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New England's Power Developments:
Part I ... the private utility industry

The region's growing power needs and efforts
to stimulate even greater growth have brought
forth bold new plans and proposals from both
public and private sectors of the electric utility
industry. This article reviews the present
utility systems and their plans for the developing market.

E D E RA L

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R E S E RV E
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BAN K

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ENGLAND

BUSINESS REVIEW
New England Power Developments:
Part 1 ... the private utility industry
he New England electric utility industry is
in a period of rapid growth. Since 1945 the
annual peak demand has more than tripled to 8 million kilowatts in 1965. The projected
peak for 1985 is about 27 million kilowatts.
Such growth and the prospects ahead have
caused a decided change in the industry's planning and operations, and more changes are in
the making. But, while past and projected
growth in demand is comparable to the United
States experience as a whole, power rates in
New England remain relatively high and energy
consumption relatively low.

tric development to Maine and neighboring
states. A third, the Yankee-Dixie scheme,
would bring power to New England from the
coal fields of northern Appalachia. Finally, the
Federal Dickey hydro project in northern
Maine would mah a block of energy and peaking power available to the area.

As a result, new proposals have been advanced from outside the industry's private
sector to help bring rates down and increase
energy use. One proposal, advanced by
Vermont's Governor Hoff, as a member of the
New England Governors' Conference, would
tap Canada's vast hydro resources for import
and area-wide distribution throughout New

Existing privately owned systems, now supplying 97 percent of the load, have their own
plans to lower rates and increase energy con sumption. Moreover, utility managements feel
their plans will he carried out at lower cost and
with greater reliability of service for the region
than any of the new proposals. Their plans,
and the current state of the systems on which
they build, are analyzed in this issue. A succeeding issue will examine the new proposals as
alternatives or as increments for serving the
developing power needs. Some plan or comhina tion of plans is optimal for the region. The
region should do its best to seek that optimum.

England. Another, the proposed Maine Power
Authority, would offer large -scale atomic-elec-

Industry Structure

The New England Business Review is produced in the Research Department. John M.
Wilkinson was primarily responsible for the
article, .. New England Power Developments:
Part I ... the private utility industry."

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Dating from 1882 when Thomas Edison'.,
120-kilowatt Pearl Street Station in New York
City began ~erving a one-square-mile area, early
production of commercial power throughout
the country was small-scale and its distribution
was of necessity local. By the turn of the cen-

February 1966
tury, with advancing technology in steamelectric production and particularly with the
development of the transformer which made
transmission practical, the expansion of singlecompany service areas was rapid, and by the
1920's a widespread consolidation of local properties into large utility systems was underway.
Here in New England, waterpower was a dominant force in early development, and hydroelectric energy production from the region's
dispersed watercourses became a natural source
of local power supply for early electric light
companies and industry. Perhaps for other
reasons unique to the Yankee community, besides its geography, small hydro and steam
power systems under separate ownership and
localized management persisted in New England beyond the wave of corporate integration

elsewhere. To a degree, they remain a characteristic of the industry today.
This is not to say that the industry here has
not been altered. From a high of nearly 400
privately and publicly owned operating companies in the twenties, the number declined
steadily over the succeeding three decades.
Still, we begin 1966 supplied by 39 privately
owned operating companies generating power
in 73 thermal and 93 hydro plants. There are
26 murricipal and three rural electric cooperative systems generating all or part of their own
needs in 38 small plants, and 88 municipal and
rural distribution systems that purchase all requirements from other suppliers. Meanwhile,
self-supply by industrial plants remains high
compared to other regions, with over 100

TABLE 1
Major New England Systems
and 1964 Electric Operating Revenues
New E.ngland Electric System

. $185,868,000

Boston Edison Company .
Connecticut Light and Power Company

Hartford Electric Light Company
Central Maine Power Company .

147,494,000
96,928,000
63,260,000

53,735,000

United Illuminating Company

53,130,000

Public Service Company of New Hampshire

41,923,000

Western Massachusetts Companies

38,791,000

Eastern Utilities Associates

38,315,000

New England Gas and Electric Association

34,577,000

Central Vermont Public Service Corporation.

15,835,000

Holyoke Water Power Company .

10,938,000

Bangor Hydro-electric Company.

10,267,000

Green Mountain Power Corporation

7,721,000

Maine Public Service Company .

6,063,000

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New England Business Review
thermal and hydro plants and 777,000 kilowatts
total capacity. The six-state supply, augmented by imports from ew York and New
Brunswick, r.eached a capability exceeding
9,000,000 kilowatts in 1965. In the systems
supplying the public, there are some massive
new boilers and some proud old tea-kettles.
The average size of all stations is about 50,000
kilowatts, and many of the nearly 300 thermal
units still in use are under a thousand kilowatts.
Fifteen major systems have emerged through
consolidations, acquisitions, and mergers as the
principal suppliers now serving about 97 percent of the regional electric load. They are
ranked in Table 1 by 1964 electric operating
revenues. New E!].gland Electric System (NEES), a holding company, controls four operating utilities. Similarly, Eastern Utilities Associates (EUA) and New England Gas and
Electric Association (NEGEA) each control
four operating subsidiaries. Yankee Atomic
Electric, a separate wholesaling company not
listed, is jointly owned by 10 of the major
systems. Three of these - Connecticut Light
and Power, Hartford Electric Light, and Western Massachusetts Electric - have agreed to
form Northeast Utilities, a holding company
parent to the three operating companies. Upon
Federal approval under the Holding Company
Act, Northeast Utilities will become the largest
electric system in New England.
In recent years, power supply on a regional
basis has assumed prime importance for this
traditionally high power cost area, as pressures
for cost and rate reduction have intensified.
In the early postwar period, supply problems
inherited from World War II and antecedent
conditions of the 1930's found most companies
in need of plant and equipment modernization.

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But modest technological advances, diversified
ownership, avoidance of interstate commerce
and attendant Federal rate regulation, and caution in the face of uncertain market growth
delayed significant changes in the production
pattern.
Since the mid-fifties, a pronounced change
has been underway in power system planning,
development and operations, stemming from
intersystem coordination initiated during wartime and since greatly expanded, plus a clearly
accelerating load growth. Since 1955 the average size of thermal unit added to the 15 major
systems has been 126,200 kilowatts, 10 most
recent additions averaged 190,000 kilowatts,
and a 600,000-kilowatt unit is now on order.
Boston Edison's 400,000-kw New-Boston Unit
#1, now on the line, represents in a single
machine more capacity than the total of the
company's additions over a 30-year period from
1915 through 1945. One of the largest stations
- NEES's 500,000-kw Brayton Point station
near Fall River - achieved in 1964 a heat rate
of 8776 btu per kilowatt-hour from its two
machines and was the most efficient station in
the entire United St,ates, burning only 10
ounces of coal per kilowatt-hour. Today, 45
percent of thermal capacity in the 15 systems is
less than 10 years old. More important, these
are the units that produce baseload output,
contributing an even higher percentage to
energy generation than to capacity. The role
of short-term peak-hour supply is relegated to
the older units and the hydro plants.
New England's oldest power producer is still
important. Hydro's "fuel" is the virtually free
and inexhaustible runoff of the watershed, and
the :flexibility of hydro - quick, inexpensive
startup and shutdown by the openin~ and

February 1966
closing of water gates - makes it ideally suited
for short-term peaking. Hydropower also remains an asset in isolated areas of light load
density. Some large plants have been installed
in recent years in such areas, others are being
redeveloped, and other sites remain undeveloped. Nonetheless, the old hydroplants are
expensive to maintain and parts are hard to
come by, so the small ones are being retired.
Two companies, Public Service of New Hampshire and Central Maine Power, are putting
reservoirs for small hydroplants to a higher use
by selling them at a token sum to the State or
to towns for continued use by another burgeoning industry - recreation. And a newer form
of hydro - pumped storage - may hasten the
demise of some surviving remnants of the
region's earliest energy source.

FIGURE 1
1964 LOAD DURATION CURVE
INTERCONNECTED NEW ENGLAND
SYSTEMS
Millions of Kilowatts

Percent

Peak plus 15% reserve

115

Maximum KW-7,513,000

100

90
80

Market Structure
Three basic charateristics of the power
market - load factor, load composition, and
load distribution - and their underlying trends
have significant implications for supply planning, system operations, production costs, and
customer rates. Load factor indicates average
use of demand relative to maximum use during
a time period and is as important to electric
utilities as fully loaded flights are to the airlines. Load building efforts of utilities are
directed as much to improving load factor as
to increasing total demand itself. In addition
to a fixed demand or readiness-to-serve charge,
most rate schedules contain successively lower
energy charges tailored to promote grea_ter use
of demand. In this way, fixed capacity may
he more fully utilized, unit costs lowered, and
rates adjusted accordingly.
The peak demand for kilowatts in New England- the load which systems must stand ready

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50
3

AO
30

Minimum KW-l,93A,000
20
10

OL__

__j__L__--L.-'-----'----'---+---'-~ O

2000

AOOO
AO

6000
60

8000 Hours
80

100 Percent

to serve at all times and in all forms - is increasing at a rate of about 6.5 percent annually.
The noncoincidental peak on all systems (excluding self-generated industrial load) reached
a high of 8,100,000 kilowatts in the Christmas
week of 1965. Energy consumption - the
use over time of kilowatts of power demanded
- was 40,700,000,000 kilowatt-hours in 1965.
Annual load factor - the ratio of average load

New England Business Review
supplied to peak load during the year - was
57.4 percent. While the national average of
other systems throughout the industry is currently about 65 percent and in a rising trend,
ew England's load factor on the average has
remained stable for the past decade. The percentage difference seems slight, yet a 7-percent
improvement in
ew England's annual load
factor by 1980 would represent a yearly increase
in sales of 12 biUion kilowatt-hours.
Figure 1 shows the actual 1964 load duration
curve for the interconnected utilities of this
region. It is seen that almost as much capacity
is required for only 20 percent or less of the
time, just to meet peakload and maintain reserves, as is required nearly all of the time for
baseload, continuous output.
ot so apparent
is the fact that, with capacity in place, incremental energy production is relatively inexpensive. It is therefore desirable to raise the
curve throughout its length relative to the peak,
as well as to raise the peak itself.
Closely associated with load factor, the composition of total load by customer type follows
from the cross-currents of economic and social
development within the region.
ot surprisingly, with ever greater urbanization of a growing population, residential energy use has risen
steadily and now accounts for about 45 percent of power sales. On the other hand,
industrial use has risen by 2½ times since 1945
but is now only 25 percent of total sales, declining from 33 percent since the end of World
War ll. Nationally, it is almost the reverse,
industrial sales being 46 percent and residential
sales 29 percent.
ew England, of course, has
nothing to compare with the massive industrial
concentrations elsewhere.

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As household use of electricity becomes an
increasingly sensitive barometer of this area's
utility growth and a frequently cited indicator
of consumer response to rates, the underlying
trend is of v ital concern to planning and policy.
The national average of residential sales per
customer in 1964 was 4703 kilowatt-hours; in
New England it was 3538 kilowatt-hours. Ten
years ago the difference was not so great. This
region's householder consumed 25 percent less
electricity in 1955, but 33 percent less in 1964,
than the nat ional average. Even so, some systems are only a little below the national average and three systems have slightly exceeded it.
Two of these, Green Mountain Power and
Central Vermont Public Service, offer lower
residential r ates than other systems and receive
power through a contract between the State
and the New York Power Authority. Western
Massachusetts Electric, on the other hand, has
vigorously promoted all-electric residential
heating with considerable success. Vermont
also offers generally lower industrial rates but
the State has not enjoyed the industrial growth
rate of the t h ree southern New England States.
Load dist ribution is far more difficult to
"improve" in terms of economic efficiency than
either load factor or load composition. In
fact, it is rarely altered in the short run except
by a favorable combination of factors leading
to sizabie new economic development. One
of the striking characteristics of the New England load is its concentration near the seacoast.
An estimated 90 percent of total load is within
45 miles of tidewater, along a 300-mile-long
coastal band between Augusta, Maine, and
Bridgeport, Connecticut. The remaining 10
percent is spread over 80 percent of the land
area, a vast inland market with small concen-

February 1966
FIGURE 2
PAST AND PROJECTED PEAK LOAD- NEW ENGLAND ELECTRICAL UTILITIES
Millions of Kilowatts

•
Federal Power Commission
Projection

-----Actual Demand-----

0 ,________.______._____..__________.______._____...._______.______

1945

1950

•Author's

1955

extrapolation

1960

1965

1975

1980

1985

beyond 1980

trations in the upper Connecticut Valley and
in upstate Vermont. The trend is toward a
more highly concentrated demand in the future,
due to forces independent of the power industry. ln increasingly urbanized New England, this basic fact is too often ignored. [ t is
certain to shape future development.
The Federal Power Commission's 1964 National Power Survey forecasts New England
load growth to 1980 as shown in Figure 2.
Peak demand is expected to reach 20,450,000
kilowatts with energy consumption of 104.6
billion kilowatt-hours. This forecast reflects

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1970

the trend toward higher residential and commercial demand and it indicates that the present annual load factor will prevail over the
next 15 years, despite efforts directed toward
its improvement.
[n anticipation of this
market, and with a watchful eye on shifting
market patterns, the principal utility suppliers
are preparing for a growth that will approach
650,000 kilowatts annually by the early 1970's.

Industry-Market Forces and the Cost of
Power
The "high cost of power in New England"
has been a popular topic of discussion for some

New England Business Review
time and remains an issue of valid public concern. Enough comparisons have been made
between power rates here and in the rest of the
ation, and enough prescriptions offered for
curing the high-cost malady, to keep the consumer both confused and ever hopeful. Unfortunately, oft-quoted percentages too seldom
relate to comparable amounts and kinds of
power, types of customers, and locational and
evertheless, a broad differential
use factors.
does exist, and before examining what is
planned or propo ed to remedy the situation,
some light may be shed by summarizing briefly
what has brought it about.
Many elements of cost are involved. first
and perhaps most obvious, without local coal
ew England pays the
mines and oil fields,
freight on fuel brought from distant sources,
and lacking abundant waterpower resources,
reliance on fossil fuels has been heavy. Second,
state and local taxation is substantially higher
in ew England than elsewhere in the Tation.
Property taxes are particularly burdensome
for the capital intensi e electric utility industry.
Third, many systems elsewhere are either themselves exempt from Federal, state, and local
taxes or purchase untaxed power from public
systems. In ew England, on the other band,
most power systems are privately owned.
These utilities pay corporate income taxes.
Their stockholders and bondholders pay a tax
on both dividend and interest income. This
differential taxation largely explains why the
financing costs of private systems are almost
twice those of publicly owned utilities. In
addition, Massachusetts law limits bonded
debt to 50 percent of the capital structure, thus
keeping higher cost equity financing artificially
high. Fourth, today's industry structure, while

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undergoing a transformation, is still plagued
with inefficiencies inherited from earlier times,
causing persistent abnormal expenses for fuel,
operations, maintenance, and a multiplicity of
managements. Administration and General
Expenses alone ·were 2.2 mills per kilowatt-hour
of sales in 1964, 87 percent above the national
industry average. On a cost-per-customer basis
- the more relevant comparison since it costs
about as much to administer a 1,000-kilowattew
hour as a 10,000-kilowatt-hour load the
above
percent
26
were
systems
England
national average. Fifth, construction costs
have always been higher in New England for
many reasons: higher land values for plant sites
and transmission rights-of-way, higher wage
scales, higher transportation costs from supply
points, rough terrain for rural lines, underground cabling in highly settled areas, and
more costly plant and transmission design to
protect against a seasonally severe climate.
Sixth, most of these same reasons impose higher
operation and maintenance expenses as well.
The direct impact of these costs on power
rates has the further indirect effect of discouraging energy consumption, which in itself is
a factor tending to increase costs. The load
duration curve clearly indicates the large
amount of capacity that must be maintained
for only short-time use. This unfavorable
situation is accentuated by two factors not
common to most systems with which New
England is frequently compared. First, due to
climate - some harsh winter days and lack of
widespread need for summer air-conditioning
- the region experiences a sharp winter peak
and lower summer consumption. Many areas
of the country have a summer peak which
matches or exceeds their winter peak. Second,

February 1966
high energy consumption occurs in areas where
heavy industry predominates. In New England, the industry mix is typified by small,
diversified labor-intensive manufactures with
low load factors, in contrast to the high loadfactor industries producing steel, aluminum,
and chemicals. For better or worse, depending
on one's viewpoints, New England was not
endowed with a combination of abundant raw
materials and proximity to national markets
such as is attractive to heavy power-consuming
manufacturers.
This combination of supply and demand
forces has kept power rates where they are.
While rate reductions exceeding $22 million
have been put into effect in the past 3 years,
reflecting cost reductions already achieved,
public pressure for more dramatic results remains strong . Two major efforts by the industry - one little publicized but highly
significant, the other in large part already
announced - show promise of producing such
results. The first is intersystem coordination
on a scale not heretofore accepted. The second
is the industry plan for development.

lntersystem Coordination
Coordination among a group of neighboring
utilities in system planning, development, and
operations can achieve substantial economies.
The essential ingredients are a willingness to
negotiate agreements and a network of strong
interconnecting transmission circuits. When
these exist, the advantages to be gained are
impressive:
• larger, more efficient baseload generators
can be installed for combined load growth
than can be justified for a single company

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• larger, lower cost peaking installations can
be justified, such as pumped storage, to carry
the combined peaks of several systems than
are warranted for individual system peaks
• the most economical location for new
plants can be selected in terms of site, fuel
sources, and combined markets, without regard to company boundaries
• the most economically routed, high-capacity, joint-use transmission lines can be installed, without regard to company boundaries
• load diversity among systems due to time
zone, load type, and seasonal differences
occasions a lower simultaneous peakload
on interconnected systems than the sum of
peaks of separate systems, thereby permitting
systems which share capacity to maintain
lower combined peaking capability
• unscheduled outage diversity (simultaneous breakdown) among systems occasions a
lower simultaneous outage on interconnected
system's than the sum of outages on separate
systems, thereby permitting systems which
share reserves to maintain lower combined
reserve margms
• streamflow diversity throughout an area
may enable two or more systems with hydro
capacity to gain firm dependable hydropower
if water release schedules are coordinated
• two or rnore systems with both hydro and
thermal capacity may save fuel during high
stream runoff periods and enhance firm dependable hydropower in low-flow periods by
exchanging hydro and thermal energy

New England Business Review
• scheduled maintenance capacity and spinning reserve capacity can be minimized and
can be provided by more efficient standby
machines, when two or more systems coordinate their maintenance programs and share
their best operating reserves
• coordinated dispatching of total load of
combined systems assures that load increments are met with the least costly generation and related transmission increments
available
• engineering and administrative cost savings can be realized by the pooling of talent
in planning and operations.
These concepts are not new to the industry;
neither are they costless nor everywhere applicable. Load diversity and streamflow diversity,
for example, are not as significant within a
small region such as New England as between
regions. Similarly, the degree and price of coordination vary together. Therefore, the industry has approached coordination, not for
its own sake, but with a careful weighing of required investments and potential gains.
Accepting as fact the somewhat fragmentary
industry structure, and the natural reluctance
of companies to sacrifice sovereignty, what is
the record of intersystem coordination in this
region? Recognition that the isolated system
could not hope to meet exacting modern standards of economy and service reliability led
some utilities into early but limited forms of
cooperation. Sharing of production, much
easier to arrange and account for than sharing
of transmission, has taken three forms: joint
ownership, unit contracts, and firm contracts.

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Going back at least 44 years, three small operating companies formed Montaup Electric Company (all four now subsidiaries of Eastern
Utilities Associates) to build Somerset power
station in Rhode Island. Capacity of this
joint-ownership venture, now grown from
38,000 to 329,000 kw, is still being shared. Its
modern counterparts are Yankee Atomic Electric Company, jointly owned by 10 companies
and now operating the 185,000-kw "first generation" prototype nuclear unit at Rowe, Massachusetts, Connecticut Yankee Atomic Power
Company with 11 companies participating in a
500,000-kw "second-generation" nuclear unit
now under construction, and Maine Yankee
Atomic Power Company with 11 participants
in a planned 700,000-kw station.
The more frequently employed "unit contract" is sometimes a long-term agreement
ainong two or more systems which relates to
specific generating units financed by a single
system. Price to the company contracting for
a portion of the output is.based on performance
of the unit, so the transaction is normally made
at cost with risk of outages also shared. NEGEA's 550,000-kw Cape Cod Canal unit #1, for
example, will he owned and operated by its subsidiary, Plymouth County Electric, hut output
will be shared equally with Boston Edison,
New England Power (A NEES generating
subsidiary), and Montaup Electric for 33 years.
Actual fixed and variable plant costs (except
fuel) will be divided equally among the four
contracting parties, and fuel expense will he
prorated on an energy-delivered basis. Similarly, Public Service of New Hampshire will
sell 100,000 kw of its scheduled 350,000-kw
Merrimack unit #2 to VELCO, a transmission
subsidiary of three Vermont companies, for

February 1966
distribution in Vermont for 30 years under the
same pricing policy. Neither of the owning
companies nor most participants could have
justified such large units for their own nearterm load growth alone.
Short-term capacity-sharing contracts have
also become common. They also normally take
the form of unit contracts relating to specific
facilities. Less frequently used two-party firm
contracts not tied to unit performance provide
for demand and energy charges and a minimum purchase obligation, such as in bulk
supply contracts between major wholesalers and
smaller distribution systems. As examples of
unit contracts, in 1961 Central Maine Power
arranged to buy 15,000 kw of New England
Power's Brayton Point output in 1964, enabling it to defer construction of its 125,000-kw
Wyman unit #3 for 1 year. In turn, Central
Maine is selling a share of Wyman for 3 years
to Public Service of New Hampshire and
VELCO, permitting deferment of Merrimack
#2 and other Vermont additions. Public Service
of New Hampshire will also buy 50,000 kw for
1 year from Boston Edison, made available
with completion of Boston Edison's 400,000-kw
New-Boston unit in 1965. Meanwhile, Boston
Edison bought 100,000 kw from New England
Power during 1964, but is now selling 100,000
kw of New-Boston #1 to New England Power
for 5 years. New England Power, in turn, sells
to Vermont and buys from Consolidated Edison
of New York and Niagara Mohawk. The
Connecticut companies also have agreements
with neighboring New York utilities.
These are recent examples of a long series of
arrangements proving increasingly useful over
the years with the advent of large generator

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units and higher voltage transmission. Through
some 50 system interconnections of 69,000 volts
or higher, and a number of lesser capacity ties,
the major utilities have also developed informal
bi-lateral and multi-lateral working agreements
or formal contracts covering reserve sharing,
emergency interchange, load frequency control,
mutual support during maintenance outages,
and other aspects of partial coordination over
widespread service areas.
The Connecticut companies with Western
Massachusetts Electric have pioneered in a
more detailed concept of operational integration. As members of the Connecticut Valley
Electric Exchange, or CONVEX, and predecessor pooling organizations dating from the 1920's,
these companies are committed to joint-use
generation and transmission capacity planning,
coordinated design and development, and virtually complete one-system operational integration. The distinguishing feature of their
pooling is multi-system economic load dispatching, whereby a central dispatch office is
empowered to call upon least-costly increments
of production from participating companies,
irrespective of ownership, to meet load increments and similarly, as load declines, to call for
selective unit back-off or shut-down, spinning
reserve (responsive capability on the line but
not generating) and cold reserve.
This procedure has been partially automated
for nearly 10 years by electronic computer control. Knowing the incremental fuel efficiencies
at all output levels for each of 22 thermal generators, as well as transmission losses incurred between each generator and load centers, a computer in Southington, Connecticut acts to minimize the delivered cost of power. By continuous

New England Business Review
PRIVATELY OWNED UTILITIES EXPANSION PLANS

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Nuclear generat i ng stat i on

P u mped hydro generating stat i on

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F o ss i l fuel generat i ng station
345-kv constructed , unde r
construct i on , or planned

O OOOO

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Proposed 345-kv additions

February 1966
TABLE 2
Industry Plans
Generation and Transmission Additions, 1966-72
Map
No.

Plant Additions

Nuclear
1 Connecticut Yankee
2 Vermont Atomic
3 Millstone Point
4 Boston Edison
5 Maine Atomic

Year
Completed

Capability
(maximum kw)

1967
1969
1969
1971
1972

500,000
450,000
600,000
650,000
700,000
2,900,000

Fossil-fueled
6 New-Boston #2
7 Bridgeport Harbor #3
8 Merrimack #2
9 Cape Cod Canal #1
10 Brayton Point #3

1967
1968
1968
1968
1969

Pumped Storage
Northfield Mountain

1971

Transmission
345-kv lines, substations,
and operating equipment

1972

Total additions and costs

night-and-day calculations of the cost level of
all units connected to load, and continuous
scanning of other available units (or other output levels of connected units) for the next-best
source of supply, adjustments are automatically
signalled directly to the operating and on-call
machines.

On occasion, of course, service

reliability takes precedence over strictly economic decisions. Present limited computer
capability precludes economic dispatch of 11
additional thermal and several hydro plants

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Cost
($ millions)

390

400,000
400,000
350,000
560,000
640,000
2,350,000

250

1,000,000

90
6,250,000

800

on the CONVEX systems, and until a larger
computer now on order is installed, manual dispatch of these units will continue. These and
other system functions are performed by means
of leased telephone, carrier current, telecommunications, and micro-wave. The close coordination so far achieved in CO VEX results
in part from concentration of supply and load.
Elsewhere in ew England, greater dispersion of supply, load, and ownership account for
autonomous operations of most systems.
ew

New England Business Review
England Electric, operating widespread hydro
and thermal properties in a four-state area, at
present dispatches its own system manually but
plans for early full automation. Central Maine
Power's new computer center has the capability
for multi-system economic dispatch. For the
past 5 years Boston Edi on has dispatched 16
units within its own system on the same advanced, fully-automated basis as employed in
CONVEX, and has recently taken on the
manual dispatch of the EGEA system as well.
The remaining utilities operate as essentially
separate entities.
evertheless, a considerable
degree of intersystem coordination is achieved
by means of the contracts described and less
formal procedures. Economy energy interchange (sometimes called "economy flow") is
operative on a daily and hourly basis through
instant communication among load dispatchers.
Typ.i cally, a system experiencing increasing
load, but faced with relatively high incremental
energy costs in its own plants (say 5 mills), will
call adjacent systems for quotations until a
block of more economical (say 4 mills) energy
is found for a stated time period, whereupon an
exchange transaction is effected, the flow of
power is metered, and the I-mill saving is split
between buyer and seller.
While substantial benefits accrue from present procedures, potential savings appear even
greater, both from more inclusive system groupings and from more refined, fully-automated
operating decisions. As now constituted, economic loading still relies to a considerable
degree on manual calculations and experienced
judgment, albeit with a high degree of accuracy.
Fuel cost and plant factor comparisons among
neighbor.mg units reveal the extent to which
opportunities for economy flow are foregone.

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With greater instrumentation, the performance
of more alternative choices can be more quickly
and accurately determined in response to fast
changing market conditions. In terms of the
1980 energy forecast, a 1 percent saving in
energy cosL will be worth $3 million annually.
Studies now in progress may lead to adoption
of a Master systems operations center for all
of New England with perhaps four multi-system
Satellite centers patterned after CONVEX on a
sub-area basis. Such an integrated complex
would achieve near-optimal area-wide operational coordination.
Mere size and monolithic structure are not
always guarantees of efficiency. Nonetheless,
it might be argued persuasively from the sole
standpoint of economic efficiency, that an area
the size of New England could best be served
by a single utility system. Regulated in the
public interest, the benefits of complete corporate, engineering, operational, maintenance,
and admin istrative integration would indeed be
considerable. Short of this, since most systems
are simply not for sale, the industry has achieved a degree of coordination which, if
advanced to the levels now contemplated, will
approach the one-system concept. lt is evident
from emerging industry plans that further
progress in this direction is inevitable.

Industry Plans and the Impact on Costs
and Rates
In the Electric Coordinating Council's Planning Committee, the vehicle has been created
for a unified approach to future development.
Representing 13 utility systems, this engineering-economic group is the source of recommendations to corporate management for investment decisions. As an advisory group, it

February 1966
suggests; management prerogative to reject
suggestions is clear. One of its several specialized sub-committees is now engaged in the task
of structuring an area-wide power system to
meet a moving load target to 1990 at lowest
cost and with greatest service reliability. lts
work, labelled a "Study of Alternative Capacity Expansion for a One-System New-England," deals with the design variables already
mentioned: load characteristics; plant location
and size, type and source of fuel, thermal
efficiency, transmission circuits; baseload, peaking and reserve capacity; operating tools and
techniques, system costs and output. Many
alternative designs, or patterns of generation
expansion, are being tested and compared by
computer simulation, in search of the optimal
combination of variables over time for meeting
the objective.
Meanwhile, specific plans have been formulated for nearer-term objectives and some have
already been translated into action programs.
The accompanying map shows generating
additions and associated 345,000 volt backbone
transmission now under construction or reasonably certain of development in the next 7
years. This program reflects a blend of Planning Committee technical recommendations
for the area and managerial judgment of
individual company res ponsib il ities, ca pab ili ties,
and strategy. Table 2 lists generating additions keyed by number to map locations which,
if brought into being, will constitute nearly 45
percent of the total New England power capability, including reserves, available to meet
the predicted 13-million-kilowatt 1972 peak.
Baseloaded to operate at very high plant
factors, they will produce an estimated 60
percent of 1972 kilowatt-hours. Taking into

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account expected plant retirements, over 61
percent of 1972 capability and nearly 75 percent of generation will come from plants less
than 15 years old. Jf retirements were based
solely on unit size and age, the 11 additions
would permit dismantling of over 100 old units
and still meet the 1972 peak load with adequate
reserves.
The $800 million estimate, large as it seems,
is low by comparison to prices of the recent past.
Lt may even be reduced as projects come under
contract, unless inflation destroys the gains
that are clearly in sight. Power supply technology and design are steadily improving.
Keen competition prevails in the equipment and
construction industries, and fossil fuel suppliers
are well a ware of the inroads being made by
nuclear fuel. Recent "turnkey" contracts for
design, equipment and construction of complete
power stations, and recent completion of much
EHV transmission, give evidence that costs
are being lowered.
At prevailing prices and with 75-90 percent
plant fa,c tor operation of the 10 baseload
plants, production costs will be sharply lower
than present levels for the region. When in
full production, these units and the remarkably
low-cost 25 percent plant factor pumped storage hydro will produce at about the following
levels:
Billion kwh

Mills per kwh

nuclear
23.3
conventional
thermal
15.5
pumped storage
2.2
hydro

4.5

41.0

4.9

total

5.0
8.1

New England Business Review
The nominal cost of 345-kv backbone transmission - 4 / 10 of one mill per kilowatt-hour
of new generation - is not included, as this
network will be shared by all present and future
production.
While this massive low-cost increment of
interconnected generation is certain to have
a pronounced impact, it is not an easy matter
to trace the precise effect on power costs to
the ultimate consumer. Any sweeping predictions in this regard concerning any increment
of low-cost power to New England can be
grossly misleading. lt is often overlooked, or
ignored, that all of today's distribution costs
and most of today's high-voltage transmission
and generation costs will remain in the systems
of 1972. lt is therefore appropriate to view the
forthcoming program as a single production
increment delivering power into the existing
systems at multiple points, and to compare
present production costs against projected 1972
production costs with the low-cost increment
averaged in. The reduction or saving must
then be measured against total delivered costs to
ultimate customers. This approach does not
reflect improvements to existing systems by
1972 from plant retirements, more complete
coordination, and other favorable cost factors,
such as depreciated book values, nor does it
reflect the slightly higher costs of operating
present units in 1972 for shorter duration as
newer units take the baseload, but it does provide a close approximation.
The average total delivered cost - production, transmission, and distribution - to ultimate customers in 1964 on the systems serving
97 percent of load was about 24 mills per kilowatt-hour. The production component of this

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total was just over 50 percent, or 12 mills, including prorations of fixed charges and general
expense. With 62 percent (41 billion kilowatthours) of 1972 production at the new level of
4.9 mills, and the remaining 38 percent at the
prevailing level of 12 mills, the weighted average production costs in 1972 should be about
7.6 mills, with no other improvements assumed,
or 37 percent less than in 1964. The reduction
of 4.4 mills would lower the present delivered
cost of 24 mills by about 19 percent. It is clear
that dramatic results can be achieved only by
a truly immense increment of strategically
located new power supply of the magnitude
now contemplated by the industry.
Looking beyond 1972, emerging plans of the
utilities are less certain. Present thermal production sites are said to be suitable for expansion by 5 to 6 million kilowatts for baseload
output, and excellent sites for development of
some two million kilowatts more of very lowcost pumped storage for peaking are said to be
available. l[ the historical trend of increasing

efficiency in power supply continues, even
lower-cost baseload power is in prospect than is
now foreseen.
Furthermore, any pumped
storage peaking will become cheaper with age,
since its major cost component is the pumping
energy supplied to it by thermal generation.

Yankee Power in Transition
A quiet revolution in electric power technology is bringing forth new opportunities,
new concepts, and new plans which promise
dramatic change to historical circumstances
and traditional ways. Publicized regional differences are narrowing as persistent regional
disadvantages are overcome. New England's
utilities are active participants in this revolution, and they propose to put its benefits to

February 1966
work in power markets of the 1970's and 1980's.
Certain implications of the developing situation seem clear:

can participate m the benefits of the onesystem concept or chooses to seek other
solutions.

• By 1972, barring further inflation, the
average price of electricity may be reduced
as much as 25 percent by a massive increase
in productive capacity, a strong high-voltage
transmission network, and closer intersystem and interregional coordination of operations.

• As New England is encouraged by lower
rates to use its power system capabilities
less sparingly, further economies are in
prospect and load may grow even faster
than predicted.

• The one-system concept may be made
operational in most of ew England in the
years ahead, bringing increasing economy
and reliability, and presenting a formidable
private industry yardstick of power costs
and service.
• Small systems, both public and private,
may continue to suffer inherent cost disadvantages unless they are able to participate
more broadly in the one-system concept.
• The vast "inland" market may continue to
suffer inherent cost disadvantages unless it

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New proposals - for a Canadian hydropower import, an Appalachian thermal power
import, a Maine Power Authority, and DickeyLincoln School project - should be examined
in the light of these implications. In this
period of rapid change, one thing seems certain: by 1980, over 90 percent of electric
energy consumed in New England will be generated in power plants not yet in service today.
Herein lies the opportunity to meet an old
problem with new tools. It is an opportunity
for resourcefulness, innovation, and cooperation. It should be viewed by all as an opportunity for real public service.

New England Business Review

Some Economic Indicators
UNEMPLOYMENT RATES
Seasonally Adjusted

Percent

7 .0

Unemployment rates have
shown a dramatic decline in both
the region and the Nation and
have reached their lowest levels
since 1957.

6 .0

5 .0

1965

1964

1963

1966

CONSUMER PRICES
Index

1957 -1959=100

Seasonally Adjusted

113

111

109

107

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Consumer prices on the other
hand have risen to new highs.
The temporary September drop
in Massachusetts prices was concentrated in the food and housing
components.

February 1966

Here's New England MANUFACTURING INDEXES (seasonally adjusted)
1957-59 = 100

NEW ENGLAND
Nov. '65
pDec. '65
Dec. '64

UNITED STATES
Dec. '65
Nov. '65
Dec. '6 4

All Manufacturing

139

137

126

150

148

139

Nonelectrical ~achinery
Electrical Machinery
Transportation Equipment

152
157
183

150
152
176

136
139
145

169
173
161

168
168
157

151
149
140

Textiles, Apparel, Leather

102
103
102
96

108
110
109
100

104
105
114
95

140
140
n.a.
n.a.

139
139
147
110

132
130
141
106

135

132

125

149

147

140

Textiles
Apparel
Leather and Shoes
Paper

Percent Change From:
BANKING AND CREDIT
Commercial and Industrial Loans($ millions)
(Weekly Reporting Member Banks)

Dec. '65
2,234

Nov. '65
0

Dec .'64
+20

Percent Change Fro m:
Dec. '65
49,850

Nov. '65
+ 2

Dec.' 64
+20

Deposits ($ millions)
(Weekly Reporting Member Banks)

6,417

+11

161,991

Check Payments ($ billions)
(Selected Metropolitan Areas) *

217 .3

+21

3,249.6

+16

Consumer Installment Credit Outstanding
(index, seas. adj. 1957-59 = 100)

162.7

+10

197.4

+13

132

4,070

+ 1
+20

DEPARTMENT STORE SALES
(index, seas. adj. 1957-59 = 100)

EMPLOYMENT, PRICES, MAN-HOURS
& EARNINGS
Nonagricultural Employment (thousands)
Insured Unemployment (thousands)
(excl. R.R. and temporary programs)
Consumer Prices
(index, 195 7-59 = 100)
Production-Worker Man-Hours
(index, 1957-59 = 100)
Weekly Earnings in Manufacturing($)

89
112.0
(Mass.)

n.a.

+ 3
-32

62,563
1,255

+ 1
+20

+ 4
-23

111.0

6
4

104.1

114.3

102.25
(Mass.)

110.92

+ 4
+12

OTHER INDICATORS
203,389

-11

3,933,145

89,205

1,679,899

Nonresidential

83,436

Public Works and Utilities

30,748

- 9
-22

+11
+ 1

Total Construction Contract Awards* ( $ thous.)
Residential

Electrical Energy Production (4 weeks
ending Dec. 25th, 1965)
(index, seas. adj. 1957-59 = 100)
Business Failures (number)
New Business Incorporations (number)
* Seasonally adJusted annual rate.
**3-mos. moving averages - Oct., Nov., Dec. ,

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158

62
1,208

+50
p

1,447,454

+ 9
-17

165

1,090

+ 6
+20

805,792

+15

= preliminary

1
5

18,185
n .a.

+13
4

not available

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•

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•

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•

Full text of New England Economic Review : February 1966

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