[COVER PHOTO]
1996 New England Electric System Annual Report
"Keeping the lights on,
earning our keep -
lasting values in a
changing world."
[NEES LOGO]
[PHOTO OF LINE DEPARTMENT EMPLOYEES]
About the cover
Line Department employees tend to our more than 22,000 miles of
distribution and transmission wires - the critical infrastructure
of NEES's electricity delivery business.
Clockwise, from left: Narragansett Electric's Jeff Crum, Jack
Hobson, Doug Paul, Marie Sullivan, and Luon Kim.
1996
NEES has consistently overcome challenges - from the oil
embargoes and inflation of the 1970's, to a severe recession in
the early 1990's - to provide competitive financial performance
for our shareholders. To continue this record, we are adapting
the NEES organization to a restructured industry. We agreed to
sell our generation business, and to shift our primary focus to
the energy delivery or regulated wires business. We also began
to pursue new opportunities in competitive businesses such as
energy services, transmission project management, and
telecommunications.
Financial Results
1996 1995 1994
-------- ------- -------
Earnings per average share $ 3.22 $ 3.15 $ 3.07
Dividends declared per share $ 2.360 $ 2.345 $ 2.285
Book value per share at year end $ 25.98 $ 25.13 $ 24.33
Market price per share at year end $34 7/8 $39 5/8 $32 1/8
Growth in kilowatt-hour (kWh)
deliveries to ultimate customers 1.7% 0.7% 1.6%
Cost per kWh sold to ultimate
customers (cents) 9.51 9.54 9.29
Return on Common Equity
[GRAPH]
New England Electric System 12.6%
Median of U.S. Electric Utilities 11.5%
Median of New England/New York
Electric Utilities 11.1%
New England Electric System (NEES) is a public utility holding
company headquartered in Westborough, Massachusetts. Its
subsidiaries are currently engaged in the generation,
transmission, distribution, and sale of electric energy, and
serve 1.3 million customers in Massachusetts, Rhode Island, and
New Hampshire. Other business activities include independent
transmission projects, telecommunications, and energy marketing
through AllEnergy Marketing Company, L.L.C., a joint venture with
Eastern Enterprises.
"The actions of our legislators and regulators
will provide substantial long-term benefits
to our customers while treating
NEES investors fairly."
[PICTURE OF UTILITY RESTRUCTURING ACT SIGNING]
Rhode Island makes history as Governor Lincoln Almond (seated)
signs the Utility Restructuring Act. Left to right: Robert
McCabe, president of Narragansett Electric; John Harwood, Speaker
of the House; David Gulvin of Eastern Utilities; Senator Paul
Tavares; Senator William Irons; NEES CEO John Rowe; and House
Majority Leader George Caruolo.
To Our Fellow Shareholders
Changes came, fast and furious, during 1996. But despite the
uneasiness brought on by the restructuring of New England's
electricity industry, NEES employees kept their focus where it
belongs on continuing the outstanding financial record that
investors in NEES have come to expect. We did this by providing
better service at lower cost.
We thank these hard working people for bringing NEES its
eighth consecutive year of solid financial performance. Earnings
per share were $3.22, compared with $3.15 in the previous year.
Return on common equity was 12.6 percent, placing us in the top
third of the nation s electric utilities. We are the only utility
to be in the top third of the New England-New York region in each
of the last eight years, and are pleased that the stock market
has recognized this superior performance, generally with the
highest share-price-to-book ratio in the region.
Competition
As you know, we face growing pressures to modify utility
franchises with new, more competitive structures. These
pressures are particularly powerful in New England where the cost
of electricity has exceeded the national average for many years.
NEES's costs are lower than those of its neighbors, but we are
not immune to these pressures. We are focusing on obtaining fair
treatment for utilities and their shareholders, rather than
attempting to delay trends that we consider inescapable or to
oppose public policies we perceive to be sound.
In 1996, our efforts to make public policy work for our
investors yielded substantial success. In August, Rhode Island
adopted the first detailed, definitive agenda for bringing the
benefits of competition and customer choice to all consumers
while compensating utility shareholders for the harm done to
their existing generating commitments. In September, we achieved
a settlement agreement in Massachusetts with the Attorney
General, Division of Energy Resources, and a variety of other
interests on a similar plan which the Department of Public
Utilities has now approved.
These breakthroughs are described in more detail on pages
6-8. Their principal features include the opening of our
transmission and distribution systems to retail competition in
1998, rate reductions for customers, and a transition charge to
compensate NEES for investments in generation that cannot be
recovered in the new marketplace or otherwise mitigated. Similar
measures have now been adopted in California and Pennsylvania.
The actions of our legislators and regulators will provide
substantial long-term benefits to our customers while treating
our investors fairly. If we had been required to give our
competitors access to our wires without provision for recovering
past investments, large portions of our generating commitments
would have become unrecoverable, or "stranded," depriving you of
the capital you have invested. These stranded investment issues
must be addressed in each state that chooses a competitive model.
We are grateful that two of our states have addressed these
issues so squarely and we are working to resolve them in New
Hampshire as well.
[PHOTO OF JOHN W. ROWE APPEARS HERE]
John W. Rowe, President and Chief Executive Officer
Restructuring
Adapting to a revolution is never easy or painless. Competition
and guaranteed rate reductions will reduce our revenues in 1998
and require even more substantial cost reductions than we have
previously attained. More fundamentally, in exchange for
stranded cost recovery, NEES has agreed to sell all of its fossil
and hydroelectric power plants and to seek buyers for its nuclear
and purchased power contracts.
Selling our generation is a bold response to new realities,
but is also a major concession. While NEES achieved its present
form in 1947, our roots in generation go back to 1907 when our
corporate predecessors developed hydroelectric generation on the
Connecticut River. So, parting with our power plants is as
emotionally unsettling as selling the family home. We are
compelled to decrease the size of the System. Many of our most
valuable employees will leave to take jobs with the new owners,
and some will need to seek employment elsewhere.
Nevertheless, this tough decision to divest our generation
business was necessary to protect the value of your investment.
By agreeing to divest, we secured a broad base of support from
customers, regulators, and legislative leaders for the recovery
of stranded costs. Further, we will avoid volatile returns and
possible losses from the generating business over the next
several years, a scenario that is inconsistent with the stable
returns that most investors seek from electric utilities.
As the generation sale process goes forward, we are working
with our labor unions and employees to implement the
organizational changes necessary, and to determine the benefits
to be paid to employees who lose their positions. We are
confident that, whether for a NEES company or for the new owners
of our generating business, NEES people will succeed at meeting
the new challenges of the industry.
[PHOTO OF JOAN T. BOK APPEARS HERE]
Joan T. Bok, Chairman of the Board
Vision
Once the divestiture is complete, a new vision arises for NEES -
to become the region's most profitable, most successful
electricity delivery company. We have the know-how, the
infrastructure, and the skilled people to excel at that business,
and we expect substantial opportunities to expand our electricity
delivery system in coming years. The cash from our generation
sale will give us new capabilities in that regard.
We are seizing new opportunities in the energy industry
through a joint venture with Eastern Enterprises, the parent
company of the largest gas company in Massachusetts. This joint
venture, AllEnergy Marketing Company, L.L.C., positions us to be
a successful marketer of natural gas, electricity, propane, oil,
and energy related services. AllEnergy has a superb management
and sales team, and NEES plans to contribute up to $50 million
over a five-year period to give it the maximum chance of success.
Director
In July 1996, the NEES board of directors elected a new member,
William M. Bulger. Mr. Bulger is president of the University of
Massachusetts, and had served as Massachusetts Senate president
for 18 years. We are delighted that someone of Mr. Bulger's
intellectual force and breadth of experience has joined our
board, and are confident that he will make a substantial
contribution.
Commitment
The year 1996 was clearly one of major change and difficult
decisions for NEES. But the underpinning of NEES's success
remained - and will remain - an unyielding commitment to
shareholder value. This commitment permeates our organization,
from the board room, to the executive suite, to the locker rooms
of our crews. It is founded on employee self-interest and shared
success. From 12 to 46 percent of each employee's total
compensation (depending on position) will hinge on NEES meeting
annual targets for earnings and customer costs. We are one of
the few U.S. electric utilities to have agreements with labor
unions that base part of compensation on the company's financial
performance for shareholders. Through various investment
programs, our employees collectively are NEES's largest
shareholder.
We thank you for your confidence in NEES and the employees of
our companies, a few of whom are highlighted on the following
pages. The focused efforts and commitment of this kind of people
will continue to make NEES the right utility investment choice.
We also thank you for your investment in our company. We
will strive to make 1997 another successful year, and to be ready
for retail competition when it comes in 1998.
s/John W. Rowe
John W. Rowe
President and Chief Executive Officer
s/Joan T. Bok
Joan T. Bok
Chairman of the Board
February 28, 1997
Making public policy work for our company
NEES leads New England's electric utilities in shaping the
restructuring of the electricity industry. This leadership
derives from our position as New England's lowest-cost major
electricity provider, our tradition of productive working
relationships with policy makers, and our absolute commitment to
shareholder value.
"The accomplishments of 1996
greatly reduce the uncertainty associated
with industry restructuring."
[PHOTO OF PAM VIAPIANO, JOSE ROTGER, PAIGE GRAENING, AND TERRY
SCHWENNESEN]
Responding to new rules that promote competition among power
suppliers are legal and rates experts, left to right: Pam
Viapiano, Jose Rotger, Paige Graening, and Terry Schwennesen.
Our top priority in negotiations with state legislators,
regulators, and various stakeholders was to obtain rules for
industry restructuring that will allow us to recover our stranded
costs. This is critical, because providing competitors access to
our transmission and distribution systems threatens to reduce the
value of our generation and purchased power contracts by as much
as $4.5 billion. While more work remains to be done, we have
succeeded in establishing a framework for recovering those
investments.
Legislation
Rhode Island's Utility Restructuring Act of 1996 was the first
legislation enacted in the nation to establish precise ground
rules and timetables for competition in retail electricity
markets. The statute phases in choice of electricity supplier
for Rhode Island customers during a 12-month period beginning in
July 1997. It set a precedent for treating utilities fairly by
establishing a transition charge that enables recovery of the
above-market sunk costs of our plants and other obligations. The
transition charge will be set at 2.8 cents per kilowatt-hour for
the first three years, but declines to approximately 0.7 cents
per kilowatt-hour in 12.5 years. Under the statute, the
transition charge will be adjusted to reflect the result of the
sale of our generation business.
We are grateful to the officials of Rhode Island for
reconciling fair treatment of shareholders with real savings and
real choices for customers.
[PHOTO OF LARRY REILLY APPEARS HERE]
Larry Reilly, President of Massachusetts Electric
Settlement
In September, we were the first electric utility in Massachusetts
to reach agreement with the state's Attorney General and Division
of Energy Resources on a plan called "Consumers First." The plan
would offer Massachusetts customers a choice of electricity
suppliers beginning in 1998 and allow utilities to recover
stranded costs through a charge similar to that in the Rhode
Island statute. Under the agreement, the NEES companies must
divest ownership of our power plants to another company or
companies. The market value of our generation fleet, as
determined by the divestiture, will be deducted from the amount
of stranded investment we can recover, reducing the transition
charge paid by customers.
"Our people and our power plants are
the best in New England, and will be a major force in
the region's energy market as it enters the next century."
[PHOTO OF GENERATOR OVERHAUL]
Working on a generator overhaul at our Bellows Falls hydro
station in Vermont are, left to right: Tim Nelson, Dennis Harty,
and Mike Welch.
Recently, the Massachusetts Department of Public Utilities
(DPU) approved our Consumers First settlement. In addition, it
issued final rules on industry restructuring and a detailed
proposal for enabling legislation. These rules are consistent
with the basic principles contained in Consumers First and
reaffirm the state's commitment to stranded cost recovery.
To effectuate the Rhode Island statute and Massachusetts
settlement, we have filed with the FERC to terminate the
wholesale power contracts between New England Power Company and
Massachusetts Electric, Nantucket Electric, and Narragansett
Electric. FERC Order No. 888, issued in April 1996, opened
wholesale power sales to competition and provided for full
recovery of stranded costs from customers.
In late February 1997, the New Hampshire Public Utilities
Commission (NHPUC) endorsed the principle of full stranded cost
recovery for utilities such as our subsidiary Granite State
Electric whose rates are below regional averages. However, the
NHPUC indicated that the calculation of stranded costs to be
recovered would be less than that proposed by Granite State. The
NHPUC indicated that its decision would not result in savings for
Granite State's customers. Earlier, Granite State had reached an
interim settlement agreement with several customers and other
parties that would provide a guaranteed rate reduction, initial
access charges, and other terms mirroring our Massachusetts
settlement. The New Hampshire interim settlement is pending
before the NHPUC.
[PHOTO OF LARRY BAILEY APPEARS HERE]
Larry Bailey, Director of Generation Operations
Work remains to be done in obtaining final approvals for our
plan of action, putting the industry rules into effect, and
successfully completing the divestiture of our generation
business. Legislatures or regulators may yet take a detrimental
course. However, the accomplishments of 1996 greatly reduce the
uncertainty associated with industry restructuring.
Focusing on success
Our plans for the future are to focus on the regulated
electricity delivery (or "wires") business, to expand it when and
where possible, and to make targeted investments in unregulated
businesses where we believe we can increase shareholder value.
[PHOTO OF MARILYN FLINT-JACQUES APPEARS HERE]
Marilyn Flint-Jacques, Customer Service Operations Manager
Infrastructure
Our wires infrastructure includes more than 20,000 miles of
distribution lines and 2,400 miles of transmission lines, serving
more than 1.3 million customers in a 4,700 square-mile area of
Massachusetts, Rhode Island, and New Hampshire. While those
customers will look to the competitive marketplace for their
electricity supplier, they will continue to rely on the local
distribution company to deliver that supply to their homes and
businesses and to do so with high reliability.
We believe that the pressures of the new era, including new
performance-based rate structures, will compel the consolidation
of wires companies. Indeed, this could parallel the era of rapid
consolidation through which our present System was built. As we
go forward, we will be opportunistic in merging with or acquiring
companies that allow us to expand our distribution infrastructure
and customer base.
Maintaining and improving our network of power lines and
related equipment will take on increasing importance in coming
years as customers' requirements continue to increase. Both the
Rhode Island statute and the Massachusetts settlement allow our
distribution companies the opportunity to earn fair returns while
providing high-quality customer service. We will draw on
existing strengths to deliver that service - reliable
transmission and distribution systems; highly skilled workers to
build, maintain, dispatch, and fix those systems; information and
communication technologies to support the business; and a
customer service strategy that keeps our people in direct contact
with customers.
"World class customer service requires
a round-the-clock, state-of-the-art facility.
In 1996, we made that facility a reality."
[PHOTO OF SERVICE REPRESENTATIVES]
150 highly-trained service representatives are a critical link to
customers, both in day-to-day transactions and in
storm-related emergencies. Left to right: Mary Jane Powers,
Steven Soucy, Lee Anne Swanson, and Michael Rossacci.
Service
To better meet the needs of customers in the coming years, we
opened a new, state-of-the-art Customer Service and Operations
Center to take calls and serve customers seven days a week, 24
hours per day. This Northborough, Mass. facility consolidates
the customer service operations of seven Massachusetts locations.
Extensive training of employees, round-the-clock availability,
and sophisticated software allow us to answer customer questions
more easily and quickly, and to handle more than 1.5 million
calls per year. The facility also serves as our new control
center for coordinating repair work to lines and related
equipment during major emergencies. During back-to-back
snowstorms in December 1996, the staff handled more than 70,000
calls and coordinated the efforts of more than 500 line crews,
some from as far away as Canada and Pennsylvania.
Because the center was purposely built to meet needs greater
than our own, it will support our growth strategy. The NEES
companies were leaders in developing billing systems for retail
competition pilot programs, and are marketing our center's
customer and billing services to other energy companies.
[PHOTO OF JEFF DONAHUE APPEARS HERE]
Jeff Donahue, President, NEERI
Transmission
In the area of electricity transmission, we will seek competitive
investment opportunities, within and outside the United States,
that are emerging as utilities around the world respond to
privatization initiatives. Transmission development projects
will be pursued by our subsidiary New England Electric Resources,
Inc. (NEERI). Where appropriate, NEERI will team with its
strategic partner, ABB Power Systems, a global leader in
transmission equipment.
NEERI's strong experience and partnership with ABB will make
it a leading contender for large transmission development
projects. Our extensive experience includes the high voltage
direct current interconnection with Hydro-Quebec that delivers
hydroelectricity from James Bay in Canada to New England, and the
26-mile-long submarine cable that in 1996 connected Nantucket
Island to our transmission grid on the mainland. Both were
completed on time and under budget. The Nantucket cable allows
us to better serve the island, which joined our System in 1996,
and also includes a fiber installation that will allow enhanced
telecommunications service.
In December, we proposed to build, own, and operate a
600-megawatt high voltage direct current submarine cable
transmission connection between Connecticut and Long Island,
which would introduce competitively attractive sources of power
to Long Island.
"Our expertise in high voltage direct current
transmission positions us for opportunities
on a global scale."
Telecommunications
We established a new subsidiary, NEES Communications, Inc. (NEES
Com), in August 1996 to allow the NEES companies to capture a
portion of the estimated $300 billion per year global
telecommunications industry. This subsidiary, which is an exempt
telecommunications company with a license from the Federal
Communications Commission, will seek to create value for both
customers and shareholders. It will focus on the fiber optics,
cable, and personal communications sectors of the
telecommunications industry. By year-end 1996, three fiber optic
projects, which will over time yield more than $2 million in
customer savings, had been completed.
[PHOTO OF LAYING SUBMARINE CABLE]
In 1996, a NEES company completed the 26-mile-long submarine
cable connecting Nantucket Island to the mainland. It is the
longest underwater power cable in the Northeast.
"AllEnergy will compete with a full range of
fuels and services to help customers
get more value for their
energy dollars."
[PHOTO OF ALLENERGY TEAM]
The AllEnergy team's significant experience in electricity,
natural gas, and other energy products and services is coupled
with strong sales and marketing capabilities. The team includes,
left to right: Bill Heil, Mary Smith, Deborah Chin, and John
Dickson.
Energy marketing
We joined with Eastern Enterprises, the parent company of Boston
Gas, the largest natural gas distributor in New England, to form
AllEnergy Marketing Company, L.L.C. in 1996. This venture
provides energy commodities, products, and services to customers
in the competitive market in New England and New York. In
December, AllEnergy announced the acquisition of Texas Liquids
Ltd, Inc. of New Jersey, adding propane and other petroleum
products to AllEnergy's menu of offerings.
The strength of this venture is its ability to meet the
unique, evolving energy needs of customers within the region by
offering all energy commodities - electricity, gas, propane, and
oil - as well as value-added services such as energy management
and power supply consulting. It was a successful participant in
retail competition pilot programs in New Hampshire and
Massachusetts during 1996.
Moving forward
As competition approached, NEES promptly recognized that the
value of NEES shareholders' investments could be threatened by
stranded costs. We acted decisively to insure fair treatment for
our shareholders. We made significant progress in this area in
1996 and are further along than most utilities in putting the
stranded cost recovery issue behind us.
Now, we must consolidate these accomplishments into real
revenue streams, and strengthen our wires and other businesses.
Another new chapter is opening, in which we will strive to grow
both our existing and new businesses and to continue delivering
superior utility returns.
[PHOTO OF MARCY REED APPEARS HERE]
Marcy Reed, Chief Financial Officer, AllEnergy
Financial Review
Industry Restructuring
On October 1, 1996, the New England Electric System (NEES)
companies announced their intention to divest their generating
business. The decision to divest the generating business was due
to a combination of factors, discussed below, relating to the
restructuring of the electric utility industry.
For the past several years, the electric utility business has
been subjected to rapidly increasing competitive pressures
stemming from a number of trends, including the presence of
surplus generating capacity, a disparity in electric rates among
regions of the country, improvements in generation efficiency,
increasing demand for customer choice, and new regulations and
legislation intended to foster competition.
In the recent past, this competition was most prominent in
the bulk power market, in which nonutility generators have
significantly increased their market share. Despite increased
competition in the bulk power market, competition in the retail
market has been limited as electric utilities have maintained
exclusive franchises for the retail sale of electricity in
specified service territories.
In states across the country, including Massachusetts, Rhode
Island, and New Hampshire, there have been proposals to allow
retail customers to choose their electricity supplier, with
incumbent utilities required to deliver that electricity over
their transmission and distribution systems (also known as
"retail wheeling"). When electricity customers are allowed to
choose their electricity supplier, utilities across the country
will face the risk that market prices may not be sufficient to
recover the costs of the commitments incurred to supply customers
under a regulated structure. The amounts by which costs exceed
market prices are commonly referred to as "stranded costs."
[GRAPH APPEARS HERE, EARNINGS PER AVERAGE SHARE]
NEES provides electric service to retail customers through
separate distribution subsidiaries operating in Massachusetts,
Rhode Island, and New Hampshire. Each of the distribution
subsidiaries purchases electricity on behalf of its customers
under wholesale all-requirements contracts with NEES's wholesale
generating subsidiary, New England Power Company (NEP). NEP also
provides all-requirements service to seven unaffiliated electric
utilities. NEP estimates that at December 31, 1996 its
above-market commitments on behalf of its all-requirements
customers are as much as $4.5 billion on a present-value basis
(before the application of the proceeds from the sale of its
generating business).
As described below, comprehensive legislation was enacted in
Rhode Island and a settlement agreement was reached in
Massachusetts which, when all regulatory approvals are in place,
would allow recovery of NEP's above-market commitments to retail
customers in those states, which make up 95 percent of NEP's
all-requirements sales. In return for that recovery, the NEES
companies have agreed to provide lower rates to customers, as
well as sell their generating business. Efforts are ongoing with
New Hampshire and unaffiliated customers to secure recovery of
the balance of NEP's above-market commitments.
Massachusetts Settlement Agreement
On February 26, 1997, the Massachusetts Department of Public
Utilities (MDPU) approved a settlement among NEP, its
Massachusetts distribution affiliates Massachusetts Electric
Company (Massachusetts Electric) and Nantucket Electric Company
(Nantucket), the Massachusetts Attorney General, the
Massachusetts Division of Energy Resources, and 12 other parties,
which provides for retail choice by Massachusetts customers and
the recovery of NEP's above-market commitments to serve those
customers.
The settlement provides for the commencement of retail choice
on January 1, 1998 (contingent on choice being available to the
customers of all Massachusetts investor-owned utilities).
Customers who do not choose an alternative supplier would receive
"standard offer" service, which would be priced to guarantee
customers at least a 10 percent savings in 1998 compared with
September 1996 bundled electricity prices.
In accordance with the settlement, NEP's wholesale contracts
with Massachusetts Electric and Nantucket have been amended to
allow for early termination of all-requirements service under
those contracts. The amendment provides that upon early
termination, Massachusetts Electric's and Nantucket's share of
the cost of NEP's above-market generation commitments will be
recovered through a transition access charge on distribution
facilities. Those commitments consist of (i) the above-market
portion of generating plant commitments, (ii) regulatory assets,
(iii) the above-market portion of purchased power contracts, and
(iv) the operating costs of nuclear plants that cannot be avoided
by shutting down the plants, including nuclear decommissioning
costs.
The above-market portion of costs associated with generating
plants and regulatory assets would be recovered over 12 years,
and would earn a return on equity of 9.4 percent. As the
transition access charge declines, NEP would earn mitigation
incentives that would supplement its return on equity. The
incentives are structured such that NEP believes, based on its
expectations of the level of mitigation it can achieve through
divestiture and other means, that it could earn a cumulative
return on equity on unrecovered costs of approximately 11
percent. The above-market component of purchased power contracts
and nuclear decommissioning costs would be recovered as incurred
over the life of those obligations, a period expected to extend
beyond 12 years. Initially, the transition access charge would
be set at 2.8 cents per kilowatt-hour (kWh) through December 31,
2000, and is expected to decline thereafter. The initial
transition access charge assumes that the generating plants have
no market value. To measure their actual market value, the NEES
companies agreed to sell their generating business. The net
proceeds from the sale will be used to reduce the transition
access charge.
[GRAPH APPEARS HERE, RETURN ON COMMON EQUITY]
The settlement also establishes performance-based rates for
Massachusetts Electric. Under the settlement, Massachusetts
Electric's nonfuel rates (and NEP's wholesale rates to
Massachusetts Electric) would be frozen at current levels until
the earlier of the commencement of retail choice or January 1,
2001. Upon commencement of retail choice, Massachusetts
Electric's distribution rates would be set at a level
approximately $45 million above the level embedded in its current
bundled rates, with such rates then frozen through the year 2000.
This increase reflects changes to the distribution cost of
service that include an $11 million increase in annual
depreciation expense, a $3 million annual contribution to a storm
fund, and increased amortization of unfunded deferred income
taxes of $1 million over six years. Massachusetts Electric's
return on equity would be subject to a floor of 6 percent and a
ceiling of 11 percent, effective upon commencement of retail
choice. Earnings over the ceiling would be shared equally
between customers and shareholders up to a maximum of 12.5
percent. This sharing results in an effective cap on
shareholder's return on equity of 11.75 percent. To the extent
that earnings fall below the floor, Massachusetts Electric would
be authorized to surcharge customers for the shortfall.
The settlement would also eliminate Massachusetts Electric's
purchased power cost adjustment (PPCA) mechanism as of July 31,
1996. This mechanism allows Massachusetts Electric to recover
purchased power rate changes from NEP and the effects of NEP's
seasonal rates. The settlement also stipulates that
Massachusetts Electric's net $18 million PPCA refund liability
balance at July 31, 1996 will be used to prefund a storm
contingency fund with $3 million, while the remainder will be
used to offset regulatory assets for hazardous waste costs.
The settlement is subject to approval by the Federal Energy
Regulatory Commission (FERC). The FERC accepted the filing to
become effective February 1, 1997, subject to refund, and ordered
hearings. In addition, various bills are pending before the
Massachusetts legislature relating to utility restructuring
issues that could affect the implementation of the settlement.
Rhode Island Legislation
In August 1996, the state of Rhode Island enacted pioneering
legislation that allows customers in that state the opportunity
to choose their electricity supplier. Under the Rhode Island
statute, state accounts, certain new customers, and the largest
manufacturing customers will be able to choose their supplier
beginning on July 1, 1997. These customers represent
approximately 2 percent of NEES's retail customer kWh sales. The
balance of Rhode Island customers will be able to choose their
supplier in 1998.
The statute calls for NEP's contract with NEES's Rhode Island
distribution subsidiary, The Narragansett Electric Company
(Narragansett), to be amended to permit a gradual, early
termination of all-requirements service under this contract. The
amendment provides that, in return, Narragansett's 22 percent
share of the cost of NEP's above-market generation commitments
would be recovered through a transition access charge on
Narragansett's distribution facilities. The specifics of the
transition access charge are similar to, and were a model for,
those contained in the Massachusetts settlement. One difference
is the statute's return on equity, which will be set at 11
percent as long as the NEES companies complete the divestiture or
other market valuation of their generating business; otherwise,
the return will be equal to 9.2 percent.
The statute also establishes performance-based rates for
distribution utilities, such as Narragansett. Under the statute,
Narragansett increased distribution rates by approximately $11
million in 1997, and is entitled to a similar increase in 1998.
In addition, in 1997, Narragansett's return on equity from
distribution operations will be subject to a floor of 6 percent
and a ceiling of 11 percent. Earnings over the ceiling will be
shared equally between customers and shareholders up to a maximum
return on equity from distribution operations of 12.5 percent.
This sharing results in an effective cap on shareholder's return
on equity of 11.75 percent. To the extent that earnings fall
below the floor, Narragansett will be authorized to surcharge
customers for the shortfall.
NEP and Narragansett filed with the FERC an amendment to
their all-requirements contract in order to implement the
statute. The FERC has set down the amendment, along with the
Massachusetts settlement, for hearing. Narragansett has
indicated it is willing to make certain changes to its plan in
Rhode Island to parallel provisions in the Massachusetts
settlement. Implementation of other aspects of the statute is
subject to approval of the Rhode Island Public Utilities
Commission (RIPUC).
[GRAPH APPEARS HERE, DIVIDENDS DECLARED PER SHARE ANNUAL RATE]
New Hampshire Proceeding and Settlement Agreement
On February 28, 1997, the New Hampshire Public Utilities
Commission (NHPUC) issued its plan to implement a New Hampshire
law calling for retail access by 1998. Under the plan, utilities
such as Granite State Electric Company (Granite State) whose
rates are below the regional average would be allowed full
recovery of stranded costs as calculated by the NHPUC. However,
the NHPUC indicated that its methodology and proposed timing of
recovery would yield both initial access charges and total
recovery less than that requested by Granite State although the
NHPUC indicated that its decision would not result in savings for
Granite State's customers.
Prior to the issuance of the NHPUC order, Granite State
reached an interim settlement with several customers and other
stakeholders that would set initial access charges at 2.8 cents
per kWh for two years, and in other respects would mirror the
Massachusetts settlement described previously. Stranded costs to
be recovered after the two-year initial period would be subject
to future regulatory determination. Unlike the NHPUC order, the
interim settlement agreement would provide all customers with a
rate reduction of approximately 10 percent. This interim
settlement is still pending before the NHPUC.
Federal Activity
In April 1996, the FERC issued Order No. 888 requiring utilities
that own transmission facilities to file open access tariffs to
make available transmission service to affiliates and
nonaffiliates at fair, nondiscriminatory rates. Order No. 888
also stated that public utilities will be allowed to seek
recovery of legitimate and verifiable stranded costs from
departing customers as a result of wholesale competition. The
FERC indicated that it will provide for the recovery of retail
stranded costs only if state regulators lack the legal authority
to address those costs at the time retail wheeling is required.
The FERC also stated that it would permit stranded cost recovery
under wholesale all-requirements contracts, such as the contracts
between NEP and its retail affiliates.
Because of the Massachusetts settlement and the Rhode Island
statute, NEP does not expect it will rely exclusively on Order
No. 888 to recover stranded costs from its affiliates in
Massachusetts and Rhode Island. NEP cannot predict at this time
whether an Order No. 888 filing will be necessary to fully
recover stranded costs from Granite State or from seven
unaffiliated wholesale customers should any of those customers
choose to terminate service under their contract with NEP.
Granite State and these seven unaffiliated customers are
responsible for approximately 3 percent and 2 percent of NEP's
sales, respectively.
In July 1996, NEP, on behalf of the NEES companies, filed a
transmission tariff with the FERC pursuant to Order No. 888. The
FERC accepted the filing, but ordered NEP to refile to conform
more closely with the FERC's requirements under Order No. 888.
Implementation of the tariff in mid-1996 did not have a
significant impact on NEP's revenues. On February 26, 1997, the
FERC announced Order No. 888-A, reaffirming the principles of
Order No. 888, including stranded cost recovery.
A number of proposals for legislation related to industry
restructuring have been brought forward for consideration by the
current Congress. The scope and aim of these vary widely;
however, the NEES companies and others will argue that state
settlements should be respected. NEES cannot predict what
federal legislation, if any, may be enacted.
Divestiture of Generation Business
Under the Massachusetts settlement and thus automatically under
the Rhode Island statute, the NEES companies must complete the
divestiture of their generating business within six months of the
later of the commencement of retail choice in Massachusetts or
the receipt of all necessary regulatory approvals. The NEES
companies are in the process of soliciting proposals for the
acquisition of their nonnuclear generating business with the
objective of reaching definitive purchase and sale agreements by
mid-1997. Closing would follow the receipt of regulatory
approvals, which are expected to take at least six to 12 months
following the execution of purchase and sale agreements. At
December 1996, nonnuclear net generating plant was approximately
$1.1 billion.
As part of the divestiture plan, NEP will endeavor to sell,
or otherwise transfer, its minority interest in four nuclear
power plants to nonaffiliates. NEP may retain responsibility for
decommissioning and related expenses, if necessary. To the
extent that NEP is unable to divest its nuclear generating
interests, the Massachusetts settlement provides for a sharing
between customers and shareholders of the revenues associated
with the nuclear interests and the costs not otherwise reflected
in the access charge, with 80 percent allocated to customers and
20 percent to shareholders. This sharing mechanism is not
included in the Rhode Island statute previously discussed. In
addition, New England Energy Incorporated (NEEI) is planning to
sell its oil and gas properties, the cost of which is supported
by NEP through fuel purchase contracts.
[GRAPH APPEARS HERE, BOOK VALUE PER SHARE AT YEAR END ($)]
Risk Factors
While substantial progress has been made in resolving the
uncertainty regarding the impact on shareholders from industry
restructuring, significant risks remain. These include, but are
not limited to (i) the potential that ultimately the
Massachusetts settlement and the Rhode Island statute will not be
implemented in the manner anticipated by NEES, (ii) the
possibility of state or federal legislation that would increase
the risks to shareholders above those contained in the
Massachusetts settlement and Rhode Island statute, and (iii) the
potential for adverse stranded cost recovery decisions involving
Granite State and NEP's unaffiliated customers.
Even if these risks do not materialize, the implementation of
the Massachusetts settlement and the Rhode Island statute will
negatively impact financial results for NEES starting in 1998.
The returns on equity permitted on NEES subsidiaries'
transmission and distribution operations (up to 11.75 percent)
and on the unrecovered commitments in the generating business
(generally 9.4 percent to 11 percent) are less than those
historically earned by NEES. In addition, starting in 1998,
earnings will be affected by the return on the reinvestment of
the proceeds from the sale of the generation business. Such
reinvestment return is likely, at least in the near term, to be
less than is currently earned by the generation business.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Financial Accounting Standards
No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), requires regulated entities, in appropriate
circumstances, to establish regulatory assets, and thereby defer
the income statement impact of certain costs expected to be
recovered in future rates. The NEES companies have recorded
approximately $550 million in regulatory assets in compliance
with FAS 71 of which approximately $75 million relate to the
transmission and distribution business.
Both the Massachusetts settlement and the Rhode Island
statute provide for full recovery of the costs of generating
assets and oil and gas related assets (including regulatory
assets) not recoverable from the proceeds of the divestiture of
NEP's generating business. The cost of these assets would be
recovered as part of a transition access charge imposed on all
distribution customers. After the proposed divestiture,
substantially all of NEP's business, including the recovery of
its stranded costs, would remain under cost-based rate
regulation. NEES believes the Massachusetts settlement and the
Rhode Island statute will enable the NEES distribution companies
operating in those states to recover through rates their specific
costs of providing ongoing distribution services. In addition,
FERC Order No. 888 enables transmission companies to recover
their specific costs of providing transmission service. NEES
believes these factors will allow its principal subsidiaries to
continue to apply FAS 71 and that no impairment of plant assets
will exist under Statement of Financial Accounting Standards No.
121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of (FAS 121). Any loss from the
divestiture of generating assets and oil and gas assets will be
recorded as a regulatory asset to be recovered through the
ongoing transition access charge.
Although NEES believes that its subsidiaries will continue to
meet the criteria for continued application of FAS 71, NEES
understands that members of the SEC staff have raised questions
concerning the continued applicability of FAS 71 to certain other
electric utilities facing restructuring. In addition, despite
the progress made to date in Massachusetts and Rhode Island, it
is possible that the final restructuring plans ultimately ordered
by regulatory bodies would not reflect full recovery of stranded
costs, including a fair return on those costs as they are being
recovered. In the event that future circumstances should cause
the application of FAS 71 to be discontinued, a noncash write-off
of previously established regulatory assets and liabilities
related to the affected operations would be required. In
addition, write-downs of plant assets under FAS 121 could be
required, including a write-off of any loss from the divestiture
of the generating business.
[GRAPH APPEARS HERE, 1996 DISTRIBUTION OF REVENUE(%)]
Overview of Financial Results
Earnings were $3.22 per share in 1996 compared with $3.15 and
$3.07 per share in 1995 and 1994, respectively. The return on
common equity was 12.6 percent in 1996, 12.8 percent in 1995, and
12.7 percent in 1994. The market price of NEES common shares was
$34 7/8 per share at the end of 1996 compared with $39 5/8 per
share and $32 1/8 per share at the end of 1995 and 1994,
respectively.
The increase in 1996 earnings reflects retail rate increases
and higher kWh sales as well as decreased purchased power costs.
These increases in income were partially offset by a decreased
allowance for funds used during construction (AFDC) and increased
property tax expense, both primarily due to the completion in the
second half of 1995 of the Manchester Street Station.
The increase in 1995 earnings reflects slightly higher kWh
sales to ultimate customers, decreased depreciation and
amortization expense, and decreased operation and maintenance
expenses, partially offset by higher purchased power and interest
expenses.
Operating Revenue
Operating revenue increased $79 million in 1996 and reflects
retail rate increases and sales growth, partially offset by
decreases in revenues under rate adjustment mechanisms.
Retail rate increases include a Massachusetts Electric $31
million base rate increase effective in October 1995, a
Narragansett $12 million base rate increase effective in December
1995, and a Granite State $1 million increase effective in
November 1995.
Rate adjustment mechanisms referred to above include the
distribution subsidiaries' PPCA mechanisms. The provisions of
the Massachusetts settlement would have caused the PPCA mechanism
for Massachusetts Electric to end, effective July 31, 1996.
However, since the Massachusetts settlement had not been approved
at the end of 1996, Massachusetts Electric accrued refund
provisions of $9 million related to assumed operation of the PPCA
provision during the last five months of 1996.
In 1996, kWh deliveries to ultimate customers increased 1.7
percent, while total kWh sales increased 1.3 percent. The
difference is the result of pilot programs in Massachusetts and
New Hampshire, whereby the NEES distribution companies delivered
power provided by other companies. The increase in kWh
deliveries reflects the effects of an improving economy and the
acquisition of Nantucket, partially offset by the effects of
milder weather in the last half of the year.
Operating revenue increased $29 million in 1995. This
increase reflected modest sales growth, increased fuel revenues,
the November 1994 expiration of a Massachusetts Electric
temporary rate decrease, and the October 1995 Massachusetts
Electric rate increase. These increases were partially offset by
a decrease in the amortization of unbilled revenues in 1995
compared with 1994.
Kwh sales to ultimate customers increased less than 1 percent
in 1995. This increase was primarily due to a return to more
normal weather in the fourth quarter of 1995, along with a warmer
summer in 1995, partially offset by lower kWh sales in the first
quarter of 1995 due to unusually mild weather.
The distribution companies have received approval from their
respective regulatory agencies to recover demand-side management
(DSM) program expenditures in rates on a current basis. These
expenditures were $59 million, $64 million, and $70 million in
1996, 1995, and 1994, respectively. Since 1990, the distribution
companies have been allowed to earn incentives based on the
results of their DSM programs and have recorded before-tax
incentives of $6.0 million, $5.7 million, and $7.7 million in
1996, 1995, and 1994, respectively.
Operating Expenses
Total operating expenses increased $54 million in 1996 compared
with 1995. This increase reflects increased fuel costs and
increased taxes. These increases were partially offset by
decreased maintenance expense, lower purchased power costs, and
decreased depreciation and amortization expense.
[GRAPH APPEARS HERE, CUSTOMERS SERVED PER EMPLOYEE]
Fuel costs increased in 1996, primarily due to fixed pipeline
demand charges that, prior to the completion of the Manchester
Street Station, were being partially deferred for amortization
and recovery after the unit went into service in the second half
of 1995. The increase in fuel costs also reflects increased
generation as a result of growth in sales to ultimate customers
as well as generation supplied to other utilities.
In 1996 purchased power costs decreased, reflecting the
expiration of certain purchased power contracts. In addition,
purchased power costs in the first half of 1995 included NEP's
share of costs to repair steam generator tubes at the Maine
Yankee nuclear power plant in which NEP has a 20 percent
ownership interest.
Maintenance expense decreased in 1996, reflecting reduced
thermal and hydro generating plant overhaul activity, partially
offset by $13 million of costs to correct deficiencies at the
Millstone 3 nuclear unit, in which NEP has a 12 percent ownership
interest.
In the fourth quarter of 1996, Massachusetts Electric
incurred approximately $8 million of costs related to a severe
winter storm. The Massachusetts settlement provides for the
recovery of the costs associated with major storms; however, its
application to the 1996 storm is subject to clarification by the
MDPU. Because the Massachusetts settlement had not been approved
as of December 31, 1996, Massachusetts Electric deferred the 1996
storm costs based upon long-standing regulatory practice allowing
the recovery over five years of costs of major storms.
In 1996, depreciation and amortization expense decreased,
reflecting a decrease in oil and gas amortization expense as well
as the completion in mid-1995 of the amortization of a portion of
Seabrook 1 costs and Salem Harbor coal conversion costs. These
decreases were partially offset by increased depreciation of
other utility plant assets, including the Manchester Street
Station.
Taxes, other than income taxes, increased in 1996, primarily
as a result of increased property taxes on the Manchester Street
Station.
Total operating expenses increased $2 million in 1995
compared with 1994, reflecting increased purchased power and fuel
expenses. Purchased power expense increased, reflecting
overhauls and refueling shutdowns at partially-owned nuclear
power facilities, including NEP's share of costs to repair steam
generator tubes at the Maine Yankee nuclear power plant. The
increase in purchased power expense also includes the
amortization of previously deferred purchased power contract
termination costs.
Fuel costs, including the fuel portion of purchased power
expense, increased in 1995, reflecting increased short-term
purchases by NEP due to decreased nuclear generation and
decreased hydro production resulting from low water levels.
In accordance with NEP's 1995 rate agreement, other operation
expense in 1995 reflects the commencement of the amortization
over seven years, of approximately $19 million of previously
deferred costs associated with postretirement benefits other than
pensions (PBOP) and the recognition of currently incurred PBOP
costs.
NEP's 1995 rate agreement also provided for the recovery over
three years of $27 million of costs related to the replacement of
a turbine rotor at one of NEP's generating stations and of
charges described above associated with the dismantlement of a
retired generating facility.
Depreciation and amortization expense decreased in 1995 due
to reduced amortization of Seabrook 1 in accordance with NEP's
1995 rate agreement, which deferred recognition of $15 million of
such amortization from 1995 to 1996, the completion of the
amortization of the costs of certain coal conversion facilities
in the first half of 1995, and decreased oil and gas amortization
due to decreased production. Partially offsetting these
decreases were increased depreciation rates of approximately $8
million approved in NEP's 1995 rate agreement, increased charges
associated with the dismantlement of a retired generating
facility, and depreciation of new plant expenditures, including
the Manchester Street Station.
Allowance for Funds Used During Construction
The changes in AFDC in 1996 and 1995 are due to the Manchester
Street Station repowering project which began commercial
operation in the second half of 1995.
Investments in Nuclear Units
NEP owns minority interests in six nuclear generating units, two
of which, Yankee Atomic and Connecticut Yankee, have been shut
down permanently. Two others, Millstone 3 and Maine Yankee, are
currently shut down and have been placed on the Nuclear
Regulatory Commission's (NRC) "Watch List," signifying that their
safety performance exhibits sufficient weakness to warrant
increased NRC attention. Neither may restart without NRC
approval. At present, the Vermont Yankee and Seabrook 1 nuclear
generating units appear to be operating routinely without major
problems.
On October 9, 1996, the NRC issued letters to operators of
nuclear power plants requiring them to document that the plants
are operated and maintained within their design and licensing
bases, and that any deviations are reconciled in a timely manner.
The Seabrook 1, Maine Yankee, and Vermont Yankee nuclear power
plants responded to the NRC letters in February 1997.
Uncertainties regarding the future of nuclear generating
stations, particularly older units such as Maine Yankee and
Vermont Yankee, are increasing rapidly and could adversely affect
their service lives, availability, and costs. These
uncertainties stem from a combination of factors, including the
acceleration of competitive pressures in the power generation
industry and increased NRC scrutiny.
Connecticut Yankee
NEP has a 15 percent equity ownership interest in Connecticut
Yankee. As a result of an economic analysis, the Connecticut
Yankee board of directors voted in December 1996 to permanently
shut down and decommission the plant.
In December 1996, Connecticut Yankee filed with the FERC to
recover all of its approximately $246 million undepreciated
investment in the plant and other costs over the period extending
through June 2007, when the plant's NRC operating license would
have expired. In a 1993 decision, the FERC allowed Yankee Atomic
to recover its undepreciated investment in its permanently shut
down nuclear plant, in part on the grounds that owners should not
be discouraged from closing uneconomic plants. Several parties
have intervened in opposition to Connecticut Yankee's filing.
NEP believes that the FERC will allow NEP to recover from its
customers all costs that the FERC allows Connecticut Yankee to
recover from NEP.
NEP has recorded the estimated future payment obligation to
Connecticut Yankee of $114 million as a liability and as an
offsetting regulatory asset, reflecting NEP's expected future
rate recovery of such costs. The NRC has identified numerous
apparent violations of its regulations, which may result in the
assessment of civil penalties.
Millstone 3
In April 1996, the NRC ordered Millstone 3, which has experienced
numerous technical and nontechnical problems, to remain shut down
pending verification that the unit's operations are in accordance
with NRC regulations and the unit's operating license. Millstone
3 is operated by a subsidiary of Northeast Utilities (NU). NEP
is not an owner of Millstone 1 and 2 nuclear generating units,
which are also shut down under NRC orders.
A number of significant prerequisites must be fulfilled prior
to restart of Millstone 3, including certification by NU that the
unit adequately conforms to its design and licensing bases, an
independent verification of corrective action taken at the unit,
an NRC assessment concluding a culture change has occurred,
public hearings, and a vote of the NRC Commissioners. NU
announced in December 1996 that it expects Millstone 3 to be
ready for restart around the end of 1997, subject to review by
the NRC Commissioners. NEP cannot predict when Millstone 3 will
be allowed by the NRC to restart, but believes that the unit will
remain shut down for a very protracted period.
NEP incurred $10 million of actual costs in 1996 related to
corrective actions associated with the outage. NEP has also
accrued a liability of approximately $3 million for its share of
future corrective action costs. Additional costs may be
incurred. During the outage, NEP is also incurring approximately
$1.6 million per month in incremental replacement power costs,
which it has been recovering from customers through its fuel
clause.
Several criminal investigations related to Millstone 3 are
ongoing. The NRC has identified numerous apparent violations of
its regulations which may result in the assessment of civil
penalties. NEP and other minority owners of Millstone 3 are
assessing their legal rights with respect to NU's operation of
Millstone 3.
Maine Yankee
Over the past few years, the Maine Yankee nuclear generating
plant has experienced numerous technical and nontechnical
problems. In 1995, the plant had been shut down for much of the
year due to the discovery of cracks in its steam generator tubes.
The plant is currently shut down due to a cable routing problem.
In addition, due to leaking nuclear fuel rods, 68 fuel assemblies
will be replaced. As a result, Maine Yankee management does not
expect the unit to restart until at least summer of 1997.
In late 1995, allegations were made to the NRC that
inadequate analyses of the plant's emergency core cooling system
had been performed. As a result of the allegations, the NRC
limited the plant's operation to 90 percent of full capacity. In
September 1996, the NRC asked the Department of Justice (DOJ) to
review, for potential criminal violations, an NRC investigatory
report on the allegations. The DOJ is not limited in its
investigation to the matters covered in that report.
During 1996, the NRC conducted an independent safety
assessment (ISA) and identified a number of weaknesses,
deficiencies, and apparent violations which could result in
fines. Yankee Atomic performed professional services for Maine
Yankee associated with the matters being investigated. In
response to the ISA results, Maine Yankee has indicated that it
will spend more than $50 million in 1997 on operational
improvements. Additionally, in February 1997, Entergy
Corporation, an operator of five nuclear units, commenced
providing management services.
Under a confirmatory action letter issued by the NRC on
December 18, 1996, and supplemented on January 30, 1997, Maine
Yankee must fulfill certain commitments before its plant will be
allowed by the NRC staff to return to service. Because of
regulatory and other uncertainties faced by Maine Yankee, NEP
cannot predict whether or when Maine Yankee will return to
service.
During the outage, NEP is incurring approximately $1.8
million per month in incremental replacement power costs, which
it has been recovering from customers through its fuel clause.
Brayton Point
In October 1996, the Environmental Protection Agency (EPA)
announced it was beginning a process to determine whether to
modify or revoke NEP's water discharge permit for its Brayton
Point 1,576 megawatt power plant. This action came two years
before the permit expiration date. The EPA stated it took this
step in response to a request from the Rhode Island Department of
Environmental Management (RIDEM) that action be taken on the
Brayton Point permit prior to its 1998 renewal, based on concerns
raised in a final RIDEM report issued in October 1996. The
report asserted a statistical correlation between the decline in
the fish population in Mount Hope Bay and a change in operations
at Brayton Point that occurred in the mid-1980's.
In February 1997, NEP signed a memorandum of agreement
negotiated with the various federal and state environmental
agencies under which NEP will voluntarily operate under more
stringent conditions than under its existing permit. The
agreement is in lieu of any immediate action on the permit, but
will cover only the months of February and March 1997. During
this time, the parties will continue to work toward a longer-term
solution. NEP cannot predict at this time what permit changes
will be required or the impact on Brayton Point's operations and
economics. However, permit changes may substantially impact the
plant's capacity and ability to produce energy as well as require
significant capital expenditures of tens of millions of dollars
to construct equipment to address the concerns raised by the
environmental agencies.
Hazardous Waste
The electric utility industry typically utilizes and/or generates
in its operations a range of potentially hazardous products and
by-products. 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 40 such manufactured gas locations, including nine of the 23
locations for which NEES companies have been identified by either
federal or state environmental regulatory agencies as potentially
responsible parties, mostly located in Massachusetts. In 1993,
the MDPU approved a settlement agreement that provides for rate
recovery of remediation costs of former manufactured gas sites
and certain other hazardous waste sites in Massachusetts. A more
detailed discussion of this settlement agreement and of potential
hazardous waste liabilities is contained in Note D-3 of the Notes
to the Financial Statements. Predicting the potential costs to
investigate and remediate hazardous waste sites continues to be
difficult. At December 31, 1996, NEES had total reserves of $48
million and a related regulatory asset of $18 million. NEES
believes that hazardous waste liabilities for all sites of which
it is aware, and which are not covered by a rate agreement, are
not material to its financial position.
Electric and Magnetic Fields (EMF)
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. In
October 1996, the National Research Council of the National
Academy of Sciences released a report stating no conclusive and
consistent evidence demonstrates that exposures to residential
EMF produce adverse health effects. 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.
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.
Liquidity and Capital Resources
Capital requirements for 1996 and projections for 1997 are shown
below:
Year ended December 31 (millions of dollars) 1996 1997
---- ----
Cash expenditures for utility plant $235 $230
Oil and gas exploration and development 20 15
---- ----
Total capital expenditures 255 245
Maturing debt and prepayment requirements 24 80
---- ----
Total capital requirements $279 $325
Cash from utility operations after
payment of dividends $242 $250
Cash from oil and gas operations 29 35
---- ----
Total cash from operations
after the payment of dividends $271 $285
---- ----
The long-term financing activities of the NEES subsidiaries
for 1996 and the projected long-term financings for 1997 are
summarized as follows:
1996 Actual 1997 Projected
(millions of dollars) Issues Retirements Issues Retirements
------ ----------- ------ -----------
NEP $48 $ 58 $ - $ 3
Massachusetts Electric 20 - 50 30
Narragansett 2 2 40 33
Granite State - 1 5 -
Nantucket 28 - - 1
Hydro-Transmission companies - 12 - 11
Narragansett Energy
Resources Company - 1 - 2
NEEI - 33 - 20
------ ---------- ------ ----------
$98 $107 $95 $100
Interest rates on the long-term debt issued in 1996 shown
above range from 4.10 percent to 7.24 percent.
Net cash from operating activities provided all of the funds
necessary for oil and gas expenditures in 1996 and is projected
to provide all of the funds necessary in 1997. NEEI's 1996 oil
and gas exploration and development costs included $7 million of
capitalized interest costs.
At December 31, 1996, NEES and its consolidated subsidiaries
had lines of credit and standby bond purchase facilities with
banks totaling $706 million. These lines and facilities were
used at December 31, 1996 for liquidity support for $4 million of
short-term borrowings, $141 million of commercial paper
borrowings, and $372 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 (dollar amounts expressed in millions, except per share
data)
1996 1995 1994 1993 1992
------- -------- ------- ------- -------
Operating revenue:
Electric sales (excluding
fuel cost recovery) $ 1,531 $ 1,521 $ 1,518 $ 1,488 $ 1,424
Fuel cost recovery 662 600 568 582 597
Other utility revenue 125 121 117 117 118
Oil and gas sales 33 30 40 47 43
------- ------- ------- ------- -------
Total operating revenue $ 2,351 $ 2,272 $ 2,243 $ 2,234 $ 2,182
Net income $ 209 $ 205 $ 199 $ 190 $ 185
Average common shares
(000's) 64,924 64,944 64,970 64,970 64,970
Per share data:
Net income $ 3.22 $ 3.15 $ 3.07 $ 2.93 $ 2.85
Dividends declared $ 2.360 $ 2.345 $ 2.285 $ 2.22 $ 2.14
Return on average
common equity 12.6% 12.8% 12.7% 12.6% 12.6%
Total assets $ 5,223 $ 5,191 $ 5,085 $ 4,796 $ 4,585
Capitalization:
Common share equity $ 1,685 $ 1,632 $ 1,581 $ 1,530 $ 1,487
Minority interests 46 49 55 56 61
Cumulative preferred stock 126 147 147 147 162
Long-term debt 1,615 1,675 1,520 1,512 1,533
------- ------- ------- ------- -------
Total capitalization $ 3,472 $ 3,503 $ 3,303 $ 3,245 $ 3,243
Deliveries to ultimate
customers (millions
of kWh) 21,674 21,311 21,155 20,832 20,554
Cost per kWh sold to ultimate
customers (cents) 9.51 9.54 9.29 9.50 9.43
System maximum
demand (MW) 4,091 4,381 4,385 4,081 3,964
Electric capability
(net MW)-year end 5,276 5,482 5,533 5,362 5,479
Number of employees 4,787 4,832 4,990 4,969 5,415
Number of ultimate customers
(in thousands) 1,333 1,314 1,300 1,288 1,277
------- ------- ------- ------- -------
New England Electric System and Subsidiaries
Statements of Consolidated Income
Year Ended December 31 (thousands of dollars, except per share data)
1996 1995 1994
---------- ---------- ----------
Operating revenue $2,350,698 $2,271,712 $2,243,029
Operating expenses:
Fuel for generation 334,994 237,498 220,956
Purchased electric energy 509,400 548,370 514,143
Other operation 501,090 500,721 494,741
Maintenance 127,785 136,058 161,473
Depreciation and amortization 246,379 264,666 301,123
Taxes, other than income taxes 143,733 132,631 125,840
Income taxes 139,199 128,340 128,257
---------- ---------- ----------
Total operating expenses 2,002,580 1,948,284 1,946,533
---------- ---------- ----------
Operating income 348,118 323,428 296,496
Other income:
Allowance for equity funds used
during construction 7,852 10,169
Equity in income of generating
companies 10,334 10,552 9,758
Other income (expense), net (8,166) (6,306) (3,856)
---------- ---------- ----------
Operating and other income 350,286 335,526 312,567
---------- ---------- ----------
Interest:
Interest on long-term debt 110,479 108,365 93,500
Other interest 19,527 19,826 11,298
Allowance for borrowed funds
used during construction (2,246) (14,016) (7,793)
---------- ---------- ----------
Total interest 127,760 114,175 97,005
---------- ---------- ----------
Income after interest 222,526 221,351 215,562
Preferred dividends and net gain
on reacquisition of preferred
stock of subsidiaries 6,463 8,690 8,697
Minority interests 7,127 7,904 7,439
----------- ----------- -----------
Net income $ 208,936 $ 204,757 $ 199,426
----------- ----------- -----------
Average common shares 64,924,468 64,944,187 64,969,652
Per share data:
Net income $ 3.22 $ 3.15 $ 3.07
Dividends declared $ 2.360 $ 2.345 $ 2.285
----------- ----------- -----------
Statements of Consolidated Retained Earnings
Year Ended December 31 (thousands of dollars)
1996 1995 1994
--------- --------- ---------
Retained earnings at beginning of year $ 831,529 $ 779,045 $ 728,075
Net income 208,936 204,757 199,426
Dividends declared on common shares (153,173) (152,273) (148,456)
--------- --------- ---------
Retained earnings at end of year $ 887,292 $ 831,529 $ 779,045
--------- --------- ---------
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)
1996 1995
---------- ----------
Assets
Utility plant, at original cost $5,692,956 $5,480,001
Less accumulated provisions for depreciation
and amortization 1,853,003 1,710,991
---------- ----------
3,839,953 3,769,010
Net investment in Seabrook 1 under
rate settlement (Note A) 15,210
Construction work in progress 56,652 71,682
---------- ----------
Net utility plant 3,896,605 3,855,902
---------- ----------
Oil and gas properties, at full cost (Note A) 1,286,661 1,266,290
Less accumulated provision for amortization 1,081,940 1,032,777
---------- ----------
Net oil and gas properties 204,721 233,513
---------- ----------
Investments:
Nuclear power companies, at equity (Note D) 47,902 47,056
Other subsidiaries, at equity 40,124 40,259
Other investments 96,399 87,992
---------- ----------
Total investments 184,425 175,307
---------- ----------
Current assets:
Cash 8,477 7,064
Accounts receivable, less reserves
of $18,702 and $18,308 262,103 284,033
Unbilled revenues 59,093 66,300
Fuel, materials, and supplies, at average cost 74,111 73,724
Prepaid and other current assets 85,096 77,673
---------- ----------
Total current assets 488,880 508,794
---------- ----------
Deferred charges and other assets (Note B) 448,620 417,360
---------- ----------
$5,223,251 $5,190,876
---------- ----------
Capitalization and liabilities
Capitalization (see accompanying statements):
Common share equity $1,685,417 $1,631,779
Minority interests in consolidated
subsidiaries 46,293 48,912
Cumulative preferred stock of subsidiaries 126,166 147,016
Long-term debt 1,614,578 1,675,170
---------- ----------
Total capitalization 3,472,454 3,502,877
---------- ----------
Current liabilities:
Long-term debt due within one year 79,705 23,960
Short-term debt 145,050 203,250
Accounts payable 148,592 157,486
Accrued taxes 14,911 15,894
Accrued interest 27,494 27,455
Dividends payable 37,276 38,683
Other current liabilities (Note F) 109,582 73,104
---------- ----------
Total current liabilities 562,610 539,832
---------- ----------
Deferred federal and state income taxes 750,929 780,451
Unamortized investment tax credits 91,936 93,408
Other reserves and deferred credits 345,322 274,308
Commitments and contingencies (Note D) ---------- ----------
$5,223,251 $5,190,876
---------- ----------
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)
1996 1995 1994
-------- -------- --------
Operating activities
Net income $208,936 $204,757 $199,426
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation and amortization 250,508 270,292 305,908
Deferred income taxes and
investment tax credits, net (30,328) 24,056 41,741
Allowance for funds used during
construction (2,246) (21,868) (17,962)
Amortization of unbilled revenues (8,209) (38,458)
Minority interests 7,127 7,904 7,439
Decrease (increase) in accounts
receivable, net and unbilled revenues 30,770 1,194 (33,107)
Decrease (increase) in fuel,
materials, and supplies 126 20,707 (20,117)
Decrease (increase) in prepaid
and other current assets (7,209) (955) (7,714)
Increase (decrease) in accounts payable (9,568) (11,451) 40,595
Increase (decrease) in other current
liabilities 33,999 (4,784) (25,676)
Other, net 40,455 (11,790) (34,109)
-------- -------- --------
Net cash provided by operating
activities $522,570 $469,853 $417,966
-------- -------- --------
Investing activities
Plant expenditures, excluding
allowance for funds used
during construction $(234,409) $(329,385) $(438,016)
Oil and gas exploration and
development (20,371) (17,947) (28,233)
Other investing activities (10,309) (32,460) (18,830)
--------- --------- ---------
Net cash used in investing
activities $(265,089) $(379,792) $(485,079)
--------- --------- ---------
Financing activities
Dividends paid to minority interests $ (8,878) $ (12,159) $ (8,416)
Dividends paid on NEES common shares (153,759) (151,335) (148,063)
Short-term debt (59,862) (30,720) 162,195
Long-term debt-issues 97,850 425,000 97,000
Long-term debt-retirements (106,811) (311,920) (34,920)
Preferred stock-retirements (20,900) (512)
Premium on reacquisition of long-term debt (2,003)
Return of capital to minority
interests and related premium (1,633) (1,364)
Repurchase of common shares (2,075) (1,543)
--------- --------- ---------
Net cash provided by (used in)
financing activities $(256,068) $ (86,044) $ 67,284
--------- --------- ---------
Net increase in cash and cash equivalents $ 1,413 $ 4,017 $ 171
Cash and cash equivalents at beginning
of year 7,064 3,047 2,876
--------- --------- ---------
Cash and cash equivalents at end of year $ 8,477 $ 7,064 $ 3,047
--------- --------- ---------
Supplementary information
Interest paid less amounts capitalized $ 119,710 $ 105,459 $ 90,500
--------- --------- ---------
Federal and state income taxes paid $ 168,255 $ 68,312 $ 114,597
--------- --------- ---------
Dividends received from investments
at equity $ 12,987 $ 14,748 $ 15,350
--------- --------- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
New England Electric System and Subsidiaries
Consolidated Statements of Capitalization
At December 31 (thousands of dollars)
Common share equity 1996 1995
---------- ----------
Common shares, par value $1 per share
Authorized - 150,000,000 shares
Issued - 64,969,652 shares $ 64,970 $ 64,970
Paid-in capital 736,773 736,823
Retained earnings 887,292 831,529
Treasury stock - 102,957 and 45,931 shares,
respectively (3,618) (1,543)
---------- ----------
Total common share equity $1,685,417 $1,631,779
Shares outstanding
Cumulative preferred stock of
subsidiaries 1996 1995 1996 1995
--------- -------- -------- --------
$100 Par value-
4.44% to 4.76% 371,640 430,140 $ 37,164 $ 43,014
6.00% to 7.24% 375,020 525,020 37,502 52,502
$50 Par value
4.50% to 6.95% 730,000 730,000 36,500 36,500
$25 Par value
6.84% 600,000 600,000 15,000 15,000
--------- --------- -------- --------
Total cumulative preferred stock
of subsidiaries (annual dividend
requirement of $7,332 for 1996
and $8,690 for 1995) 2,076,660 2,285,160 $126,166 $147,016
--------- --------- -------- --------
Long-term debt (Note G) Maturity Rate 1996 1995
----------------- ----------------------- ----------
Mortgage bonds 1996 through 1999 5.060%-8.280%$ 173,500 $ 183,500
2000 through 2004 6.240%-8.520% 243,500 243,500
2005 through 2014 6.110%-8.450% 94,000 74,000
2015 through 2026 7.050%-9.125% 442,700 472,550
2018 through 2022 Variable 371,850 342,000
Notes
Granite State Electric Company 1996 through 2025 7.370%-9.440% 15,000 16,000
Nantucket Electric Company 1997 through 2016 4.100%-8.500% 31,500
New England Energy Incorporated 1998 through 2002 Variable 149,000 182,000
Hydro-Transmission Companies 2001 through 2015 8.820%-9.410% 148,010 159,530
Narragansett Energy Resources
Company 2010 7.250% 30,560 32,000
----------------- ----------------------- ----------
Unamortized discounts and
premiums, net (5,337) (5,950)
--------------------
Total long-term debt 1,694,283 1,699,130
--------------------
Long-term debt due in one year (79,705) (23,960)
--------------------
$1,614,578$1,675,170
--------------------
The accompanying notes are an integral part of these consolidated
financial statements.
New England Electric System and Subsidiaries
Notes to Consolidated Financial Statements
Note A - Significant Accounting Policies
1. Nature of operations
New England Electric System (NEES) is a public utility holding
company. NEES and its subsidiaries constitute the second largest
electric utility system in New England. Its core business
activities are the generation, transmission, distribution, and
sale of electric energy and the delivery of related services,
including energy efficiency improvements, to residential,
commercial, industrial, and municipal customers. Other business
activities include independent transmission projects and
rate-regulated domestic oil and gas operations.
The NEES system provides electric service to retail customers
through separate distribution subsidiaries, Massachusetts
Electric Company (Massachusetts Electric) and Nantucket Electric
Company (Nantucket), which operate in Massachusetts; The
Narragansett Electric Company (Narragansett), which operates in
Rhode Island; and Granite State Electric Company (Granite State),
which operates in New Hampshire. Each of the distribution
subsidiaries purchases electricity on behalf of its customers
under wholesale all-requirements contracts with NEES's wholesale
generating subsidiary, New England Power Company (NEP). (See
Note B for a discussion of industry restructuring and NEP's
proposed divestiture of its generating business.)
2. Basis of consolidation and financial statement presentation
The consolidated financial statements include the accounts of
NEES and all subsidiaries except New England Electric
Transmission Corporation, which is recorded under the equity
method. Presentation of this subsidiary on the equity basis is
not material to the consolidated financial statements.
Nantucket, which was acquired by NEES on March 26, 1996, is also
included in the consolidated financial statements. NEP has a
minority interest in four regional nuclear generating companies
(Yankees). Narragansett Energy Resources Company (NERC) has a 20
percent general partnership interest in the Ocean State Power
(OSP) generating facility. NEES Energy, Inc. (NEES Energy) has a
50 percent interest in AllEnergy Marketing Company, L.L.C., a new
energy marketing joint venture with a wholly-owned subsidiary of
Eastern Enterprises. NEP, NERC, and NEES Energy account for
these ownership interests under the equity method.
NEES owns 50.4 percent of the outstanding common stock of
both New England Hydro-Transmission Electric Company, Inc. and
New England Hydro-Transmission Corporation (Hydro-Transmission
companies). The consolidated financial statements include 100
percent of the assets, liabilities, and earnings of the
Hydro-Transmission companies. Minority interests, which
represent the minority stockholders' proportionate share of the
equity and income of the Hydro-Transmission companies, have been
separately disclosed on the NEES consolidated balance sheets and
income statements.
NEP is also a 12 percent and 10 percent joint owner,
respectively, of the Millstone 3 and Seabrook 1 nuclear
generating units, each 1,150 megawatts. NEP's net investments in
Millstone 3 and Seabrook 1, included in "Net utility plant," are
approximately $379 million and $55 million, respectively. 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.
In preparing the financial statements, management is required
to make estimates that affect the reported amounts of assets and
liabilities and disclosures of asset recovery and contingent
liabilities as of the date of the balance sheets, and revenues
and expenses for the period. These estimates may differ from
actual amounts if future circumstances cause a change in the
assumptions used to calculate these estimates.
3. Electric sales revenue
All of NEES's subsidiaries accrue revenues for electricity
delivered but not yet billed (unbilled revenues), with the
exception of Granite State. Included in income are $8 million
and $38 million, in 1995 and 1994, respectively, which represent
amortization of the initial effect of recording unbilled
revenues, in accordance with the retail rate agreements. Accrued
revenues are also recorded in accordance with rate adjustment
mechanisms.
4. Allowance for funds used during construction (AFDC)
The utility subsidiaries capitalize AFDC as part of construction
costs. AFDC represents the composite interest and equity costs
of capital funds used to finance that portion of construction
costs not yet eligible for inclusion in rate base. AFDC is
capitalized in "Utility plant" with offsetting noncash 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
5.6 percent, 7.3 percent, and 7.6 percent, in 1996, 1995, and
1994, respectively.
5. Depreciation and amortization
The depreciation and amortization expense included in the
statements of consolidated income is composed of the following:
Year ended December 31 (thousands of dollars) 1996 1995 1994
-------- -------- --------
Depreciation $171,193 $159,510 $136,746
Nuclear decommissioning costs (see Note D-4) 2,629 2,629 1,951
Amortization:
Oil and gas properties (see Note A-6) 49,163 68,708 79,232
Investment in Seabrook 1
under rate settlement 15,210 23,073 65,061
Oil Conservation Adjustment (OCA) - 4,467 11,854
Property losses 6,280 6,279 6,279
Millstone 3 additional amortization,
under rate settlement 1,904 - -
-------- -------- --------
Total depreciation and amortization
expense $246,379 $264,666 $301,123
-------- -------- --------
Depreciation is provided annually on a straight-line basis.
The provision for depreciation as a percentage of weighted
average depreciable property was 3.2 percent in 1996, 3.3 percent
in 1995, and 3.1 percent in 1994. The OCA was designed to
recover expenditures for coal conversion facilities at NEP's
Salem Harbor Station. These costs were fully amortized at
December 31, 1995. In addition, Seabrook 1 costs under the rate
settlement were fully amortized at December 31, 1996. In
December 1996, New England Energy Incorporated (NEEI) recorded a
$13 million adjustment, which reduced its amortization of oil and
gas properties to correct amounts recorded in the years 1990
through 1996.
6. Oil and gas operations
NEEI participates in a rate-regulated domestic oil and gas
exploration, development, and production program through a
partnership with a nonaffiliated 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.
In conjunction with divestiture of the NEES companies' generation
business, NEEI intends to sell its oil and gas properties.
Losses from this program are passed on to NEP, and ultimately
to retail customers, under an intercompany pricing policy
approved by the Securities and Exchange Commission (SEC). NEEI
has incurred operating losses since 1986 due to low oil and gas
prices, and expects to incur substantial additional losses in the
future. Such losses were $22 million, $44 million, and $40
million in 1996, 1995, and 1994, respectively. NEP's ability to
pass these losses on to its customers was favorably resolved in
NEP's 1988 Federal Energy Regulatory Commission (FERC) rate
settlement. This settlement covered all costs incurred by, or
resulting from, commitments made by NEEI through March 1, 1988.
Other subsequent costs incurred by NEEI are subject to normal
regulatory review.
NEEI follows the full cost method of accounting for its oil
and gas operations, under which capitalized costs (including
interest paid to banks) relating to wells and leases, determined
to be either commercial or noncommercial, 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 $7 million was capitalized in
1996, and $10 million in both 1995 and 1994. In the absence of
the pricing policy, the SEC's cost center "ceiling test" rule
requires non-rate-regulated companies to write down capitalized
costs to a level that approximates the present value of their
proved oil and gas reserves. Based on NEEI's 1996 average oil
and gas selling prices, application of the ceiling test would
have resulted in a write-down of approximately $93 million after
tax ($149 million before tax) at December 31, 1996.
7. Cash
NEES and its subsidiaries classify short-term investments with an
original maturity of 90 days or less as cash.
Note B - Industry Restructuring
The electric utility business is rapidly progressing toward the
unbundling of what is now a fully-regulated, bundled product into
separate generation, transmission, and distribution components
and creating competition in the generation component. Under the
current regulatory framework, electric utilities have incurred
costs related to commitments to supply electricity to customers
that may not be economical in a competitive environment. The
amounts by which such costs exceed market prices are commonly
referred to as "stranded costs." As described below, a variety
of new rules, laws, or proposals have been enacted, or are in
process, in the jurisdictions that the NEES subsidiaries operate,
to provide for competition in a deregulated generation
environment, and allow for stranded cost recovery. See also the
"Industry Restructuring" section of Financial Review for a more
in-depth discussion of current developments in this area.
Massachusetts and Rhode Island
On February 26, 1997, the Massachusetts Department of Public
Utilities (MDPU) approved an industry restructuring settlement
agreement among NEP, its Massachusetts distribution affiliates
Massachusetts Electric and Nantucket, the Massachusetts Attorney
General, and other parties. In August 1996, the state of Rhode
Island enacted industry restructuring legislation. The
Massachusetts settlement and the Rhode Island statute have many
similarities. Both plans:
- - provide for complete retail choice by customers of their
power supplier. In Rhode Island, this would begin in July 1997
for certain customers. All customers in Rhode Island and
Massachusetts would have choice in 1998. In Massachusetts,
choice is contingent on open access being available to all
customers of Massachusetts investor-owned utilities;
- - provide for recovery of their allocated share of NEP's
stranded costs;
- - provide customers who do not choose an alternative supplier
with service called "standard offer" service;
- - implement performance-based rates over varying periods with
predetermined rate increases and with additional adjustments that
can occur as a result of performance standards or if earnings are
below or above an established floor and ceiling;
- - require an adjustment of stranded cost recovery to reflect
the market value of fossil and hydroelectric generating assets
with the Massachusetts settlement requiring actual divestiture of
such assets;
- - propose amendments to the NEP-retail companies' wholesale
all-requirements contracts which have been filed with and
accepted by the FERC, set down for hearing, and made effective,
subject to refund.
The stranded costs to be recovered in both Massachusetts and
Rhode Island include (i) the above-market portion of generating
plant commitments and regulatory assets to be recovered over 12
years in Massachusetts and 12.5 years in Rhode Island and (ii)
the above-market portion of purchased power contracts and the
operating cost of nuclear plants, that cannot be avoided by
shutting down the plants, including nuclear decommissioning
costs. These latter costs would be recovered as incurred over
the life of these obligations, a period expected to extend beyond
12 years. NEP estimates that at December 31, 1996 its
above-market commitments are approximately $4.5 billion on a
present-value basis before application of the proceeds from the
sale of its generating business.
Under the Massachusetts settlement, the NEES companies must
complete the divestiture of their generating business within six
months of the later of the commencement of retail choice in
Massachusetts or the receipt of all necessary regulatory
approvals. As part of the divestiture plan, NEP will endeavor to
sell, or otherwise transfer, its minority interest in four
nuclear power plants to nonaffiliates. To the extent NEP is
unable to divest its nuclear generating interest, the
Massachusetts settlement provides for a sharing between customers
and shareholders of the nuclear-related revenues and costs not
otherwise reflected in the stranded cost recovery, with 80
percent allocated to customers and 20 percent to shareholders.
In addition, NEEI is planning to sell its oil and gas properties,
the cost of which is supported by NEP through fuel purchased
contracts.
New Hampshire and federal activity
On February 28, 1997, the New Hampshire Public Utilities
Commission (NHPUC) issued its plan to implement a New Hampshire
law calling for retail access by 1998. Under the plan, utilities
such as Granite State whose rates are below the regional average
would be allowed full recovery of stranded costs as calculated by
the NHPUC. However, the NHPUC indicated that its methodology and
proposed timing of recovery would yield both initial access
charges and total recovery less than that requested by Granite
State although the NHPUC indicated that its decision would not
result in savings for Granite State's customers.
Prior to the issuance of the NHPUC order, Granite State
reached an interim settlement with several customers and other
stakeholders that would set initial access charges at 2.8 cents
per kWh for two years, and in other respects would mirror the
Massachusetts settlement described previously. Stranded costs to
be recovered after the two-year initial period would be subject
to future regulatory determination. Unlike the NHPUC order, the
interim settlement agreement would provide all customers with a
rate reduction of approximately 10 percent. This interim
settlement is still pending before the NHPUC.
In April 1996, the FERC issued Order No. 888 requiring
utilities that own transmission facilities to file open access
tariffs to make available transmission service to affiliates and
nonaffiliates at fair, nondiscriminatory rates. In mid-1996, NEP
filed a transmission tariff with the FERC pursuant to this
requirement. Order No. 888 also stated that public utilities
will be allowed to seek recovery of legitimate and verifiable
stranded costs from departing customers as a result of wholesale
competition. The FERC also stated that it would permit stranded
cost recovery under wholesale all-requirements contracts, such as
the contracts between NEP and its retail affiliates.
Because of the Massachusetts settlement and the Rhode Island
statute, NEP does not expect it will rely exclusively on Order
No. 888 to recover stranded costs from its affiliates in
Massachusetts and Rhode Island. NEP cannot predict at this time
whether an Order No. 888 filing will be necessary to fully
recover stranded costs from Granite State or from seven
unaffiliated wholesale customers should any of those customers
choose to terminate service under their contract with NEP.
Granite State and these seven unaffiliated customers are
responsible for approximately 3 percent and 2 percent of NEP's
sales, respectively. On February 26, 1997, the FERC announced
Order No. 888-A, reaffirming the principles of Order No. 888,
including stranded cost recovery.
Accounting implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Financial Accounting Standards
No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), requires regulated entities, in appropriate
circumstances, to establish regulatory assets, and thereby defer
the income statement impact of certain costs expected to be
recovered in future rates. The NEES companies have recorded
approximately $550 million in regulatory assets in compliance
with FAS 71 of which approximately $75 million relate to the
transmission and distribution business.
Both the Massachusetts settlement and the Rhode Island
statute provide for full recovery of the costs of generating
assets and oil and gas related assets (including regulatory
assets) not recoverable from the proceeds of the divestiture of
NEP's generating business. The cost of these assets would be
recovered as part of a transition access charge imposed on all
distribution customers. After the proposed divestiture,
substantially all of NEP's business, including the recovery of
its stranded costs, would remain under cost-based rate
regulation. NEES believes the Massachusetts settlement and the
Rhode Island statute will enable the NEES distribution companies
operating in those states to recover through rates their specific
costs of providing ongoing distribution services. In addition,
FERC Order No. 888 enables transmission companies to recover
their specific costs of providing transmission service. NEES
believes these factors will allow its principal subsidiaries to
continue to apply FAS 71 and that no impairment of plant assets
will exist under Statement of Financial Accounting Standards No.
121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of (FAS 121). Any loss from the
divestiture of generating assets and oil and gas assets will be
recorded as a regulatory asset to be recovered through the
ongoing transition access charge.
Although NEES believes that its subsidiaries will continue to
meet the criteria for continued application of FAS 71, NEES
understands that members of the SEC staff have raised questions
concerning the continued applicability of FAS 71 to certain other
electric utilities facing restructuring. In addition, despite
the progress made to date in Massachusetts and Rhode Island, it
is possible that the final restructuring plans ultimately ordered
by regulatory bodies would not reflect full recovery of stranded
costs, including a fair return on those costs as they are being
recovered. In the event that future circumstances should cause
the application of FAS 71 to be discontinued, a noncash write-off
of previously established regulatory assets and liabilities
related to the affected operations would be required. In
addition, write-downs of plant assets under FAS 121 could be
required, including a write-off of any loss from the divestiture
of the generating business.
The components of regulatory assets are as follows:
At December 31 (thousands of dollars) 1996 1995
-------- --------
Oil and gas properties:
in excess of SEC "ceiling test" (see Note A-6) $149,100 $178,200
-------- --------
Regulatory assets included in current assets &
liabilities:
Accrued NEEI losses (see Note A-6) 21,648 43,731
Rate adjustment mechanisms (see Note F) (48,894) (6,720)
-------- --------
(27,246) 37,011
-------- --------
Regulatory assets included in deferred charges:
Accrued Connecticut Yankee costs (see Note D-4) 114,425 -
Accrued Yankee Atomic costs (see Note D-4) 51,988 67,566
Unamortized losses on reacquired debt 52,167 54,583
Deferred SFAS No. 106 costs (see Note E-2) 29,839 38,669
Deferred SFAS No. 109 costs (see Note C) 72,075 74,083
Purchased power contract termination costs 19,578 23,494
Deferred gas pipeline charges (see Note D-2) 59,733 62,873
Environmental response costs (see Note D-3) 18,265 19,276
Deferred storm costs 6,530 8,259
Unamortized property losses 253 12,044
Other 6,226 24,109
-------- --------
431,079 384,956
-------- --------
$552,933 $600,167
-------- --------
Additional deferred charges included in "Deferred charges and
other assets" on the consolidated balance sheets, that do not
represent regulatory assets, totaled $17,541,000 and $32,404,000
at December 31, 1996 and 1995, respectively.
Note C - Income Taxes
Total income taxes in the statements of consolidated income are as follows:
Year ended December 31 (thousands of dollars) 1996 1995 1994
-------- -------- --------
Income taxes charged to operations $139,199 $128,340 $128,257
Income taxes charged to "Other income" (3,018) 762 779
-------- -------- --------
Total income taxes $136,181 $129,102 $129,036
-------- -------- --------
Total income taxes, as shown above, consist of the following components:
Year ended December 31 (thousands of dollars) 1996 1995 1994
-------- -------- --------
Current income taxes $166,509 $105,046 $ 87,295
Deferred income taxes (28,652) 25,578 46,166
Investment tax credits, net (1,676) (1,522) (4,425)
Total income taxes $136,181 $129,102 $129,036
-------- -------- --------
Total income taxes, as shown on previous page, consist of federal and
state components as follows:
Year ended December 31 (thousands of dollars) 1996 1995 1994
-------- -------- --------
Federal income taxes $111,573 $103,503 $104,136
State income taxes 24,608 25,599 24,900
-------- -------- --------
Total income taxes $136,181 $129,102 $129,036
-------- -------- --------
Investment tax credits of subsidiaries are deferred and
amortized over the estimated lives of the property giving rise to
the credits. Although investment tax credits were generally
eliminated by the 1986 tax legislation, additional carry forward
amounts continue to be recognized.
With regulatory approval, the subsidiaries have adopted
comprehensive interperiod tax allocation (normalization) for
temporary book/tax differences.
Total income taxes differ from the amounts computed by
applying the federal statutory tax rates to income before taxes.
The reasons for the differences are as follows:
Year ended December 31 (thousands of dollars) 1996 1995 1994
-------- --------- --------
Computed tax at statutory rate $123,053 $119,892 $118,006
Increases (reductions) in tax resulting from:
Reversal of deferred taxes recorded
at a higher rate (2,175) (3,306) (4,230)
Amortization of investment tax credits (4,347) (4,443) (5,272)
State income tax, net of federal income
tax benefit 15,995 16,639 16,185
All other differences 3,655 320 4,347
-------- --------- --------
Total income taxes $136,181 $ 129,102 $129,036
-------- --------- --------
The following table identifies the major components of total deferred
income taxes:
At December 31 (millions of dollars) 1996 1995
------- --------
Deferred tax asset:
Plant related $ 110 $ 104
Investment tax credits 37 38
All other 143 122
------- --------
290 264
------- --------
Deferred tax liability:
Plant related (811) (788)
Equity AFDC (53) (56)
All other (177) (200)
------- --------
(1,041) (1,044)
------- --------
Net deferred tax liability $ (751) $ (780)
------- -------
There were no valuation allowances for deferred tax assets
deemed necessary.
Federal income tax returns for NEES and its subsidiaries have
been examined and reported on by the Internal Revenue Service
(IRS) through 1991. The returns for 1992 and 1993 are currently
under examination by the IRS.
Note D - Commitments and Contingencies
1. Plant expenditures
The NEES subsidiaries' utility plant expenditures are estimated
to be $230 million in 1997. At December 31, 1996, substantial
commitments had been made relative to future planned
expenditures.
2. Natural gas pipeline capacity
In connection with serving NEP's gas-burning electric generation
facilities, NEP has entered into several contracts for natural
gas pipeline capacity and gas supply. These agreements require
minimum fixed payments that are currently estimated to be
approximately $57 million to $60 million per year from 1997 to
2001. Under these agreements, remaining fixed payments from 2002
through 2014 total approximately $525 million.
As part of a rate settlement, NEP was recovering 50 percent
of the fixed pipeline capacity payments through its current fuel
clause and deferring the recovery of the remaining 50 percent
until the Manchester Street repowering project was completed.
These deferrals ended in November 1995, at which time NEP had
deferred payments of approximately $63 million, which will be
amortized over 25 years in accordance with rate settlements (see
Note B).
In connection with managing its fuel supply, NEP uses a
portion of this pipeline capacity to sell natural gas. Proceeds
from the sale of natural gas and pipeline capacity of $50
million, $71 million, and $55 million in 1996, 1995, and 1994,
respectively, have been passed on to customers through NEP's fuel
clause. These proceeds have been reflected as an offset to the
related fuel expense in "Fuel for generation" in NEP's statements
of income. Natural gas sales decreased in 1996 as a result of
the Manchester Street Station entering commercial operation in
the second half of 1995.
3. Hazardous waste
The Federal Comprehensive Environmental Response, Compensation
and Liability Act, more commonly known as the "Superfund" law,
imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous
substances. A number of states, including Massachusetts, have
enacted similar laws.
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. NEES subsidiaries currently have in
place an internal environmental audit program and an external
waste disposal vendor audit and qualification 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 potentially
responsible parties (PRPs) by either the United States
Environmental Protection Agency (EPA) or the Massachusetts
Department of Environmental Protection for 23 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 manufactured gas locations (including
nine of the 23 locations for which NEES companies are PRPs)
mostly located in Massachusetts. NEES and its subsidiaries are
currently aware of other possible hazardous waste sites, and may
in the future become aware of additional sites, that they may be
held responsible for remediating.
In 1993, the MDPU approved a settlement agreement regarding
the rate recovery of remediation costs of former manufactured gas
sites and certain other hazardous waste sites located in
Massachusetts. Under that agreement, qualified costs related to
these sites are paid out of a special fund established on
Massachusetts Electric's books. Massachusetts Electric made an
initial $30 million contribution to the fund. Rate-recoverable
contributions of $3 million, adjusted since 1993 for inflation,
are added annually to the fund along with interest and any
recoveries from insurance carriers. At December 31, 1996, the
fund had a balance of $17 million. Under the 1996 Massachusetts
settlement, an additional $15 million will be transferred to the
fund in 1997 out of existing reserves for refunds.
Predicting the potential costs to investigate and remediate
hazardous waste sites continues to be difficult. There are also
significant uncertainties as to the portion, if any, of the
investigation and remediation costs of any particular hazardous
waste site that may ultimately be borne by NEES or its
subsidiaries. Where appropriate, the NEES companies intend to
seek recovery from their insurers and from other PRPs, but it is
uncertain whether, and to what extent, such efforts will be
successful. At December 31, 1996, NEES had total reserves for
environmental response costs of $48 million and a related
regulatory asset of $18 million. NEES believes that hazardous
waste liabilities for all sites of which it is aware, and which
are not covered by a rate agreement, are not material to its
financial position.
In October 1996, the American Institute of Certified Public
Accountants issued new accounting rules for Environmental
Remediation Liabilities which become effective in 1997. NEES
does not believe these new rules will have a material effect on
NEES's financial position or results of operations.
4. Nuclear plant decommissioning and nuclear fuel disposal
NEP is liable for its share of decommissioning costs for
Millstone 3, Seabrook 1, and all of the Yankees. Decommissioning
costs include not only estimated costs to decontaminate the units
as required by the Nuclear Regulatory Commission (NRC), but also
costs to dismantle the uncontaminated portion of the units. NEP
records decommissioning cost expense on its books consistent with
its rate recovery. NEP is recovering its share of projected
decommissioning costs for Millstone 3 and Seabrook 1 through
depreciation expense. In addition, NEP is paying its portion of
projected decommissioning costs for all of the Yankees through
purchased power expense. Such costs reflect estimates of total
decommissioning costs approved by the FERC.
Connecticut Yankee
NEP has a 15 percent equity ownership interest in Connecticut
Yankee. As a result of an economic analysis, the Connecticut
Yankee board of directors voted in December 1996 to permanently
shut down and decommission the plant.
In December 1996, Connecticut Yankee filed with the FERC to
recover all of its approximately $246 million undepreciated
investment in the plant and other costs over the period extending
through June 2007, when the plant's NRC operating license would
have expired. In a 1993 decision, the FERC allowed Yankee Atomic
to recover its undepreciated investment in its permanently shut
down nuclear plant, in part on the grounds that owners should not
be discouraged from closing uneconomic plants. Several parties
have intervened in opposition to Connecticut Yankee's filing.
NEP believes that the FERC will allow NEP to recover from its
customers all costs that the FERC allows Connecticut Yankee to
recover from NEP.
NEP has recorded the estimated future payment obligation to
Connecticut Yankee of $114 million as a liability and as an
offsetting regulatory asset, reflecting NEP's expected future
rate recovery of such costs. The NRC has identified numerous
apparent violations of its regulations, which may result in the
assessment of civil penalties.
Yankee Atomic
NEP has a 30 percent ownership interest in Yankee Atomic. In
1992, the Yankee Atomic board of directors decided to permanently
cease power operation of, and decommission, the facility.
Decommissioning is currently underway.
NEP has recorded an estimate of its total future payment
obligations for post-operating costs to Yankee Atomic as a
liability and as an offsetting regulatory asset, reflecting its
expected future rate recovery of such costs. This liability and
related regulatory asset are approximately $52 million each at
December 31, 1996.
Decommissioning Trust Funds
Each nuclear unit in which NEP has an ownership interest has
established a decommissioning trust fund or escrow fund into
which payments are being made to meet the projected costs of
decommissioning. Listed below is information on each operating
nuclear plant in which NEP has an ownership interest.
NEP's share of (millions of dollars)
-----------------------------------
NEP's EstimatedDecommissioning
Ownership Net Decommissioning Fund License
Unit Interest (%)Plant AssetsCost (in 1996$) Balances* Expiration
- ---- ----------- ------------ --------------- --------------- ----------
Maine Yankee** 20 44 74 31 2008
Vermont Yankee 20 36 75 30 2012
Millstone 3*** 12 379 62 16 2025
Seabrook 1*** 10 55 45 7 2026
<FN>
*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.
***Fund balances are included in "Other investments" on the balance sheets and approximate
market value.
</FN>
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; those
repositories do not currently exist. If any of the units were
shut down prior to the end of their operating licenses, the funds
collected for decommissioning to that point would be
insufficient.
The Nuclear Waste Policy Act of 1982 establishes that the
federal government is responsible for the disposal of spent
nuclear fuel. The federal government requires NEP to pay a fee
based on its share of the net generation from the Millstone 3 and
Seabrook 1 nuclear units. NEP is recovering this fee through its
fuel clause. Similar costs are incurred by the Maine Yankee and
Vermont Yankee nuclear generating units. These costs are billed
to NEP and also recovered from customers through NEP's fuel
clause.
5. Investments in nuclear units
The Millstone 3 and Maine Yankee nuclear generating units are
currently shut down and have been placed on the NRC "Watch List,"
signifying that their safety performance exhibits sufficient
weakness to warrant increased NRC attention. Neither may restart
without NRC approval. At present, the Vermont Yankee and
Seabrook 1 nuclear generating units appear to be operating
routinely without major problems.
On October 9, 1996, the NRC issued letters to operators of
nuclear power plants requiring them to document that the plants
are operated and maintained within their design and licensing
bases, and that any deviations are reconciled in a timely manner.
The Seabrook 1, Maine Yankee, and Vermont Yankee nuclear power
plants responded to the NRC letters in February 1997.
Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Maine Yankee and
Vermont Yankee, are increasing rapidly and could adversely affect
their service lives, availability, and costs. These
uncertainties stem from a combination of factors, including the
acceleration of competitive pressures in the power generation
industry and increased NRC scrutiny.
Millstone 3
In April 1996, the NRC ordered Millstone 3, which has experienced
numerous technical and nontechnical problems, to remain shut down
pending verification that the unit's operations are in accordance
with NRC regulations and the unit's operating license. Millstone
3 is operated by a subsidiary of Northeast Utilities (NU). NEP
is not an owner of the Millstone 1 and 2 nuclear generating
units, which are also shut down under NRC orders.
A number of significant prerequisites must be fulfilled prior
to restart of Millstone 3, including certification by NU that the
unit adequately conforms to its design and licensing bases, an
independent verification of corrective actions taken at the unit,
an NRC assessment concluding a culture change has occurred,
public hearings, and a vote of the NRC Commissioners. NU
announced in December 1996 that it expects Millstone 3 to be
ready for restart around the end of 1997, subject to review by
the NRC Commissioners. NEP cannot predict when Millstone 3 will
be allowed by the NRC to restart, but believes that the unit will
remain shut down for a very protracted period.
NEP incurred $10 million of actual costs in 1996 related to
corrective actions associated with the outage. NEP has also
accrued a liability of approximately $3 million for its share of
future corrective action costs. Additional costs may be
incurred. During the outage, NEP is also incurring approximately
$1.6 million per month in incremental replacement power costs,
which it has been recovering from customers through its fuel
clause.
Several criminal investigations related to Millstone 3 are
ongoing. The NRC has identified numerous apparent violations of
its regulations which may result in the assessment of civil
penalties. NEP and other minority owners of Millstone 3 are
assessing their legal rights with respect to NU's operation of
Millstone 3.
Maine Yankee
Over the past few years, the Maine Yankee nuclear generating
plant has experienced numerous technical and nontechnical
problems. In 1995, the plant had been shut down for much of the
year due to the discovery of cracks in its steam generator tubes.
The plant is currently shut down due to a cable routing problem.
In addition, due to leaking nuclear fuel rods, 68 fuel assemblies
will be replaced. As a result, Maine Yankee management does not
expect the unit to restart until at least summer of 1997.
In late 1995, allegations were made to the NRC that
inadequate analyses of the plant's emergency core cooling system
had been performed. As a result of the allegations, the NRC
limited the plant's operation to 90 percent of full capacity. In
September 1996, the NRC asked the Department of Justice (DOJ) to
review, for potential criminal violations, an NRC investigatory
report on the allegations. The DOJ is not limited in its
investigation to the matters covered in that report.
During 1996, the NRC conducted an independent safety
assessment (ISA) and identified a number of weaknesses,
deficiencies, and apparent violations which could result in
fines. Yankee Atomic performed professional services for Maine
Yankee associated with the matters being investigated. In
response to the ISA results, Maine Yankee has indicated that it
will spend more than $50 million in 1997 on operational
improvements. Additionally, in February 1997, Entergy
Corporation, an operator of five nuclear units, commenced
providing management services.
Under a confirmatory action letter issued by the NRC on
December 18, 1996, and supplemented on January 30, 1997, Maine
Yankee must fulfill certain commitments before its plant will be
allowed by the NRC staff to return to service. Because of
regulatory and other uncertainties faced by Maine Yankee, NEP
cannot predict whether or when Maine Yankee will return to
service.
During the outage, NEP is incurring approximately $1.8 million
per month in incremental replacement power costs, which it has
been recovering from customers through its fuel clause.
6. Nuclear insurance
The Price-Anderson Act limits the amount of liability claims that
would have to be paid in the event of a single incident at a
nuclear plant to $8.9 billion (based upon 110 licensed reactors).
The maximum amount of commercially available insurance coverage to
pay such claims is $200 million. The remaining $8.7 billion would
be provided by an assessment of up to $79.3 million per incident
levied on each of the participating nuclear units in the United
States, subject to a maximum assessment of $10 million per
incident per nuclear unit in any year. The maximum assessment,
which was most recently adjusted in 1993, is adjusted for
inflation at least every five years. NEP's current interest in
the Yankees (excluding Yankee Atomic and Connecticut Yankee),
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. Connecticut Yankee is planning to file with the NRC for
a similar exemption.
Each of the nuclear units in which NEP has an ownership
interest also carries nuclear property insurance to cover the
costs of property damage, decontamination or premature
decommissioning, and workers' claims resulting from a nuclear
incident. These policies may require additional premium
assessments if losses relating to nuclear incidents at units
covered by this insurance occurring in a prior six-year period
exceed the accumulated funds available. NEP's maximum potential
exposure for these assessments, either directly, or indirectly
through purchased power payments to the Yankees, is approximately
$11 million per year.
7. 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 1997 to 2029. In
conjunction with its divestiture plan, NEP will endeavor to sell
these long-term contracts.
Certain of these contracts require NEP to make minimum fixed
payments, even when the supplier is unable to deliver power, to
cover NEP's proportionate share of the capital and fixed operating
costs of these generating units. The fixed portion of payments
under these contracts totaled $186 million in 1996, $215 million
in 1995, and $190 million in 1994. These contracts, excluding
contracts with Yankee Atomic and Connecticut Yankee (see Note
D-4), have minimum fixed payment requirements of $155 million in
1997, $150 million in 1998 and 1999, $145 million in 2000 and
2001, and approximately $1.3 billion thereafter. Approximately 92
percent of the payments under these contracts are to the Yankees
and OSP, entities in which NEES subsidiaries hold ownership
interests.
NEP's other contracts, principally with nonutility 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 $230 million in 1996, $245 million in
1995, and $210 million in 1994.
Note E - Employee Benefits
1. Pension plans
The NEES companies' retirement plans are noncontributory
defined-benefit plans covering substantially all employees. The
plans provide pension benefits based on the employee's
compensation during the five years prior to retirement. The NEES
companies' funding policy is to contribute each year the net
periodic pension cost for that year. However, the contribution
for any year will not be less than the minimum contribution
required by federal law or greater than the maximum tax deductible
amount.
Net pension cost for 1996, 1995, and 1994 included the
following components:
Year ended December 31 (thousands of dollars) 1996 1995 1994
-------- -------- -------
Service cost - benefits earned during
the period $ 14,918 $ 14,167 $13,715
Plus (less):
Interest cost on projected benefit obligation 51,461 54,821 49,067
Return on plan assets at expected long-term rate (52,085) (49,691) (47,281)
Amortization 2,887 5,589 5,781
Net pension cost $ 17,181 $ 24,886 $21,282
-------- -------- -------
Actual return on plan assets $ 91,571 $130,979 $ 4,384
-------- -------- -------
Year ended December 31 1997 1996 1995 1994
----- ----- ----- -----
Assumptions used to determine
pension cost:
Discount rate 7.25% 7.25% 8.25% 7.25%
Average rate of increase in future
compensation levels 4.13% 4.13% 4.63% 4.35%
Expected long-term rate of return
on assets 8.50% 8.50% 8.75% 8.75%
The increase in 1995 costs and the decrease in 1996 costs
reflect additional amounts recorded in the fourth quarter of 1995
related to certain supplemental benefit changes.
The following table sets forth the retirement plans' funded
status:
At December 31 (millions of dollars) 1996 1995
---------------------------- ------------------------------
Union Non-UnionSupple- Union Non-Union Supple-
EmployeeEmployee mental EmployeeEmployee mental
Plans Plans Plans Plans Plans Plans
-------- ---------------- -------- --------- -------
Benefits earned
Actuarial present value
of accumulated benefit liability:
Vested $298 $342 $47 $293 $343 $60
Nonvested 9 10 1 8 10 -
------------------------ ---------------- --------
Total $307 $352 $48 $301 $353 $60
------------------------ ---------------- --------
Reconciliation of funded status
Actuarial present value of
projected benefit liability $355 $398 $54 $346 $402 $73
Unrecognized prior service costs (6) (3) - (7) (4) (16)
SFAS No. 87 transition liability
not yet recognized (amortized) - (1) (3) - (1) (4)
Net gain (loss) not yet
recognized (amortized) 25 15 (3) (1) (23) (7)
Additional minimum liability
recognized - - 3 - - 14
------------------------ ---------------- --------
374 409 51 338 374 60
------------------------ ---------------- --------
Pension fund assets at fair value 384 428 - 349 392 -
SFAS No. 87 transition asset
not yet recognized (amortized) (10) - - (11) - -
------------------------ ---------------- --------
374 428 - 338 392 -
------------------------ ---------------- --------
Accrued pension/(prepaid)
payments recorded on books $ - $(19) $51 $ - $(18) $60
------------------------ ---------------- --------
The plans' funded status at December 31, 1996 and 1995 were
calculated using the assumed rates from 1997 and 1996,
respectively, and the 1983 Group Annuity Mortality table.
Plan assets are composed primarily of corporate equity, debt
securities, and cash equivalents.
In addition to its regular pension funds shown in the table
above, NEES and its subsidiaries have a separate trust fund,
commonly referred to as a Rabbi Trust, for certain supplemental
pensions and deferred compensation for key executives and
employees. The balance of this Rabbi Trust is invested in
short-term investments and NEES shares. At December 31, 1996 and
1995, the Rabbi Trust held 102,957 and 45,931 NEES shares,
respectively, accounted for as treasury stock. At the end of 1996
and 1995, the difference between costs and market value of
investments in the Rabbi Trust was not material. The short-term
investments held in the Rabbi Trust amount to $45 and $43 million
at December 31, 1996 and 1995, respectively.
2. Postretirement benefit plans other than pensions (PBOPs)
The NEES subsidiaries provide health care and life insurance
coverage to eligible retired employees. Eligibility is based on
certain age and length of service requirements and in some cases
retirees must contribute to the cost of their coverage.
The total cost of PBOPs for 1996, 1995, and 1994 included the
following components:
Year ended December 31 (thousands of dollars) 1996 1995 1994
-------- -------- --------
Service cost - benefits earned during
the period $ 6,794 $ 7,137 $ 8,575
Plus (less):
Interest cost on accumulated benefit
obligation 24,667 29,377 27,813
Return on plan assets at expected
long-term rate (12,958) (9,742) (7,821)
Amortization 13,099 16,204 18,273
-------- -------- --------
Net postretirement benefit cost $ 31,602 $ 42,976 $ 46,840
-------- -------- --------
Actual return on plan assets $ 24,881 $ 29,054 $ 185
-------- -------- --------
Year ended December 31 1997 1996 1995 1994
-------- -------- -------- --------
Assumptions used to determine
postretirement benefit cost:
Discount rate 7.25% 7.25% 8.25% 7.25%
Expected long-term rate of return on assets 8.25% 8.25% 8.50% 8.50%
Health care cost rate - 1994 - - - 11.00%
Health care cost rate - 1995 to 1999 8.00% 8.00% 8.50% 8.50%
Health care cost rate - 2000 to 2004 6.25% 6.25% 8.50% 8.50%
Health care cost rate 2005 and beyond 5.25% 5.25% 6.25% 6.25%
The following table sets forth benefits earned and the plans' funded status:
At December 31 (millions of dollars) 1996 1995
-------- --------
Accumulated postretirement benefit obligation:
Retirees $ 236 $ 230
Fully eligible active plan participants 24 23
Other active plan participants 109 121
-------- --------
Total benefits earned 369 374
Unrecognized prior service costs (1) (1)
Unrecognized transition obligation (294) (313)
Net gain not yet recognized 101 71
-------- --------
175 131
-------- --------
Plan assets at fair value 202 160
-------- --------
Prepaid postretirement benefit costs recorded on books $ 27 $ 29
The plans' funded status at December 31, 1996 and 1995 were
calculated using the assumed rates in effect for 1997 and 1996,
respectively.
The assumptions used in the health care cost trends have 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,
1996 by approximately $44 million and the net periodic cost for
1996 by approximately $5 million.
The NEES subsidiaries fund the annual tax-deductible
contributions. Plan assets are invested in equity and debt
securities and cash equivalents.
Note F - Short-Term Borrowings and Other Current Liabilities
At December 31, 1996, NEES and its consolidated subsidiaries had
lines of credit and standby bond purchase facilities with banks
totaling $706 million. These lines and facilities were used at
December 31, 1996 for liquidity support for $4 million of
short-term borrowing, $141 million of commercial paper borrowings,
and $372 million of NEP mortgage bonds in tax-exempt commercial
paper mode (see Note G). Fees are paid on the lines and
facilities in lieu of compensating balances. The weighted average
rate on outstanding short-term borrowings was 5.51 percent at
December 31, 1996. The fair value of the NEES subsidiaries'
short-term debt equals carrying value.
The components of other current liabilities are as follows:
At December 31 (thousands of dollars) 1996 1995
-------- -------
Accrued wages and benefits $ 37,872 $30,222
Rate adjustment mechanisms 50,614 19,772
Customer deposits 10,595 10,993
Other 10,501 12,117
-------- -------
$109,582 $73,104
-------- -------
Note G - Long-Term Debt
Substantially all of 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) 1997 1998 1999 2000 2001
------- -------- -------- -------- -------
Maturing long-term debt $66,265 $ 76,470 $34,480 $ 92,485 $ 6,495
Mandatory prepayments:
Hydro-Transmission companies 11,520 11,520 11,520 11,520 10,790
NEEI - 14,000 30,000 30,000 30,000
NERC 1,920 1,920 2,280 2,280 2,280
------- -------- ------- -------- -------
Total $79,705 $103,910 $78,280 $136,285 $49,565
------- -------- ------- -------- -------
The terms of $372 million of variable rate pollution control
revenue bonds collateralized by NEP mortgage bonds at December 31,
1996 require NEP to reacquire the bonds under certain limited
circumstances. NEP has approximately $740 million of mortgage
bonds outstanding, including those collateralizing pollution
control revenue bonds. The bond indenture restricts the sale of
the trust property in its entirety or substantially in its
entirety. The proposed sale of NEP's generating business would
likely require that NEP either amend the bond indenture or defease
the bonds in connection with the proposed sale. Any defeasance of
bonds would be by the deposit of cash representing principal and
interest to the maturity date or interest, principal, and general
redemption premium to an earlier redemption date. At December 31,
1996, interest rates on NEP's variable rate bonds ranged from 2.30
percent to 4.80 percent. Also, at December 31, 1996, interest
rates on NEEI's debt ranged from 5.30 percent to 6.17 percent.
At December 31, 1996, the NEES subsidiaries' long-term debt had
a carrying value of approximately $1,694,000,000 and a fair value
of approximately $1,730,000,000. The fair value of debt that
reprices frequently at market rates approximates carrying value.
The fair market value of the NEES subsidiaries' long-term debt was
estimated based on the quoted prices for similar issues or on the
current rates offered to the NEES companies for debt of the same
remaining maturity.
Note H - Supplementary Quarterly Financial Information (unaudited)
1996 Quarter Ended Mar. 31 June 30 Sept. 30 Dec. 31
-------- -------- -------- --------
(thousands of dollars, except per share amounts)
Operating revenue $586,220 $551,110 $616,857 $596,511
Operating income $ 94,955 $ 69,133 $ 97,384 $ 86,646
Net income $ 61,496 $ 35,001 $ 64,375 $ 48,064
Net income per average share $ .95 $ .54 $ .99 $ .74
-------- -------- -------- --------
1995 Quarter Ended Mar. 31 June 30 Sept. 30 Dec. 31*
-------- -------- --------- --------
(thousands of dollars, except per share amounts)
Operating revenue $ 558,316 $533,547 $599,126 $580,723
Operating income $ 73,385 $ 59,881 $102,321 $ 87,841
Net income $ 47,662 $ 33,531 $ 73,820 $ 49,744
Net income per average share $ .73 $ .52 $ 1.14 $ .76
--------- -------- -------- --------
<FN>
*See Note E
</FN>
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 where 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,
1996 and 1995 and the related consolidated statements of income,
retained earnings and cash flows for each of the three years in
the period ended December 31, 1996. 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, 1996 and
1995, and the consolidated results of its operations and its cash
flows for each of the three years in the period ended December 31,
1996, in conformity with generally accepted accounting principles.
Boston, Massachusetts /s Coopers & Lybrand L.L.P.
February 28, 1997
Shareholder Information
For shareholder information or assistance, write or call
Shareholder Services at:
New England Electric System, Shareholder Services,
P.O. Box 770, Westborough, MA 01581
Toll-free number: 1-800-466-7215 Local number: (508) 389-4900
Fax: (508) 836-0276 E-mail: shrser@neesnet.com
Dividend reinvestment
Shareholders of New England Electric System common shares who hold
their shares in registered form are eligible to participate in the
Dividend Reinvestment and Common Share Purchase Plan. The Plan
provides participants the opportunity to reinvest their dividends
and send in optional cash payments to purchase additional common
shares. These shares will be newly issued shares or shares
purchased in the open market. The Company will pay all brokerage
commissions and service charges associated with the Plan. For more
information on the Plan, please contact Shareholder Services at
our toll-free number listed above.
Direct deposit of dividends
Shareholders who hold New England Electric System common shares in
their own name may request to have their dividends directly
deposited into their checking or savings account. This service is
provided without fees. If you participate in Direct Deposit, you
will receive a credit advice for your records. To sign up for this
service, please call Shareholder Services on our toll-free number
to request an authorization form.
Change of address
Please contact Shareholder Services on our toll-free number to
notify us of your address change.
Form 10-K
Copies of the Annual Report on Form 10-K to the Securities and
Exchange Commission for 1996 are available upon request at no
charge by writing to the address at left.
Annual meeting
The annual meeting of New England Electric System will be held at
the Casino, located at Roger Williams Park in Providence, RI on
April 29, 1997 at 10:30 a.m.
Stock exchange listings
New England Electric System common shares are listed on the New
York Stock Exchange and the Boston Stock Exchange under the symbol
NES.
Transfer agent
Certificates for transfer should be mailed to our transfer agent
at:
Bank of Boston, c/o Boston EquiServe
P.O. Box 8040
Boston, MA 02266-8040
New England Electric System common shares
1996 1995
---- ----
Price Range ($) Price Range ($)
High Low Dividend High Low Dividend
Declared ($) Declared ($)
First Quarter 40.625 36.125 .590 34.250 30.625 .575
Second Quarter 38.875 32.875 .590 35.250 29.625 .590
Third Quarter 36.375 31.125 .590 37.250 32.875 .590
Fourth Quarter 35.625 31.000 .590 40.000 37.000 .590
The total number of shareholders at December 31, 1996 was 52,564.
[MAP OF SERVICE AREAS]
NEES Subsidiaries
As of January 1, 1997
Massachusetts Electric Company
25 Research Drive, Westborough, Massachusetts 01582
The Narragansett Electric Company
280 Melrose Street, Providence, Rhode Island 02901
Granite State Electric Company
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766
Nantucket Electric Company
25 Research Drive, Westborough, Massachusetts 01582
AllEnergy Marketing Company, L.L.C.*
95 Sawyer Road, Waltham, Massachusetts 02154
* Joint venture with Eastern Enterprises
Granite State Energy, Inc.
4 Park Street, Concord, New Hampshire 03301
NEES Energy, Inc.
25 Research Drive, Westborough, Massachusetts 01582
Narragansett Energy Resources Company
280 Melrose Street, Providence, Rhode Island 02901
New England Power Company
25 Research Drive, Westborough, Massachusetts 01582
NEES Communications, Inc.
25 Research Drive, Westborough, Massachusetts 01582
New England Electric Resources, Inc.
25 Research Drive, Westborough, Massachusetts 01582
New England Energy Incorporated
25 Research Drive, Westborough, Massachusetts 01582
New England Electric Transmission Corporation
4 Park Street, Concord, New Hampshire 03301
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
Executive Team
[PHOTO OF EXECUTIVE TEAM]
Left to right: Alfred D. Houston, Cheryl A. LaFleur, Michael E.
Jesanis, Richard P. Sergel, John W. Rowe, and Jeffrey D. Tranen
NEES Officers
As of January 1, 1997
John W. Rowe
President and Chief Executive Officer
Alfred D. Houston
Executive Vice President and Chief Financial Officer
Richard P. Sergel
Senior Vice President
Jeffrey D. Tranen
Senior Vice President
Cheryl A. LaFleur
Vice President, General Counsel, and Secretary
Michael E. Jesanis
Vice President and Treasurer
Distribution Company Presidents
(not pictured)
Robert L. McCabe
- - The Narragansett Electric Company
Lawrence J. Reilly
- - Massachusetts Electric Company
- - Nantucket Electric Company
- - Granite State Electric Company
[PHOTOS OF NEES DIRECTORS]
Left to right: Edward H. Ladd, James Q. Wilson, Joshua A. McClure,
John M. Kucharski, George M. Sage, John W. Rowe, Joan T. Bok,
Charles E. Soule, Paul L. Joskow, Anne Wexler, James R. Winoker,
and William M. Bulger
NEES Directors
As of January 1, 1997
Joan T. Bok
Chairman of the Board, New England Electric System, Westborough,
Massachusetts
- - Corporate Responsibility Committee
- - Executive Committee
William M. Bulger
President, University of Massachusetts, Boston, Massachusetts
- - Audit Committee
Paul L. Joskow
Professor of Economics and Management and Head, Department of
Economics, 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
- - Nominating Committee
Joshua A. McClure
Former President, American Custom Kitchens, Inc., Providence, Rhode
Island
- - Corporate Responsibility Committee
John W. Rowe
President and Chief Executive Officer, New England Electric
System, Westborough, Massachusetts
- - Corporate Responsibility Committee
- - Executive Committee
George M. Sage
President and Treasurer, Bonanza Bus Lines, Inc., Providence,
Rhode Island
- - Compensation Committee
- - Executive Committee
- - Nominating 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
- - Nominating Committee
James Q. Wilson
Professor of Strategy and Organization, 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
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 therefore.
This report is not to be considered as an offer to sell or buy or
solicitation of an offer to sell or buy any security.
[NEES LOGO]
New England Electric System
25 Research Drive
Westborough, Massachusetts 01582
Telephone 508-389-2000
www.nees.com