
Retained earnings at
beginning of year $ 728,075 $ 684,132 $ 638,130
Net income 199,426 190,223 185,037
Dividends declared on common
shares (148,456) (144,233) (139,035)
Premium on redemption of
preferred stock of
subsidiaries (2,047)
---------- --------- ---------
Retained earnings at end
of year $ 779,045 $ 728,075 $ 684,132
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)
1994 1993
---------- ----------
Assets
Utility plant, at original cost $4,914,807 $4,661,612
Less accumulated provisions for depreciation and
amortization 1,610,378 1,511,271
---------- ----------
3,304,429 3,150,341
Net investment in Seabrook 1 under rate settlement
(Note C) 38,283 103,344
Construction work in progress 374,009 228,816
---------- ----------
Net utility plant 3,716,721 3,482,501
Oil and gas properties, at full cost (Note A)1,248,3431,220,110
Less accumulated provision for amortization 964,069 884,837
---------- ----------
Net oil and gas properties 284,274 335,273
Investments:
Nuclear power companies, at equity (Note D) 46,349 46,342
Other subsidiaries, at equity 42,195 44,676
Other investments 50,895 28,836
---------- ----------
Total investments 139,439 119,854
Current assets:
Cash 3,047 2,876
Accounts receivable, less reserves of $15,095
and $14,551 295,627 275,020
Unbilled revenues (Note A) 55,900 43,400
Fuel, materials, and supplies, at average cost94,431 74,314
Prepaid and other current assets 76,718 69,004
---------- ----------
Total current assets 525,723 464,614
Accrued Yankee Atomic costs (Note D) 122,452 103,501
Deferred charges and other assets (Note A) 296,232 290,135
---------- ----------
$5,084,841 $4,795,878
========== ==========
Capitalization and liabilities
Capitalization (see accompanying statements):
Common share equity $1,580,838 $1,529,868
Minority interests in consolidated subsidiaries55,066 55,855
Cumulative preferred stock of subsidiaries 147,016 147,528
Long-term debt 1,520,488 1,511,589
---------- ----------
Total capitalization 3,303,408 3,244,840
Current liabilities:
Long-term debt due within one year 65,920 12,920
Short-term debt 233,970 71,775
Accounts payable 168,937 128,342
Accrued taxes 11,002 10,332
Accrued interest 25,193 23,278
Dividends payable 37,154 36,950
Other current liabilities (Note A) 93,251 153,812
---------- ----------
Total current liabilities 635,427 437,409
Deferred federal and state income taxes 751,855 705,026
Unamortized investment tax credits 94,930 99,355
Accrued Yankee Atomic costs (Note D) 122,452 103,501
Other reserves and deferred credits 176,769 205,747
Commitments and contingencies (Note E) ---------- ----------
$5,084,841 $4,795,878
========== ==========
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)
1994 1993 1992
--------- --------- ---------
Operating activities
Net income $ 199,426 $ 190,223 $ 185,037
Adjustments to reconcile net
income to net cash provided by
operating activities:
Depreciation and amortization 305,908 300,444 305,046
Deferred income taxes and
investment tax credits-net 41,741 4,105 11,163
Allowance for funds used during
construction (17,962) (6,611) (4,936)
Amortization of unbilled revenues(38,458) (2,700)
Minority interests 7,439 8,022 9,264
Early retirement program 23,922
Decrease (increase) in accounts
receivable, net and unbilled
revenues (33,107) (27,503) (27,157)
Decrease (increase) in fuel,
materials, and supplies (20,117) 13,786 (8,590)
Decrease (increase) in prepaid and
other current assets (7,714) 5,904 (64,858)
Increase (decrease) in accounts
payable 40,595 (42,967) 34,623
Increase (decrease) in other current
liabilities (25,676) 64,658 (2,447)
Other, net (34,109) (32,632) (2,146)
--------- --------- --------
Net cash provided by operating
activities $ 417,966 $ 498,651 $ 434,999
Investing activities
Plant expenditures, excluding
allowance for funds used during
construction $(438,016) $(304,659) $(241,872)
Oil and gas exploration and
development (28,233) (18,965) (21,262)
Other investing activities (18,830) (107) 2,388
--------- --------- ---------
Net cash used in investing
activities $(485,079) $(323,731) $(260,746)
Financing activities
Dividends paid to minority interests$ (8,416)$ (10,622)$ (15,939)
Dividends paid on NEES common shares(148,063)(142,352)(140,174)
Short-term debt 162,195 29,525 42,250
Long-term debt-issues 97,000 372,500 477,500
Long-term debt-retirements (34,920) (395,820) (585,120)
Preferred stock-issues 55,000
Preferred stock-retirements (512) (70,000)
Premium on reacquisition of long-term
debt (10,996) (16,135)
Premium on redemption of preferred
stock (2,047)
--------- --------- ---------
Net cash provided by (used in)
financing activities $ 67,284 $(174,812) $(237,618)
Net increase (decrease) in cash and
cash equivalents $ 171 $ 108 $ (63,365)
Cash and cash equivalents at beginning
of year 2,876 2,768 66,133
--------- --------- ---------
Cash and cash equivalents at end of
year $ 3,047 $ 2,876 $ 2,768
Supplementary information
Interest paid less amounts capitalized$ 90,500$ 97,518$ 119,146
Federal and state income taxes paid$ 114,597$ 124,853$ 99,935
Dividends received from investments at
equity $ 15,350 $ 14,404 $ 18,405
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)
1994 1993
---------- ----------
Common share equity
Common shares, par value $1 per share
Authorized-150,000,000 shares
Outstanding-64,969,652 shares $ 64,970 $ 64,970
Paid-in capital 736,823 736,823
Retained earnings 779,045 728,075
---------- ----------
Total common share equity $1,580,838 $1,529,868
Cumulative preferred stock of Shares outstanding
subsidiaries
1994 1993 1994 1993
--------- --------- -------- --------
$100 Par value-
4.44% to 4.76% 430,140 430,140 $ 43,014 $ 43,014
6.00% to 7.24% 525,020 530,140 52,502 53,014
$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 1994
and $8,720 for 1993) 2,285,160 2,290,280 $147,016 $147,528
Long-term debt (Note H) Maturity Rate 1994 1993
------------------------------------- --------
Mortgage bonds* 1995 through 19994.730%-8.280%$ 203,500$ 187,500
2000 through 20046.240%-8.520%187,500 152,500
2005 through 20146.110%-6.660%35,000 35,000
2015 through 20247.050%-9.125%422,550 376,550
2018 through 2022 Variable342,000 342,000
Notes
Granite State Electric Company1996 through 20237.370%-12.550%14,40015,800
New England Energy Incorporated 1998 Variable216,000238,000
Hydro-Transmission Companies2001 through 20158.820%-9.410%171,050 182,570
Unamortized discounts and premiums, net (5,592) (5,411)
-------------------
Total long-term debt 1,586,4081,524,509
Long-term debt due in one year (65,920) (12,920)
-------------------
$1,520,488$1,511,589
<FN>
*Includes $382,350 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.Basis of consolidation and system of accounts
The consolidated financial statements include the accounts of New England
Electric System (NEES) and all subsidiaries except New England Electric
Transmission Corporation, which is recorded at equity. 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 (Resources) has a 20 percent general partnership interest in
the Ocean State Power (OSP) generating facility. NEP and Resources account
for these ownership interests on 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. Since NEES is the majority stockholder in these
companies, the ownership interests of the other stockholders are called
minority interests and have been separately disclosed on the NEES consolidated
income statements and balance sheets. The "Minority interests" line on the
statements of consolidated income includes the minority interests' portion of
the net earnings of the Hydro-Transmission companies.
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 $400 million. (See Note C for a discussion of Seabrook 1.)
NEP's share of the related 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.
2.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 at December 31,
1994 and 1993 were $56 million and $43 million, respectively, of which, $37
million and $11 million were recognized in income in 1994 and the fourth
quarter of 1993, respectively. The remainder of $8 million at December 31,
1994 has been deferred for recognition monthly through December 1995. Accrued
revenues are also recorded in accordance with rate adjustment mechanisms.
3.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 1994, an average of $30 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 7.6 percent,
7.4 percent, and 8.6 percent, in 1994, 1993, and 1992, respectively.
4.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) 1994 1993 1992
---------------- --------
Depreciation $136,746$127,428 $130,655
Nuclear decommissioning costs (Note A-5) 1,951 1,951 1,890
Amortization:
Oil and gas properties (Note A-6) 79,232 90,399 99,687
Investment in Seabrook 1 nuclear unit under
rate settlement (Note C) 65,061 58,437 52,443
Oil Conservation Adjustment 11,854 12,137 11,263
Property losses 6,279 6,279 6,279
---------------- --------
Total depreciation and amortization expense$301,123$296,631$302,217
Depreciation is provided annually on a straight-line basis. The provision
for depreciation as a percentage of weighted average depreciable property was
3.1 percent in 1994, 3.0 percent in 1993, and 3.2 percent in 1992.
The Oil Conservation Adjustment is designed to recover expenditures for
coal conversion facilities at NEP's Salem Harbor Station by 1995. At December
31, 1994, such unamortized coal conversion costs included in utility plant
were $4,467,000.
5.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. 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 Federal Energy
Regulatory Commission (FERC).
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 its
plant. If any of the units were shut down prior to the end of their operating
licenses, the funds collected for decommissioning to that point would be
insufficient. Listed below is information on each nuclear plant in which NEP
has an ownership interest. (See Note D for a discussion of Yankee Atomic
Nuclear Power Station decommissioning.)
NEP's share of (millions of dollars)
---------------------------------------------------
Estimated
Ownership Decommissioning Fund License
Unit Interest Cost (in 1994 $)Balances**Expiration
- ----------------------------------------------------------------
Connecticut Yankee 15% 53 22 2007
Maine Yankee*** 20% 66 22 2008
Vermont Yankee 20% 66 23 2012
Millstone 3* 12% 53 11 2025
Seabrook 1* 10% 36 4 2026
*Fund balances are included in "Other investments" on the balance sheet
and approximate market value.
**Certain additional amounts are anticipated to be available through tax
deductions.
***A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for the plant
decommissioning, the owners of Maine Yankee are jointly and severally
liable for the shortfall.
In accordance with its recent rate agreement which became effective in
1995, NEP is allowed to defer for later recovery any increases in
decommissioning payments over the level included in rates until its next rate
filing becomes effective.
There is no assurance that decommissioning costs actually incurred by the
Yankees, Millstone 3, or Seabrook 1 will not substantially exceed these
amounts. For example, decommissioning cost estimates assume the availability
of permanent repositories for both low-level and high-level nuclear waste
which do not currently exist.
The Nuclear Waste Policy Act of 1982 establishes that the federal
government is responsible for the disposal of spent nuclear fuel. The federal
government requires NEP to pay a fee based on its share of the net generation
from the Millstone 3 and Seabrook 1 nuclear units. 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 recovered
from customers through NEP's fuel clause.
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. Savings and losses from this program are being 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 precipitate declines in
oil and gas prices, and expects to incur substantial additional losses in the
future. Such losses were $40 million, $46 million, and $55 million in 1994,
1993, and 1992, respectively. NEP's ability to pass these losses on to its
customers was favorably resolved in NEP's 1988 FERC rate settlement. This
settlement covered all costs incurred by or resulting from commitments made by
NEEI through March 1, 1988. Other subsequent costs incurred by NEEI are
subject to normal regulatory review. 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,
$9 million, and $14 million was capitalized in 1994, 1993, and 1992,
respectively. In the absence of the Pricing Policy, the SEC's full cost
"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 1994 average oil and gas selling
prices and NEEI's proved reserves at December 31, 1994, application of the
ceiling test would have resulted in a write-down of approximately $120 million
after tax.
7.Cash
NEES and its subsidiaries classify short-term investments with a maturity
of 90 days or less as cash. Current banking arrangements do not require
outstanding checks to be funded until actually presented for payment.
Outstanding checks are therefore recorded in accounts payable until such time
as the banks present them for payment.
8.Deferred charges and other assets
The components of deferred charges and other assets are as follows:
At December 31 (thousands of dollars) 1994 1993
---------- ----------
Regulatory assets:
Unamortized losses on reacquired debt $ 56,249 $ 60,333
Deferred SFAS No. 106 costs (see Note F-2)41,009 24,563
Deferred SFAS No. 109 costs (see Note B)74,423 73,760
Purchased power termination costs 29,012 28,400
Deferred gas pipeline charges (see Note E-2)37,562 13,187
Environmental response costs (see Note E-3)13,167 18,752
Deferred storm costs 10,822 14,774
Unamortized property losses 7,373 12,745
Other 5,111 11,892
-------- --------
274,728 258,406
Other deferred charges and other assets:
Intangible asset-pensions (see Note F-1) 4,749 15,103
Other 16,755 16,626
-------- --------
$296,232 $290,135
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These accounting
rules require regulated entities, in appropriate circumstances, to establish
regulatory assets and liabilities, which defer the income statement impact of
certain costs that are expected to be recovered in future rates. The effects
of competition could ultimately cause the operations of the NEES companies, or
a portion thereof, to cease meeting the criteria for application of these
accounting rules. In such an event, accounting standards applicable to
enterprises in general would apply and immediate write-off of any previously
deferred costs (regulatory assets) would be necessary in the year in which
these criteria were no longer applicable. Approximately $150 million of the
regulatory assets at December 31, 1994 listed above are expected to be
recovered within 10 years, with the majority of the remaining balance to be
recovered within the following 20 years. The only items for which the
majority of the balance shown above will not be recovered within the next 10
years are the deferred SFAS No. 109 costs and the deferred gas pipeline
charges.
9.Other current liabilities
The components of other current liabilities are as follows:
At December 31 (thousands of dollars) 1994 1993
---------- ----------
Accrued wages and benefits $26,035 $ 39,756
Deferred unbilled revenues 8,209 32,300
Rate adjustment mechanisms 31,311 31,237
Accrued purchased power termination costs 21,900
Customer deposits 10,951 12,336
Other 16,745 16,283
------- --------
$93,251 $153,812
Note B - Income taxes
Total income taxes in the statements of consolidated income are as follows:
Year ended December 31 (thousands of dollars) 1994 1993 1992
---------------- --------
Income taxes charged to operations $128,257$121,124 $110,761
Income taxes charged to "Other income" 779 3,147 3,192
---------------- --------
Total income taxes $129,036$124,271 $113,953
Total income taxes, as shown above, consist of the following components:
Year ended December 31 (thousands of dollars) 1994 1993 1992
-------- ----------------
Current income taxes $ 87,295$120,167 $102,790
Deferred income taxes 46,166 7,756 13,475
Investment tax credits-net (4,425) (3,652) (2,312)
---------------- --------
Total income taxes $129,036$124,271 $113,953
Total income taxes, as shown above, consist of federal and state components as
follows:
Year ended December 31 (thousands of dollars) 1994 1993 1992
-------- ----------------
Federal income taxes $104,136$ 98,529 $ 92,647
State income taxes 24,900 25,742 21,306
---------------- --------
Total income taxes $129,036$124,271 $113,953
Investment tax credits of subsidiaries are deferred and amortized over the
estimated lives of the property giving rise to the credits. Since the Tax
Reform Act of 1986 generally eliminated investment tax credits, the amounts
shown above principally reflect the amortization of investment tax credits
generated in prior years.
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) 1994 1993 1992
-------- ----------------
Computed tax at statutory rate $118,006$113,778 $105,251
Increases (reductions) in tax resulting from:
Reversal of deferred taxes recorded at a
higher rate (4,230) (5,099) (7,175)
Amortization of investment tax credits (5,272) (4,697) (5,384)
State income tax, net of federal income
tax benefit 16,185 16,732 14,062
All other differences 4,347 3,557 7,199
---------------- --------
Total income taxes $129,036$124,271 $113,953
The Financial Accounting Standards Board established Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes" which
became effective in 1993. The application of this new standard did not have a
significant impact on 1993 or 1994 net income.
The following table identifies the major components of total deferred
income taxes:
At December 31 (millions of dollars) 1994 1993
---------- ----------
Deferred tax asset:
Plant related $ 107 $ 99
Investment tax credits 38 40
All other 108 129
------ ------
253 268
Deferred tax liability:
Plant related (777) (758)
Equity AFDC (52) (57)
All other (176) (158)
------ ------
(1,005) (973)
------ ------
Net deferred tax liability $ (752) $ (705)
There were no valuation allowances for deferred tax assets deemed
necessary.
The deferred taxes resulting from timing differences which appear on the
income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993)
primarily include deferred income taxes of $29 million related to utility
plant and $17 million in connection with postretirement benefits, partially
offset by deferred tax credits of $31 million associated with oil and gas
operations.
Federal income tax returns for NEES and its subsidiaries have been examined
and reported on by the Internal Revenue Service through 1991.
Note C - Seabrook Nuclear Unit 1 (Seabrook 1)
NEP owns approximately 10 percent of Seabrook 1, a 1,150 MW nuclear
generating unit that entered commercial service in 1990. NEP's rate recovery
of its investment in Seabrook 1 was resolved through two separate rate
settlement agreements. NEP's pre-1988 investment was being recovered in rates
over a period of seven and one-half years ending in mid-1995. Under NEP's rate
agreement, that was recently approved by the FERC, approximately $15 million
of the $38 million in Seabrook 1 costs due to be recovered in 1995 pursuant to
a 1988 settlement agreement will be deferred and recovered in 1996. This
investment, net of amortization, is shown on a separate line on the
consolidated balance sheets. NEP's net investment in Seabrook 1 since
January 1, 1988, which amounts to approximately $43 million at December 31,
1994, is included under the caption "Utility plant" on the consolidated
balance sheet and is being recovered over 37 years.
Note D - Yankee Atomic Nuclear Power Station
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. The station began commercial service in 1960. At December 31,
1994, NEP's investment in Yankee Atomic was approximately $7 million. In
February 1992, the Yankee Atomic board of directors decided to permanently
cease power operation of, and in time decommission, the facility.
In March 1993, the FERC approved a settlement agreement that allows Yankee
Atomic to recover all but $3 million of its approximately $50 million
remaining investment in the plant over the period extending to July 2000, when
the plant's Nuclear Regulatory Commission (NRC) operating license would have
expired. Yankee Atomic recorded the $3 million before-tax write-down in 1992.
The settlement agreement also allows Yankee Atomic to earn a return on the
unrecovered balance during the recovery period and to recover other costs,
including an increased level of decommissioning costs, over this same period.
Decommissioning cost recovery increased from $6 million per year to $27
million per year for the period 1993 to 1995. In the fourth quarter of 1994,
Yankee announced a new decommissioning cost estimate that, subject to approval
by the FERC, would increase billings to NEP by an additional $11 million per
year through July 2000.
NEP has recorded an estimate of its entire future payment obligations to
Yankee Atomic as a liability on its balance sheet and an offsetting regulatory
asset reflecting its expected future rate recovery of such costs. This
liability and related regulatory asset amounted to approximately $122 million
each at December 31, 1994, and are included on separate lines in the
consolidated balance sheet.
Note E - Commitments and contingencies
1. Plant expenditures
The NEES subsidiaries' utility plant expenditures are estimated to be $325
million in 1995. At December 31, 1994, substantial commitments had been made
relative to future planned expenditures.
2. Natural gas pipeline capacity
In connection with NEP's efforts to reduce sulfur dioxide emissions and
repower generating units, NEP has signed several contracts for natural gas
pipeline capacity and gas supply. These agreements require minimum fixed
payments. NEP's minimum net payments are currently estimated to be
approximately $65 million in 1995 and $70 million per year during 1996 to
1999.
As part of a rate settlement, NEP is recovering 50 percent of the fixed
pipeline capacity payments through its current fuel clause and deferring the
recovery of the remaining 50 percent until the Manchester Street repowering
project is completed. NEP has deferred payments of approximately $38 million
as of December 31, 1994 (see Note A-8). NEP has been using a portion of this
capacity to sell natural gas, the proceeds from which have been passed to
customers through NEP's fuel clause.
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 in its
operations a range of potentially hazardous products and by-products. NEES
subsidiaries currently have in place an environmental audit program intended
to enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
NEES and/or its subsidiaries have been named as a potentially responsible
party (PRP) by either the U.S. Environmental Protection Agency (EPA) or the
Massachusetts Department of Environmental Protection for 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 seven 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, at
which 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. It is uncertain at this time what the cost of
any ultimate cleanup plan will be or what NEES's share of such costs will be.
In 1993, the Massachusetts Department of Public Utilities approved a rate
agreement filed by Massachusetts Electric 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. 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. The resolution of the issue of rate recovery resulted in a
one-time increase to fourth quarter 1993 earnings of $11 million due to the
reversal of a portion of previously established hazardous waste reserves.
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 would be successful. At December 31, 1994, NEES had
total reserves for environmental response costs of $45 million and a related
regulatory asset of $13 million. NEES believes that hazardous waste
liabilities for all sites of which it is aware, and which are not covered by a
rate agreement, will not be material to its financial position.
4. Nuclear insurance
The Price-Anderson Act limits the amount of liability claims that would
have to be paid in the event of a single incident at a nuclear plant to $8.9
billion (based upon 110 licensed reactors). The maximum amount of
commercially available insurance coverage to pay such claims is only $200
million. The remaining $8.7 billion would be provided by an assessment of up
to $79.3 million per incident levied on each of the nuclear units in the
United States, subject to a maximum assessment of $10 million per incident per
nuclear unit in any year. The maximum assessment, which was most recently
calculated in 1993, is to be adjusted at least every five years to reflect
inflationary changes. NEP's current interest in the Yankees (excluding Yankee
Atomic), Millstone 3, and Seabrook 1 would subject NEP to a $58.0 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 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 $17 million per year.
5. Long-term contracts for the purchase of electricity
NEP purchases a portion of its electricity requirements pursuant to
long-term contracts with owners of various generating units. These contracts
expire in various years from 1995 to 2029.
Certain of these contracts require 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
majority of the payments under these contracts are to the Yankees (excluding
Yankee Atomic-see Note D) and OSP, entities in which NEES subsidiaries hold
ownership interests. The fixed portion of payments under these contracts
totaled $190 million in 1994 and $220 million in 1993 and 1992. These
contracts have minimum fixed payment requirements of $215 million in 1995,
$195 million in 1996, $190 million in 1997 and 1998, $185 million in 1999, and
approximately $2 billion thereafter.
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 $210 million
in 1994 and 1993 and $200 million in 1992.
6. 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
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 a recent NEP rate filing.
Note F - 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 before
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 required contribution under federal
law or greater than the maximum tax deductible amount.
Net pension cost for 1994, 1993, and 1992 included the following
components:
Year ended December 31 (thousands of dollars) 1994 1993 1992
-------- ----------------
Service cost-benefits earned during the period$13,715$11,160$10,984
Plus (less):
Interest cost on projected benefit obligation49,06749,34646,171
Return on plan assets at expected long-term
rate (47,281)(45,032) (43,877)
Amortization 5,781 1,364 1,239
------- ------- -------
Net pension cost $21,282 $16,838 $14,517
Assumptions used to determine pension cost were:
Discount rate 7.25% 8.25% 8.50%
Average rate of increase in future compensation
levels 4.35% 5.35% 6.70%
Expected long-term rate of return on assets8.75%8.75% 9.00%
------- ------- -------
Actual return on plan assets $ 4,384 $69,208 $38,489
Service cost for 1993 does not reflect costs incurred in connection with an
early retirement program offered by the NEES subsidiaries in that year (see
Note F-3).
The following table sets forth the plans' funded status at December 31 (millions of dollars):
------------------------------------------------------------
Retirement Plans
------------------------------------------------------------
1994 1993
----------------------------------------------------------
Union Non-Union Supple- Union Non-unionSupple-
Employee Employee mental EmployeeEmployee mental
Plans Plans Plans Plans Plans Plans
-------- -------- ------- ---------------- -------
Benefits earned
Actuarial present value
of accumulated benefit
liability:
Vested $251 $308 $38 $251 $333 $40
Non-vested 8 9 - 20 6 -
---- ---- ---- ---- ---- ----
Total $259 $317 $38 $271 $339 $40
Reconciliation of funded status
Actuarial present value of
projected benefit liability$303 $355 $44 $310 $383 $44
Unrecognized prior service costs(8) (4) (5) (8) (6) (4)
SFAS No. 87 transition liability
not yet recognized (amortized)- (1) (5) - (1) (5)
Net gain (loss) not yet
recognized (amortized) (13) (33) 2 (11) (45) (2)
Additional minimum liability
recognized - - 5 - 8 7
----- ----- ----- ----- ----- -----
282 317 41 291 339 40
Pension fund assets at fair value293 323 - 302 318 -
SFAS No. 87 transition asset
not yet recognized (amortized)(13) - - (14) - -
----- ----- ----- ----- ----- -----
280 323 - 288 318 -
----- ----- ----- ----- ----- -----
Accrued pension/(prepaid)
payments recorded on books $ 2 $ (6) $41 $ 3 $ 21 $40
The assumed discount rate and the assumed average rate of increase in
future compensation levels used to calculate pension cost changed
effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively.
The expected long-term rate of return on assets used to calculate pension
cost was not changed from the level shown in the table above. The plans'
funded status at December 31, 1994 was calculated using these revised
rates.
Plan assets are composed primarily of corporate equity, guaranteed
investment contracts, debt securities, and cash equivalents.
2.Postretirement benefit plans other than pensions
In 1993, SFAS No. 106, "Employer's Accounting for Postretirement
Benefits Other than Pensions" (PBOPs) went into effect. The NEES
subsidiaries provide health care and life insurance coverage to eligible
retired employees. Eligibility is based on certain age and length of
service requirements and in some cases retirees must contribute to the
cost of their coverage.
The total cost of PBOPs for 1994 and 1993 includes the following
components:
Year ended December 31 (thousands of dollars) 1994 1993
---------- ----------
Service cost-benefits earned during the period$ 8,575 $ 8,160
Plus (less):
Interest cost on the accumulated benefit
obligation 27,813 30,457
Return on plan assets at expected long-term
rate (7,821) (5,089)
Amortization 18,273 18,418
------- -------
Net postretirement benefit cost $46,840 $51,946
------- -------
Actual return on plan assets $ 185 $ 5,249
The following table sets forth benefits earned and the plans' funded
status:
At December 31 (millions of dollars) 1994 1993
---------- ----------
Accumulated postretirement benefit obligation:
Retirees $226 $249
Fully eligible active plan participants 42 23
Other active plan participants 95 130
----- -----
Total benefits earned 363 402
Unrecognized transition obligation (331) (350)
Net gain (loss) not yet recognized 43 (7)
----- -----
75 45
Plan assets at fair value 109 86
Prepaid postretirement benefit costs
recorded on books $ 34 $ 41
1995 1994 1993
------ ------ ------
Assumptions to determine postretirement
benefit cost:
Discount rate 8.25% 7.25% 8.25%
Expected long-term rate of return on assets 8.50% 8.50% 8.50%
Health care cost rate - 1994 and 1993 - 11.00% 12.00%
Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50%
Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25%
The plans' funded status at December 31, 1994 and 1993 presented above was
calculated using the assumed rates in effect for 1995 and 1994, respectively.
The health care cost trend rate assumption has a significant effect on the
amounts reported. Increasing the assumed rates by 1 percent in each year
would increase the accumulated postretirement benefit obligation as of
December 31, 1994 by approximately $54 million and the net periodic cost for
the year 1994 by approximately $7 million.
The NEES subsidiaries fund the annual tax deductible contributions. Plan
assets are invested in equity and debt securities and cash equivalents.
Prior to 1993, NEES subsidiaries recorded the cost of PBOPs when paid.
These costs amounted to approximately $13 million in 1992. Each of the NEES
subsidiaries has been permitted to recover amounts on either a current and/or
deferred basis, which are expected to at least equal the amounts calculated in
accordance with this new accounting standard. Adoption of this new accounting
standard did not have a significant impact on net income.
3.1993 Early retirement and special severance programs
In February 1993, NEES subsidiary companies offered a voluntary early
retirement program to non-union employees who were at least 55 years old with
10 years of service. This program was part of an organizational review with
the goal of streamlining operations and reducing the work force. The early
retirement offer was accepted by 344 employees. A special severance program
was also announced in February 1993 for employees affected by the
organizational review, but who were not eligible for, or did not accept, the
early retirement offer. NEES subsidiaries recorded in the first quarter a
one-time charge to 1993 earnings of approximately $18 million, after tax ($28
million, before tax), to reflect the cost of the early retirement and special
severance programs which consisted principally of pension benefits.
Note G - Short-term borrowings
At December 31, 1994, NEES and its consolidated subsidiaries had lines of
credit and standby bond purchase facilities with banks totaling $663 million.
These lines and facilities were used at December 31, 1994 for $2 million of
direct borrowings, and for liquidity support for $232 million of commercial
paper borrowings and $342 million of NEP mortgage bonds in tax-exempt
commercial paper mode (see Note H). Fees are paid on the lines and facilities
in lieu of compensating balances. The weighted average rate on outstanding
short-term borrowings was 6.1 percent at December 31, 1994. The fair value of
the NEES subsidiaries' short-term debt equals carrying value.
Note H - 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) 1995 1996 1997 1998 1999
------- --------------- -------- -------
Maturing long-term debt $35,000$10,000 $ 65,500$ 60,000 $33,000
Mandatory prepayments:
Hydro-Transmission Companies11,52011,520 11,520 11,520 11,520
Granite State Electric Company3,4001,000
NEEI 16,000 75,000 75,000 50,000
-------------- ---------------- -------
Total $65,920$97,520 $152,020$121,520 $44,520
The terms of $342 million of variable rate pollution control revenue bonds
collateralized by NEP mortgage bonds require NEP to reacquire the bonds under
certain limited circumstances. At December 31, 1994, interest rates on NEP's
variable rate bonds ranged from 3.30 percent to 5.60 percent. Also, at
December 31, 1994, interest rates on NEEI's debt ranged from 5.94 percent to
7.00 percent. NEP and the retail subsidiaries have issued $56 million of
long-term debt to date in 1995 at interest rates ranging from 7.79 percent to
8.45 percent.
At December 31, 1994, the NEES subsidiaries' long-term debt had a carrying
value of approximately $1,586,000,000 and had a fair value of approximately
$1,555,000,000. To estimate fair value, the carrying amount was used for debt
that reprices frequently at market rates because the carrying amount is a
reasonable estimate of fair value. For all other debt, the fair market value
of the 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.
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, 1994 and 1993 and the related
consolidated statements of income, retained earnings and cash flows for each
of the three years in the period ended December 31, 1994. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of the Company
as of December 31, 1994 and 1993, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting
principles.
Boston, Massachusetts /s/ COOPERS & LYBRAND L.L.P.
February 27, 1995
Shareholder Information
New England Electric System
common shares
1994 1993
---------------------------------------------------
Price range Price range
----------------Dividend---------------Dividend
High Low declared High Low declared
-------------- --------------- ---------------
First quarter $39 $35-1/8 $.56 $42-1/4 $36-7/8 $.54
Second quarter $37-5/8$31-1/2 $.57-1/2$42-7/8 $39-3/8 $.56
Third quarter $34 $28-7/8 $.57-1/2$43-3/8 $40-3/4 $.56
Fourth quarter $32 7/8$29 1/2 $.57 1/2$42 $37 $.56
The total number of shareholders at December 31, 1994 was 54,593.
Selected quarterly financial information (unaudited)
(thousands of dollars) 1st quarter 2nd quarter 3rd quarter4th quarter*
----------- ---------- ----------------------
1994
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
1993
Operating revenue $579,490 $518,136 $576,644 $559,708
Operating income $ 80,711 $ 46,046 $ 82,498 $ 93,688
Net income $ 53,586 $19,146 $ 55,531 $ 61,960
Net income per average share$ .82$ .30 $ .85 $ .96
<FN>
*See Notes A-2 and E-3 for discussion of items that increased 1993 fourth quarter
earnings.
</FN>
Shareholder services
Shareholders may direct questions or acquire additional information about
shareholder records, quarterly dividend payments, or address changes by
contacting a shareholder services representative. The following services are
available to shareholders who have shares registered in their own name: direct
deposit of dividends, automatic investments, dividend reinvestment, and
safekeeping of certificated shares.
New England Electric System
Shareholder Services Department
Post Office Box 770
Westborough, Massachusetts 01581-0770
Toll-Free Number: 1-800-466-7215
Local Number: 508-389-2699
Dividends on common shares
Dividends are generally payable on the first business day of January, April,
July, and October.
Transfer agent
Questions about the transfer of certificate shares should be directed to:
Bank of Boston, Transfer Processing
Post Office Box 644, Mail Stop 45-01-05
Boston, Massachusetts 02102-0644
617-575-3120
Stock exchange listings
New York Stock Exchange
Boston Stock Exchange
Trading symbol
NES
Annual meeting notice
The annual meeting of New England Electric System will be held at Lowell
Memorial Auditorium, Lowell, Massachusetts, on April 25, 1995, at 10:30 a.m.
Form 10K and Statistical Report
Copies of the annual report on Form 10K to the Securities and Exchange
Commission and a Statistical Report for 1994 can be obtained, free of charge,
by writing to:
New England Electric System
Investor Relations
25 Research Drive
Westborough, Massachusetts 01582
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.
System Directors
As of December 31, 1994
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
Malcolm McLane
Of Counsel
Orr & Reno, P.A., Attorneys
Concord, New Hampshire
Audit Committee
Felix A. Mirando, Jr.
Private investor
Osterville, Massachusetts
Compensation 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
System Officers
As of December 31, 1994
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
System Subsidiaries
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
[LOGO OF RECYCLED PAPER APPEARS HERE]
New England Electric System
25 Research Drive
Westborough, Massachusetts 01582
Telephone 508-366-9011
Appendix of Graphic and Image Material Appearing in New England
Electric System 1994 Annual Report
1. The cover contains images of a canoe, a pen, a mortarboard,
and a lighthouse.
2. Foldout inside cover contains a map of New England and
indicates service areas and generating facilities.
3. The financial highlights page contains a graph comparing
1994 Return on Equity percentages for New England Electric
System 12.7%, the median of U.S. Electric Utilities 11.4%,
and the median of New England/New York Electric Utilities
11.04%.
4. Pictures of Joan T. Bok, Chairman of the Board, and John W.
Rowe, President and Chief Executive Officer, appear on the
pages of the letter to shareholders.
5. A picture of a mortarboard and a picture of Douglas Smith,
senior technical representative, appear in the Customer
Focus section.
6. A picture of a lighthouse and a picture of Paul Stasiuk,
senior analyst, appear in the Competitive Marketplace
section.
7. A picture of a canoe and a picture of Paula Hamel, senior
environmental engineer, appear in the Environment section.
8. A picture of a fountain pen and a picture of Masheed Hegi,
consulting engineer, appear in the New Rules section.
9. The following graphs appear in the Financial Review Section:
a. Earnings per average share: $2.77 in 1991, $2.85 in
1992, $2.93 in 1993, and $3.07 in 1994.
b. The annual rate of dividends declared per share: $2.08
in 1991, $2.16 in 1992, $2.24 in 1993, and $2.30 in
1994.
c. Percentage growth in kilowatt hour sales to ultimate
customers: negative 1.2% in 1991, 0.4% in 1992, 1.4%
in 1993, and 1.6% in 1994.
d. Customers served per employee: 227 in 1991, 236 in
1992, 259 in 1993, and 261 in 1994.
e. 1994 New England Electric System energy mix: 31% coal,
10% oil, 19% nuclear, 12% hydro, 6% renewables, and 16%
gas.
f. 1994 Distribution of Revenue: 24% Fuel, 9% Purchased
Power (excluding fuel), 11% Wages and Benefits, 18%
other O&M, 13% Depreciation and Amortization, 11%
Taxes, 5% Interest and Preferred Dividends, 9% Earnings
- Common Shares.
g. 1994 Revenue by Sales Classification: 43% residential,
32% small and medium commercial and industrial, 20%
large commercial and industrial with SED contracts, and
5% large commercial and industrial without SED
contracts.
h. Diverse Regulation - percent of 1994 electric revenue:
73% Federal Energy Regulatory Commission, 19%
Massachusetts, 7% Rhode Island, and 1% New Hampshire.