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Energy Policy & the
Environment Report
No. 11 September 2012
THE ECONOMIC IMPACTS OF CLOSING AND
REPLACING THE INDIAN POINT ENERGY CENTER
Jonathan A. Lesser, President, Continental Economics Inc.
Executive Summary
Located some 40 miles north of New York City, in Westchester County, the Indian Point Energy Center (IPEC) consists
of two operating nuclear reactors, with a combined generating capacity of over 2,000 MW, and one long-retired
reactor. IPEC’s size and location are the key factors in both the power it provides and the decades-long fight to shutter the plant permanently.
Although antinuclear sentiment is not new, opposition to IPEC’s continued operation was galvanized by the September
11, 2001, attacks on the World Trade Center. More recently, the March 2011 earthquake and subsequent tsunami
that destroyed Japan’s Fukushima Dai-ichi nuclear plant complex has reinvigorated the debate over IPEC’s safety and
its environmental impacts.
Because IPEC provides significant quantities of round-the-clock electricity to the New York City area and because of
long-standing constraints that limit how much electricity can be imported from upstate New York, New England,
New Jersey, and elsewhere, closing IPEC would require the development of higher-cost alternatives. These alternatives include: building new natural gas–fired generating plants in southeastern New York (SENY); building additional
high-voltage transmission lines into SENY to increase the quantities of electricity that can be imported into the area;
building renewable generation, such as wind and solar resources; implementing more aggressive energy-conservation measures; or combinations of all four approaches.
This paper examines the economic consequences of closing IPEC. Specifically, we consider the broader economic
impacts of shutting down the plant and replacing its electricity-generating capacity. We evaluate how the resulting
higher electric costs will manifest themselves in reduced economic growth and job losses throughout the state.
We conclude that closing IPEC would increase average annual electric expenditures in New York State by $1.5 billion–$2.2 billion over the 15-year period 2016–30. For a typical residential customer, this would mean an increase
in the household electric bill of $76–$112 each year. The average increase for a commercial customer would be
$772–$1,132 per year. The average increase in industrial customers’ electric bills would be $16,716–$24,517. The
largest increase would be for transportation customers, such as the subway system, which would see increases of
$1.26–$1.85 million per year.
The effects of these higher electricity costs absorbed by customers would ripple through the New York economy,
leading to estimated reductions in output of $1.8 billion–$2.7 billion per year over the 15-year period 2016–30. The
resulting loss of jobs in the state could range from 26,000 to 40,000 per year, depending on the alternative chosen
to replace IPEC.
About the Author
JONATHAN A. LESSER is president of Continental Economics, Inc., an economic and litigation consulting firm specializing in issues affecting the energy industry. He has almost 30 years’ experience in the energy industry, working for
electric utilities, industry trade groups, and government energy policy and regulatory agencies. Lesser has frequently
provided expert testimony before state, federal, and international energy regulators, state legislative committees,
and in federal and state court cases. He holds an M.A. and a Ph.D. in economics from the University of Washington
and a B.S. in mathematics and economics from the University of New Mexico. Lesser is coauthor of three textbooks,
author of numerous academic and trade publications, and an editorial board member of Natural Gas and Electricity.
Acknowledgment
The author gratefully acknowledges Yevgeniy Feyman, who provided research assistance for this report.
I. Introduction
Located some 40 miles north of New York City, the Indian
Point Energy Center (IPEC) consists of two operating
nuclear reactors, with a combined generating capacity of
over 2,000 megawatts (MW), and one long-retired reactor.
IPEC generates about 20 million megawatt-hours (MWh) of
electricity each year—enough to power almost 3 million homes.
[1]
That generation, along with the plant’s location, explains the role
that IPEC plays in ensuring adequate and reliable electric supplies
for the southeast New York (SENY) region. However, the plant’s
reactors and its placement have also spurred a decades-long effort
to shutter the plant permanently.
Of course, antinuclear sentiment is not new. Events such as the
accidents at the Three Mile Island nuclear plant in 1979 and
Chernobyl in 1986, along with concerns about storage of highlevel nuclear waste, have contributed to calls to shutter IPEC.
Additionally, the September 11, 2001, attacks heightened concerns
about the plant’s vulnerability to a terrorist attack. More recently,
the March 2011 earthquake and subsequent tsunami that destroyed
Japan’s Fukushima Dai-ichi nuclear plant complex brought more
attention to questions about the potential risks.
[2]
The safety of IPEC and its environmental impacts have been
addressed thoroughly over the past few years by independent studies performed as part of the plant’s relicensing
process (one reactor’s license expires in 2013 and the
other in 2015; Entergy Nuclear, the owner of IPEC,
has applied for 20-year extensions for both).
[3]
These
studies have addressed numerous scenarios, including
catastrophic possibilities such as earthquakes or
terrorists crashing commercial airliners into the
reactor vessels, as well as more mundane concerns,
such as the environmental impact of cooling water
discharged into the Hudson River. Whether these
studies are accurate and have adequately addressed
all relevant factors (environmental “justice,”
appropriate risk avoidance, etc.) are political issues
outside the scope of this report. Any decision to close
IPEC would have inevitable economic consequences
and would require changes in current practices in
electricity generation and use. Those economic
impacts are the subject of this paper.
The plant’s two operating reactors, IPEC-2 and IPEC-
3, each have a rated generating capacity of about
1,020 MW. By generating some 2,000 MW around
the clock, IPEC provides up to 30 percent of the
New York City area’s base-load electricity (base-load
power is defined as the minimum necessary at any
given time to sustain normal activities). The plant’s
location is crucial to its importance, especially in the
dog days of summer, when electricity demand peaks.
The city, Long Island, and the Hudson Valley region
to its north (collectively designated “southeastern
New York,” or SENY, on the electricity grid) need
local sources of power because there are limits on
the amount of electricity that they can import from
outside. It is a fact of life that IPEC, if shut down,
would have to be replaced. Moreover, there would
not be much time to find substitute sources of power.
If license extensions are denied for both reactors,
alternatives—with a capacity of about 2,000 MW—
would therefore have to be online by 2016.
Those possible alternatives are: (1) building new
natural gas–fired generating plants in SENY; (2)
raising the region’s electricity-importing capacity
by building additional high-voltage transmission
lines into SENY; (3) building renewable generation,
such as wind and solar resources; (4) implementing
more aggressive energy-conservation measures (thus “generating” power by cutting consumption); or
(most likely) combining all four of these strategies
in some way.
All these alternatives would increase the price that
businesses and individuals pay for electricity. If
IPEC’s contribution could be replaced by lower-cost
electricity, we suspect that the plant would already
be closed. IPEC remains open, and its attendant controversies rage on, precisely because there is no way
to replace the plant without creating an economic
burden. This report maps the scope of that burden as
precisely as possible.
Report Organization
Section II of this report provides a nontechnical
overview of how New York’s electric system works,
the challenges of ensuring reliable electricity service
to the region, and IPEC’s role in ensuring reliable
power. Section II also details why electric-system
reliability standards effectively mandate that IPEC be
replaced by other sources if the plant is shut.
In Section III, we examine the alternatives to IPEC:
new generating plants within the region, reduced
demand through conservation, or increased ability to
import power from elsewhere.
Each alternative presents its own set of challenges. For
example, importing more electricity requires adding
high-voltage transmission capacity—a far from trivial
engineering project, rather like adding new interstate
highways or additional lanes onto existing highways.
On the other hand, replacing IPEC with 2,000 MW of
new gas-fired generating plants would require building new gas pipelines because the existing pipeline infrastructure is insufficient to transport that much more
natural gas. Building natural gas pipelines through
heavily populated areas must be done within a complex regulatory framework and, if past experience is
any guide, is likely to spark opposition.
[4]
Similarly, attempts to build new high-voltage transmission lines
into SENY have met with tremendous resistance.
Renewable power does not offer an escape from
these requirements because renewable sources (wind and solar photovoltaics) are inherently intermittent
generators of electricity. On a dark, windless, hot,
humid July evening, demand will spike, and some
nonrenewable alternative must be standing ready
to meet it. Because of this need for reliability, a
commitment to wind and solar power is also a
commitment to new gas- or oil-fired generating plants
and their associated pipelines, which will serve that
essential standby function.
Nor can energy conservation alone replace 2,000 MW
of generating capacity. There are two different forms
of energy conservation: one, “demand response,” addresses an acute, immediate problem. It involves paying industrial and commercial users to turn off power-consuming equipment when directed by the New
York Independent System Operator (NYISO), which
coordinates the state’s electric grid; the other form
of conservation is the more familiar notion of using
less electricity to obtain the same services (for example, using compact fluorescent lightbulbs instead of
incandescent ones or installing more attic insulation
to reduce heat loss in winter and keep homes cooler
in summer; or replacing inefficient air conditioners).
Although both types of energy-conservation measures
are useful, they do not constitute a magic bullet: they
are unlikely to make up for IPEC’s closure and cannot
be relied upon to do so.
Section IV quantifies the costs of various IPEC replacement strategies and examines how these costs
would affect New York’s economy. We have found
that all alternatives would create higher costs that
would reverberate throughout society, increasing the
price of goods and services to consumers, businesses, and industry.
II. How New York's Electric System Works... and How IPEC fits in
A. Why Reliability Standards Were Developed: A Brief History
Reliability standards, which are the underlying
reason that IPEC would have to be replaced
with other generating capacity, were developed in the wake of a power catastrophe. On November 9,
1965, a blackout left 30 million people—in New York,
New Jersey, most of New England, and Ontario—without power for up to 12 hours. The cause was a blown
safety relay on a transmission line that delivered electricity from a dam north of Niagara Falls. The relay, not
unlike a circuit breaker in a typical home, was set to
switch off in the event of an overflow of current, preventing damage to the system. Unfortunately, it had
been wrongly set to “blow” at too low a level.
[5]
On that cold November day, demand for electricity
was quite high. Though its line was not overloaded,
the relay tripped. With its line shut off, electricity
flowed into other transmission lines, which became
genuinely overloaded and shut down in their turn. In
short order, a cascading set of failures left much of
the Northeast in darkness.
This massive failure prompted the formation of the
North American Electric Reliability Council (NERC)
in 1968, as well as ten regional reliability councils
whose mission is to coordinate the activities of independent electric utilities.
[6]
NERC also designed voluntary reliability standards and operating policies so as
to reduce the risk of future blackouts. Some regions,
including New York State, use integrated power
pools, in which the operation of all electric generators is centrally coordinated.
 Despite NERC’s many safeguards to improve reliability, another major blackout struck the region in
August 2003. This one affected significant portions of
the Midwest, Ontario, and the Northeast, including,
once again, New York City.
[7]
In the wake of this new
crisis, new reliability standards were developed—and
this time, they were made mandatory. Today, NERC is
responsible for developing reliability standards, and
the Federal Energy Regulatory Commission (FERC)
enforces them.
[8]
NYISO coordinates the operation of all electric
generators in the state and oversees the operation
of the high-voltage transmission system. Another
state agency, the New York State Reliability Council
(NYSRC), forecasts future electricity demand and,
given transmission system constraints, how much electric generation must be provided from “local”
sources.
B. Why IPEC’s Generating Capacity Would
Have to Be Replaced
An electric transmission system operates like a set
of roads and highways. In and around New York
State, most of the “traffic” leads to SENY, especially to
New York City. However, there are too few electrical
“roads” to handle all these electrons, so not enough
electricity flows to the region—especially when
demand is greatest.
Transmission congestion is most likely to take place
in two specific areas: between upstate and SENY,
called the “UPNY-SENY interface”; and the region
between western New York and eastern New York,
called the “Total East interface.” These interfaces act
like tollgates, allowing only so many electrons to
pass through at a time. Their locations are shown
in Figure 1.
Because transmission east and south of these interfaces
is constrained, the region requires local generating
plants (including IPEC), whose energy does not
need to move along these highways from outside the
region. Figure 2 shows the location of IPEC, which is
the largest single generating plant in SENY.
The NYISO system is divided into 11 load zones,
A–K, as shown in Figure 3. Collectively, Zones G–K
make up what NYISO considers to be the SENY
region. IPEC is located in Zone H. Just south of
Zone H is Zone I, which incorporates the southern
half of Westchester County, including White Plains.
The New York City zone, which includes the
western half of Nassau County, lies south of that.
To the east is Zone K, which incorporates the bulk
of Long Island.
The New York City and Long Island zones have the
greatest electric demand and are the most constrained
of these 11 load zones. This is why generating
facilities must be located in the SENY region, in New
York City, and on Long Island.
 Each January, NYISO publishes the amount of local
generating capacity required in the New York City and
Long Island load zones for the following 12 months
to ensure that reliability standards are met.
[9]
For the
upcoming 2012–13 planning year, NYISO determined
that the amount of local generating capacity in the
New York City zone must be at least 83 percent
of the forecast peak load.
For Long Island, NYISO
determined that the amount of generating capacity
must be 99 percent of the forecast peak load.
Although IPEC is not physically located in either of
these zones, it is “downstream” of the electricity transmission bottlenecks shown on Figure 1.
Therefore, if IPEC were shut down and the capacity
it provides were not somehow replaced, NYISO
could not maintain electric-system reliability at the
required level.
[10]
IPEC provides up to 30 percent of New York City’s
total demand for electricity.
[11]
If IPEC’s output were not
replaced, the resulting decrease in system reliability
would impose significant costs on consumers. Recent
studies estimate that the total cost borne just by New
York City’s power consumers would be over $5 billion
in electric-bill increases over a 15-year period.
[12]
Adding to these direct costs would be the indirect
costs of increased potential for rolling blackouts.
Thus, to maintain system reliability if IPEC’s operating
license were not renewed and the plant shut down
permanently, the equivalent base-load capacity
would have to be available to New York City or the
demand for electricity would have to be reduced.
C. How New York's Electricity Markets Work
NYISO oversees two key electricity markets: one for
installed generating capacity; and the other for energy.
The market for capacity ensures that there is sufficient
power to meet peak summer demand at any given
instant. A power plant may not be operating at full
capacity at a given moment, but it must be capable
of reaching that capacity when demand requires it to
do so. The market for energy involves the trade of
electricity among distributors as needed (distributors
sell unneeded kilowatt-hours or buy from others
when they need more). This market ensures that
there is enough electricity to meet demand over
time. Because of the bottlenecks on transmission into
SENY, there is an overall New York state capacity
market and separate markets for the New York City
and Long Island load zones shown in Figure 3.
Local electric distribution utilities such as Consolidated
Edison (ConEd) are required to have sufficient capacity to meet their forecast peak demands each year,
plus a reserve. They meet this requirement in part with
generators that they own (for example, ConEd’s East
River Generating Station) plus capacity that is purchased from the NYISO capacity market. Because of
the transmission constraints into SENY that we have
already noted, much of that capacity must be located
within the New York City and Long Island zones.
Capacity requirements can also be met with demandresponse resources. These are essentially promises
by companies to reduce power consumption when
NYISO tells them to do so.
[13]
Thus, meeting peak
electric demand can be met by having enough generating capacity (the supply side) or by reducing peak
use (the demand side).
 The NYISO installed capacity (ICAP) market
includes several thousand MW of demand-response resources—a cost-effective source of “capacity” that
is created by cutting demand rather than increasing
supply. This approach is not cost-free. Consider a
manufacturer that reduces its demand for electricity
by shutting down a production line when asked by
NYISO. The electric system gains capacity; but the
manufacturer loses revenue, and the local economy
loses the benefits of its production.
The other market, for energy, allows local electric
distribution utilities to purchase the actual kilowatthours they need to meet customers’ electric consumption requirements each day, or sell unneeded
kilowatt-hours that they may have generated or purchased from other suppliers.
In SENY, the capacity and energy markets will face
increased demand in the next ten years. The current
NYISO forecast projects an additional 2,500 MW of
peak-load growth in the state between 2011 and 2021,
1,800 MW of which stems from projected growth in
the NYC and LI zones, as shown in Figure 4.
NYISO anticipates that peak load will increase by
about 500 MW in the NYC and LI zones by 2014, after
IPEC-2’s operating license expires (barring license
extension), and about 650 MW by 2016, after IPEC-
3’s operating license expires. The region will need
even more locally produced electricity in the future.
III. Closing IPEC: The Alternatives [14]
If IPEC were closed, replacements could certainly
be found to supply the electricity that it generates. But not for free. Every possible means of
making up for IPEC’s 2,000 MW of electrical generation would require large and expensive alterations in
today’s status quo.
The job might require, for instance, the construction
of a significant number of electric generating plants,
relatively close to New York City, and their attendant
infrastructure (for example, extra gas lines for new gas
plants). Alternatively, it might require adding highvoltage electric transmission lines to bring power to
the region from afar. Or it might demand stringent new conservation measures. As we have already explained,
any solution would likely involve some combination
of all these alternatives, and therefore entail some
combination of their negative economic effects.
[15]
This paper will first describe the available alternatives,
noting those which seem most practical. It will then
discuss the costs, according to the best estimates
available for each strategy. We will then turn to the
main original findings of this paper: the effects of
these costs on New York metropolitan employment
and overall economic activity.
Each of the alternatives to IPEC would be costly. An
independent study commissioned by NYISO estimated
that the cost to construct a new 100-megawatt (MW)
gas-fired combined-cycle generating unit in New
York City would be almost $190 million.
[16]
At that
price, replacing all of IPEC with new combined-cycle
units in NYC would require almost $4 billion. In
addition, replacing IPEC with 2,000 MW of gas-fired
generation would require adding new natural gas
pipeline capacity into SENY, over and above what is
already going to be added in an already expensive
and controversial process.
Constructing new generating resources upstate is
significantly less costly than building in New York
City. However, bringing the electricity to SENY
would require new transmission lines. Transmission
lines are multibillion-dollar projects. For example, the
proposed Champlain-Hudson Power Express (CHPE)
line, which would extend from the New York–Quebec
border to New York City, has an estimated price tag
of $2 billion. The West Point Transmission project is
another alternative that would run from Albany south
to Buchanan, where IPEC is located. Although no
cost estimates have been published, the project is
similar in design to the Neptune Transmission project
(and would be developed by the same group of
investors), which extended an undersea transmission
cable between New Jersey and Long Island. The cost
of constructing that project is estimated to have been
$600 million.
[17]
Moreover, proposed new transmission lines have
faced significant opposition in the past. For example,
the developers of the proposed New York Regional
Interconnect (NYRI), which would have delivered
power from upstate New York into SENY, were
opposed by local groups funded by the New York
state legislature itself, as well as opposed by the New
York State Department of Public Service (NYDPS),
which recommended the development of new gasfired generating units in SENY rather than building
a new transmission line. Thus, while sufficient new transmission capacity could be built, the process of
siting, permitting, and constructing new transmission
lines is complex, costly, and far from guaranteed.
 In evaluating alternatives to IPEC, one also needs to
consider the age distribution of existing generating
facilities in the NYC and LI zones. Today, there is
about 9,100 MW of installed generating capacity in
the New York City zone and an additional 5,500 MW
installed in the Long Island zone. However, as shown
in Figure 5, much of this generation is quite old. In the
NYC zone, for example, 60 percent of the generating
plants are over 40 years old. In the Long Island zone,
almost 70 percent of the generating plants are over
30 years old. These plants are typically combustion
turbines that burn natural gas and fuel oil.
[18]
The additional maintenance expenses of older plants,
combined with increasingly stringent environmental
regulations, will likely accelerate retirements, as
did New York Power Authority’s oil-fired Poletti
Generating Station in January 2010. NYISO regularly
assesses the retirement risk of existing plants that may
fail to meet environmental standards. NYISO’s most
recent Reliability Needs Assessment identified over
6,000 MW of capacity in the NYC and LI zones that
falls into the so-called Category 3 risk assessment.
[19]
In short, demand for electricity in southeastern
New York is rising fast, and generating capacity in
the region could well diminish as older plants are
accelerated into retirement. Given this context, it is
vital to understand in detail how IPEC’s 2,000 MW
of electricity might be replaced if the facility were to
lose its licenses.
A. Option 1: Replace IPEC with New Gas-Fired Generating Plants
New natural gas–fired generating units have been
built in SENY, including the NYC and LI zones. The
Astoria Energy II generating facility, for example,
began operation in July 2011. And natural gas is
currently the fuel of choice for electric generating
plants, in part because of a significant decline in
wellhead natural gas prices stemming from rapid
growth in shale gas production. However, building
more such plants to replace the output of IPEC is not
a simple swap.
First, all those additional MW of gas-fired generation
will require constructing new gas pipelines into
SENY. This is because the existing pipeline system is
already at capacity on peak-usage days.
[22]
Adding gas
infrastructure is always costly and is accompanied by environmental and political controversies.
[23]
In
fact, new gas pipeline capacity will be required
even if IPEC is not retired. Therefore, having to add
even more infrastructure to make up for the nuclear
plant would make an already difficult situation even
more daunting.
Second, while NYISO lists thousands of MW of new
generating capacity in its queue of upcoming additions (see box above), not all of that capacity actually
will be built. So the amount of gas-fired generation
required to replace IPEC is very likely even greater
than 2,000 MW.
SENY’s Natural Gas Pipeline Infrastructure
 Natural gas–fired generating units require an adequate gas pipeline infrastructure that is capable of
providing adequate and reliable supplies, not only
to meet the needs for generating plants but also for
consumers and businesses who use natural gas directly. In the past, meeting the demand for natural
gas has been a challenge, especially in extremely
cold weather, when direct natural gas demand has
been greatest. Years ago, at times of peak demand,
natural gas would be diverted from generating plants
to direct-use consumers, and the generating plants
instead burned fuel oil. Because of today’s more
stringent regulations against particulate air pollution,
this stopgap use of fuel oil is severely limited.
Figure 6 shows the natural gas pipeline infrastructure in
the Northeast. The New York City greater metropolitan
area (northern New Jersey, New York City, Long
Island, the NY counties of Westchester, Orange, and
Rockland, and southeastern Connecticut) is served
by six interstate natural gas pipeline companies, with
a combined import capacity of about 4,600 million
cubic feet (MMcf) per day.
[24]
These are: Algonquin,
Iroquois, Millennium, Tennessee, Texas Eastern, and
Transcontinental. Of these six pipelines, Iroquois
provides service to Long Island, including natural gas
for three generating plants. Table 1 provides a short
discussion of each of the six pipelines.
Not all of the capacity on these pipelines is available to
the SENY area. For example, although the Algonquin
pipeline has an overall capacity of 2,400 MMcf/day,
only 1,500 can be delivered into the SENY region.
[25]
According to the 2009 New York State Energy Plan
(NYSEP), three of these six pipelines—Algonquin,
Texas Eastern, and Transcontinental—were already
at capacity in 2009 on peak days.
[29]
By 2018, all but Iroquois are expected to be at capacity, and unmet capacity is projected to be between 40 and 375 MMcf/day
on peak days.
By 2020, annual gas demand in the state is expected
to grow by 66 billion cubic feet, with 80 percent of
this growth projected to be in the downstate New
York region, owing in large part to the addition of
new gas-fired electric generating facilities.
[31]
(These
projections, of course, assume that IPEC will stay
open and continue to contribute its electricity to
the mix.)
The existing pipeline infrastructure will be unable to
meet regional demand by 2018.
[32]
In response, new
pipelines are planned. But these plans do not include
any gas-fired replacement for IPEC. According to the
NYSEP, if natural gas is used to replace all of IPEC’s
generating capacity, the need for additional pipeline
capacity into SENY will double.
[33]
Pipeline Infrastructure Costs and Issues
The U.S. Department of Energy (USDOE) classifies
populated areas where natural gas pipelines exist
as “high consequence areas.”
[34]
Building new pipeline infrastructure through such areas is expensive
because of the additional safety measures that must
be undertaken. Moreover, residents in such areas seldom support new pipelines running beneath them.
[35]
Additionally, the geology of certain areas, including
parts of Westchester County, is not conducive to
building underground pipelines. Specifically, the
bedrock in many parts of Westchester County
extends to the surface, making an underground
pipeline prohibitively expensive to build. In other
areas, building new underground pipelines would
require excavation of old industrial sites that contain
hazardous wastes. Though the costs would depend
on the exact routes of these new pipelines (and thus the precise industrial sites involved), it is safe to say
that cleaning up such sites will add to the already
high cost of high-consequence area gas pipelines.
The amount of gas required to generate at least 2,000
MW of new generation is significant. Assuming that
all these new generating facilities were high-efficiency,
combined-cycle units, we estimate that this generation
would require an additional 330–400 MMcf per day
of natural gas.
[36]
By way of comparison, the Portland
Natural Gas Transmission System, a major interstate
pipeline extending from northern New Hampshire to
southern Maine, has a capacity of 200 MMcf per day.
The amount of natural gas required by generators that
replaced IPEC would require a relatively large pipeline, at least 30 inches in diameter, delivering gas at
pressures of about 850 pounds per square inch (psi).
[37]
How can we reckon the costs of a pipeline of these
dimensions, given the extra expenses imposed by the
region’s population density, geology, and industrial
history? A 2009 study prepared by ICF International
[38]
forecast average U.S. pipeline construction costs
increasing to $60,000 per inch-mile in 2011, escalating
about 2.5 percent per year, with costs in the Northeast
29 percent higher than average, or about $80,000
per inch-mile.
[39]
Given the high cost of constructing
in SENY, including the need to construct in highconsequence areas, we believe that a lower-bound
construction cost estimate is at least $100,000 per
inch-mile. Thus, a 30-inch pipe would cost $3 million
per mile to construct, plus the cost of the compressors
needed to deliver natural gas at pressures of 850 psi,
assuming that it could be sited successfully.
[40]
B. Option 2: Build New High-voltage
Transmission Lines to Increase Imports of
electricity into Southeastern New York and
New York City
Given that the need for local generating capacity is
created by bottlenecks in the system that carries electricity to SENY, a logical alternative to more local electric generation is more transmission capacity to bring
energy from elsewhere. More hydroelectric energy
might be imported this way from Quebec, for example (an idea that the provincial government there
has welcomed). This option would require siting and
constructing new transmission lines into SENY, which
is problematic given the history of proposed lines in
New York. Moreover, current transmission-line discussions do not propose to import only hydroelectric energy. Instead, the most developed and viable
proposals rely on a mix of hydroelectric generation,
windmills, and solar collectors. Non-hydroelectric renewables are the most costly of all sources of electricity, largely because neither sun nor wind is a 24/7
resource; as we mentioned in this report’s introduction, these sources must always be backed up with
gas-fired generators.
Transmission lines are expensive to build, not
least because they typically face significant siting
opposition. For example, the proposed New York
Regional Interconnect (NYRI), a 190-mile-long,
direct-current transmission project from the Edic
substation near Marcy, New York, to Rock Tavern
(see Figure 1), would have increased import capacity
into SENY by 1,200 MW.
[41]
NYRI was opposed by the
New York Department of Public Service and the state
legislature. In fact, the state legislature appropriated
several million dollars to fund an opposition group,
Communities Against the Regional Interconnect. Some
SENY utilities also opposed development of NYRI
because the project would have reduced prevailing
market prices for electricity in SENY. A 2007 study
prepared by Charles River Associates estimated that
NYRI would have reduced average wholesale electric
prices in all of New York State by almost 6 percent,
saving consumers $536 million in 2015 alone and
a total of $3.6 billion over the ten-year period of
2015–25.[42] Despite the estimated savings for New
York’s retail electric customers, NYRI’s application
was rejected by the New York Department of Public
Service in 2009.
Of the other major proposed transmission lines, the
355-mile-long Champlain-Hudson Power Express
(CHPE) is furthest along in the NYISO queue.
[43] CHPE
would deliver up to 1,000 MW of hydroelectric and
wind power from Quebec into the SENY region. Its
planners have sought solutions to the financial as
well as the political challenges of transmission-line
building: they expect to cover $1.5 billion of its estimated $2 billion construction cost through federal
Department of Energy loans, and the line would be
entirely underground or underwater, thus removing
visual impacts. However, the project’s dependence on
wind sources for some of its electricity will require
gas-fired capacity as a backup for days when the
wind doesn’t blow. If it is built, it will entail the expense and controversy involved in building new gasfired generating plants. And if the project is approved,
the current schedule calls for construction starting in
2013 and an in-service date of fall 2016; that is almost
a year after IPEC-3’s operating license expires.
[44]
For
all these reasons, CHPE cannot be counted on as a replacement for electricity lost in the shuttering of IPEC.
C. Option 3: Replace IPEC with Wind,
Solar Photovoltaic, and Hydroelectric
Renewable Generation
Wind generation is the most prominent renewable
generation option commonly discussed as an alternative to IPEC. The other is solar photovoltaic (PV) energy. In addition to these two renewable resource alternatives, hydroelectric generation and biomass are
possibilities, although in-state development of these
last two resources is limited.
Under a 2004 order issued by the New York Public
Service Commission (NYPSC), electric utilities in
the state already are required to meet 25 percent
of their electric needs with renewable resources.
[45]
Replacing all or part of IPEC’s installed capacity and
annual generation with renewable resources would
raise issues of cost (renewables are more expensive
sources, especially in light of decreases in natural
gas prices and the cost of gas-fired generation);
transmission capacity (because wind resources are
more likely to be developed upstate and need to be
transported to the region); and the need to backstop
wind and solar energy with additional gas-fired
generating resources.
As a possible replacement for IPEC, wind-based
generation consists of three types of energy source:
(1) windmills built within SENY that would not require
additional transmission capacity to be developed;
(2) upstate wind generation, which would require
those additional transmission lines; and (3) offshore
wind generation that takes advantage of steadier
wind speeds but that would, again, require new
transmission capacity to be built.
[46]
1. SENY Wind Generation
Currently, 1,261 MW of local (SENY) wind energy
projects are in the NYISO interconnection queue.
[47]
The earliest that any of these projects could be
completed is 2016, and the current online dates all
reflect multiyear delays from their originally proposed
online dates; these projects’ ability to replace the
output of IPEC in a timely fashion is questionable,
at best. Moreover, local wind generation will require additional gas-fired generating capacity to account
for the inherent output variability and maintain
reliability standards in SENY. Thus, this source, in
addition to the challenges involved in solar power,
brings the difficulties associated with building more
gas-fired plants.
2. Upstate Wind Generation
The NYISO interconnection queue lists 3,503 MW of
wind capacity planned for regions outside of SENY.
For this electricity to be made available to SENY (a
bottlenecked region), additional transmission capacity
must be constructed. However, the CHPE project is
the only current upstate-to-SENY transmission line
under development, and, because it is a DC line, no
upstate wind generation will be able to interconnect
with it except at the project’s inception point at the
Quebec–New York border.
[48]
3. Offshore Wind Generation
Some proponents of wind generation have proposed
offshore wind farms as a solution for replacing
IPEC’s capacity. Offshore facilities get stronger and
more consistent wind speeds than do those based on
land, which is a large part of their appeal. However,
offshore wind farms require transmission lines to
take their energy to consumers. Moreover, offshore is
twice as expensive as onshore wind power. Finally,
the economic lifetime of offshore wind generators
is uncertain, owing to limited experience with longterm maintenance costs.
[49]
There are also significant engineering hurdles to
building offshore wind farms. A promising project (a
joint venture between ConEd, the Long Island Power
Authority, and the New York Power Authority) was
recently withdrawn from the NYISO interconnection
queue for being unable to meet its planned construction milestones.
As with any intermittent source of power, all three
categories of wind generation will require nonrenewable generation as a backstop for days when
the blades cannot turn. When the wind is not blowing, fossil fuel electricity is needed to ensure system reliability, which means more power plants and
power lines.
Solar Photovoltaics
Some proponents of shuttering IPEC have recommended using solar PV as a replacement. The 2011
Synapse study discusses the potential for solar energy development under the New York State Solar
Industry Development and Jobs Act, AB 5713-C. This
bill, which has not been passed, would require New
York retail electric suppliers to procure a minimum
amount of solar energy to meet their loads each year,
beginning in 2013. By 2025, the total amount of solar capacity would be about 5,000 MW.
[50]
However,
capacity, as we have mentioned in Part II, Section
C, is not the same as the actual output of a source at
any given moment. Because the availability of solar
power depends on both the day’s weather and the
season of the year, NYISO counts only 33 percent of
solar capacity as available in summer, and 2 percent
in winter. Therefore 5,000 MW of solar PV capacity
can be counted on to replace, at best, only about
one-third of IPEC’s annual output.
[51]
Again, solar PV,
like wind power, requires extensive backup generation from gas-fired plants. Therefore, installing solar
PV would require some combination of additional
gas-fired generation in SENY, plus new gas pipelines
and additional high-voltage transmission capacity to
import greater amounts of electricity from upstate.
It is important to remember that solar PV generation is
not cost-competitive. Solar PV is far more expensive
than even offshore wind. Additionally, solar PV
currently accounts for only 32 MW in the NYISO
interconnection queue. Recently, a 3.6-MW solar farm
was constructed in Manalapan, New Jersey, costing
$17.2 million, or about $4,800 per installed kilowatt.
[52]
The expected annual output from this plant is about
4,500 MWh, enough to power roughly 450 homes.
[53]
Hydroelectric Generation
There is currently 16 MW of hydroelectric generating capacity in the NYISO interconnection queue, all
of which increases generating capacity on the Saint
Lawrence River. None of these projects is local to SENY, so they cannot replace IPEC electricity without additional transmission lines being built. Aside
from what is in the queue, there are no major plans
to implement greater hydropowered generation. So
hydropower will be unable to serve as a reliable replacement resource for IPEC, unless new hydroelectric dams are built in Quebec and their output transmitted into SENY.
In evaluating any renewable resource as replacements
for IPEC, one more factor must be taken into
account. To ensure long-term system stability, NYISO
sets standards on the amount of Unforced Capacity
(UCAP) that any resource can supply to the grid.
[54]
UCAP represents the amount of round-the-clock
electricity generation that a source can be relied
upon to provide. For land-based wind, UCAP is just
10 percent in the summer, meaning that 1,000 MW of
installed wind-generating capacity provides 100 MW
of UCAP. For solar, the highest possible UCAP is 43
percent in summer (and just 2 percent in winter),
which would mean that installing 5,000 MW of solar
PV capacity could provide no more than 2,150 MW of
summer UCAP and just 100 MW in winter.
[55]
D. Option 4: Replace IPEC with Demand-Response and Energy-Efficiency Resources
Yet another proposed alternative to IPEC consists of a
combination of additional demand-response (DR) resources and energy-efficiency measures.
[56]
In essence,
this alternative would address the loss of IPEC not by
adding new resources but by reducing peak electric
demand and overall electric consumption in SENY.
Demand-Response Resources
As we mentioned in Section II, DR resources “produce”
energy by cutting demand at strategic times. NYISO
currently has five DR programs.
[57]
The largest is the
Installed Capacity/Special Case Resource (ICAP/SCR)
program, in which electricity consumers enter bids in a
kind of auction. If a DR resource’s offer clears the market, the owner of the resource will be paid the marketclearing auction price. In exchange, the DR resource
owner (typically, a manufacturer or other large-scale
consumer) agrees to curtail the accepted quantity of
load when called upon to do so by NYISO. At the end
of 2010, 2,498 MW of DR resources were registered under the ICAP/SCR and Emergency Demand Response
(EDRP) programs.
[58]
In 2010, there were a total of 2,239
MW of ICAP/SCR resources in New York State. Of that
total, 773 MW were located in SENY load zones.
[59]
In
2011, the total quantity of these resources in New York
State decreased to 2,173 MW. In SENY, the quantity
decreased by 14 percent, to 663 MW.
[60]
Other types of DR resources can be bid into the
NYISO energy market but are not required to respond
to NYISO’s calls for load curtailment.
[61]
Because these
resources are not required to curtail load when called
upon by NYISO, their value for reliability purposes is
far less than ICAP/SCR resources, which must curtail
when called upon. These last forms of DR resources
cannot be adequate replacements for IPEC.
Energy-Efficiency Resources
In 2008, the NYPSC issued an order requiring the
state’s investor-owned electric utilities to reduce
forecast energy use 15 percent below forecast energy
sales in 2015.
[62]
This requirement is known as the “15
by 15” program. At the time, the NYPSC projected the
amount of required energy savings to be 6.4 million
MWh in 2014 and 7.5 million MWh in 2015 for the
entire state.
[63]
Projected savings from LIPA were 1.8
million MWh in 2014 and 2.2 million MWh by 2015.
Of the investor-owned utilities serving SENY, the vast
majority of energy-efficiency savings are projected to
derive from programs implemented by Consolidated
Edison. This makes economic sense. ConEd not only
has the largest loads; its higher retail rates mean that
more of its customers’ energy-efficiency measures are
cost-effective. For ConEd, the NYPSC has projected
cumulative savings of 2.4 million MWh by 2014 and
2.8 million MWh by 2015.
[64]
Thus, the proposed savings
from electric energy-efficiency programs from both LIPA
and ConEd have been estimated to be about 4.2 million
MWh in 2014 and 5.0 million MWh in 2015, roughly
one-fourth the annual energy generated by IPEC.
The NYDPS has also estimated actual savings through
February 2011. (Energy-efficiency savings cannot be measured directly because many factors—e.g.,
weather and the economy—affect individual customers’ and businesses’ electricity consumption. It
is therefore impossible, in evaluating energy-saving
measures, to say precisely how much power a consumer would have used if those measures were not in
place.) Through February 2011, the NYDPS estimated
total electric savings by the state’s investor-owned
utilities in SENY at about 96,000 MWh, far short of the
targeted savings they had expected, which were over
400,000 MWh.
[65]
Moreover, because energy-efficiency
programs typically target the lowest-cost opportunities first, the cost to obtain additional MWh savings
necessarily will increase over time.
Reducing Peak Demand Must Be the Focus of
Energy-Conservation Resources
Whatever levels of overall electricity savings can be
achieved, any discussion of replacing IPEC with savings must focus not on averages and overall figures
but on peak demand. Electric-system reliability standards require that there always be enough power to
meet the greatest demand possible, even if usage on
a given day is below peak. In SENY, electricity demand peaks during the summer. Therefore, the crucial energy-saving measures are those that contribute
to reducing summer peak demand.
[66]
 The NYISO 2011 Gold Book Report forecasts that, in
the absence of additional energy-efficiency measures,
SENY peak demand in summer 2016 would increase
to 23,526 MW, an increase of about 1,900 MW from
the observed peak in summer 2010. By 2021, NYISO
forecasts summer peak demand to increase by over
3,600 MW, as shown in Figure 7.
[67]
With the state’s energy-efficiency programs, NYISO
projects that energy-efficiency measures will reduce
summer peak growth by 1,414 MW in 2016, resulting
in a net increase over 2010 in peak demand of about
500 MW.
[68]
In 2021, NYISO estimates that peak loads
will be lower by about 1,800 MW, resulting in a net
increase in peak demand of just over 1,800 MW.
These savings are summarized in Figure 7.
For all their merits, energy-efficiency programs can
be problematic for maintaining system reliability
because NYISO has no control over energy-efficiency
savings. Moreover, the savings are all estimated,
so NYISO cannot be sure that they actually exist.
Setting aside those concerns and assuming a bestcase scenario, replacing IPEC’s full capacity would
require energy-efficiency savings to increase from
the currently estimated 1,414 MW in 2016 to over
3,400 MW—a rise of almost 150 percent. Given that
actual energy-efficiency savings are already less than the targeted energy savings, it is unrealistic to expect
these programs to make up for a shutdown at IPEC.
[69]
E. Projected Costs of Replacing IPEC
We have reviewed some of the most important practical, political, and administrative difficulties posed
by all possible methods of replacing IPEC’s electrical
generation capacity. Hovering over all of them is the
issue that we will now examine: the cost of electricity. Replacing IPEC will impose extra expense on
consumers—and not only in SENY. New York State’s
electrical system is a single, integrated unit, so the
extra expense of living without IPEC would be borne
by all the state’s citizens.
As a practical matter, replacing IPEC would not involve choosing one option—new plants or transmission lines or energy efficiency; it would involve all
three strategies in some combination. That makes it
impossible to estimate the cost of every possible combination of replacement resources: there are simply
too many. Moreover, costs will be site-specific. For
example, replacing IPEC with gas-fired combined-cycle generating units at the IPEC site could have a significantly different cost from locating those units elsewhere in Westchester County or in New York City.
Furthermore, the overall replacement cost for a given
combination depends on how the entire NYISO system operates. So building new transmission lines to
import power from upstate New York would change
how upstate generators operated, requiring an analysis of the costs of specific generating units.
To model an integrated electric system, which links
hundreds of generating plants in New York State and
beyond, is a challenge; yet it can be done. The most
accurate method available for estimating the projected
costs of replacing IPEC is the use of comprehensive
production-cost models.
Such models simulate the operation of the entire
NYISO system, incorporating every generating facility
in the state, as well as imports from Canada, New
England, and the mid-Atlantic states. The models also
account for the NYISO transmission system, including
existing bottlenecks that limit the flow of lower-cost
electricity into SENY. The models can simulate the
effects of unexpected events, such as unplanned
outages at generating units or individual transmission
lines. Such modeling is critical because it is the basis
for determining whether a given alternative to IPEC
will meet reliability standards.
We are aware of only one study that has used a detailed production-simulation approach to evaluate
the impacts of shuttering IPEC; it was performed by
the Charles River Associates in 2011.
[70]
Although no
simulation model can account for all possible contingencies, the CRA study is by far the most comprehensive analysis currently available.
The CRA study clearly demonstrated that shutting
IPEC without a replacement is not a realistic option.
Not only would the increase in wholesale energy and
capacity market prices increase the costs paid by retail electric customers throughout the state by over
$2 billion per year; it would lead to unacceptable
reductions in system reliability by 2016. Thus, IPEC
must be replaced with a combination of resources
that would provide the same quantities of energy and
capacity: about 20 million MWh and 2,000 MW of
installed capacity.
[71]
Moreover, if the plant is to be
closed, a sufficient quantity of these alternative resources must be ready by the time IPEC-3’s operating
license expires in 2015 to ensure that system reliability standards are met.
The CRA study examined three alternative scenarios
to replace IPEC, as well as estimated the additional
costs of a “do nothing” option. Because the number
of potential replacement scenarios is almost limitless,
the CRA study selected these three scenarios to
bracket the replacement cost estimates, based on the
most likely possible combinations available:
- CC LHV + NYC. Construction of two 500-MW
high-efficiency gas-fired generators known as
“combined-cycle units”: one in NYC and the
other in the Lower Hudson Valley (LHV);
[72]
- CC LHV. Construction of two 1,000-MW
combined-cycle units replacing IPEC directly in
the SENY area; and
- Low Carbon. Construction of a 1,000-MW HVDC
(high-voltage direct-current) line (similar to
the Champlain-Hudson Power Express line)
connecting into NYC, plus a 500-MW offshore
wind farm.
 Each option assumed that NYISO’s projected energyefficiency savings, as shown in Figure 7, would be
obtained.
The CRA study estimated the cost impacts in the
NYISO capacity and energy markets over a 15-year
period between 2016 and 2030, as shown in Figure
8. Although these are wholesale cost impacts, they
would eventually be paid by retail customers.
CRA estimated that doing nothing, in addition to
violating reliability requirements, would increase
wholesale electricity costs by over $2.2 billion per
year. The study found that the least costly of the
three options would be Option 1. Under this option,
the average annual wholesale cost increase would
be $1.46 billion per year for the 15-year period.
Option 3, which CRA deemed a “low carbon”
alternative, would increase costs by about $1.65
billion per year.
Over the entire 15-year period, CRA estimated the
increase in wholesale energy and capacity costs to be
$22 billion under Option 1. Option 3 would increase
costs by $24.7 billion over the 15-year period.
Table 2 shows the estimated annual cost impact per
customer, for each customer class, using published
data on the number of customers and electricity usage per customer in 2010.
For a typical residential customer, this would mean
an increase in the home’s electric bill of $76–$112
each year. The average increase for a commercial
customer would be $772–$1,132 per year. The average increase in industrial customers’ electric bills
would be $16,716–$24,517. The largest average increase would be for transportation customers, such
as the subway system, which would see increases of
$1.26–$1.85 million per year.
These estimates do not include the costs of additional
natural gas pipelines, high-voltage transmission lines,
or additional nonmarket subsidies that would need to
be paid to developers for the projects.
[73]
These could
add several billion dollars to the projected cost increases and, again, would be paid by all retail customers.
IV. Economic Impacts of Closing IPEC
As previously described, IPEC plays a vital role
in providing reliable electricity to the southeastern New York region, and therefore benefits all of New York State by helping to keep electricity prices down and contributing to the security of
the state’s electricity grid. The plant cannot be closed
without finding some way to replace its 2,000 MW
of generating capacity. And every possible replacement strategy—more power plants, more transmission lines, a turn to renewable resources, more energy-conservation efforts—would have a significant
impact on the state’s economy.
In this section, we will relate these various impacts to
form a picture of the likely economic consequences
for all New Yorkers of closing Indian Point. Some
impacts of closing IPEC would be localized, while
others would affect the entire New York economy.
If the operating licenses at the two units are not
renewed, more than 1,100 IPEC employees will lose
their jobs by 2016. That would clearly affect the local
economy of Westchester, Dutchess, and Orange
Counties, where the majority of IPEC employees live.
Some of these jobs would be replaced, depending on
whether the plant was decommissioned immediately
or put into what is called “SAFSTOR,” a form of
delayed decommissioning that allows radiation levels
in the reactor to decrease over time, reducing the
difficulty of decommissioning.[74]
Second, beginning in 2016, Entergy would no longer
purchase goods and services in New York to maintain the plant. Those expenditures are estimated to
be about $60 million per year.
[75]
Again, the reductions in purchases would be mitigated somewhat by
purchases related to decommissioning the plant, depending on when decommissioning commenced.
Third, IPEC’s closure would mean a loss of $25
million in property-tax payments to Westchester
County, as well as lost income taxes paid to the
state. There would be other local tax effects as well.
For example, Entergy pays the overwhelming majority of the property taxes collected for the Hendrick
Hudson Central Schools.
Fourth, depending on the alternative resources developed to replace IPEC, there would be local construction impacts and additional maintenance expenses.
For example, if IPEC were replaced with a natural
gas–fired, combined-cycle generating plant built at
the same location, there would be several years of
construction activity, ongoing maintenance expenditures, and so forth. There would also be construction
activity associated with the new gas pipeline capacity
that such a plant would need.
By far, the largest, longest-lasting, and most widespread economic impact of closing IPEC would arise
from higher electricity prices because electricity is
such a fundamental component of the U.S. economy.
This is the impact that we focus on here.
According to data published by the U.S. Energy
Information Administration, New York businesses
and consumers spent over $21.7 billion for electricity in 2009.
[76]
Based on the CRA analysis, shuttering
IPEC could increase electric costs by as much as 10
percent per year.
When businesses and consumers pay more for
electricity, they have less money to spend on other
goods and services and investments that increase
economic output. Moreover, goods and services
whose production requires electricity increase in
cost. So businesses and consumers have less money
to spend on goods and services, which cost more
to produce. Closing IPEC, then, would impose the
equivalent of a tax on consumers and producers that
would, as tax increases do, reduce economic growth.
The adverse economic impacts of higher electric
prices have been recognized by energy regulators.
For example, in rejecting a proposed power purchase
contract between Deepwater Wind (a small offshore
wind development) and National Grid in April
2010, one reason cited by the Rhode Island Public
Utilities Commission was the job-killing effects of
higher electric prices: “It is basic economics to know
that the more money a business spends on energy,
whether it is renewable or fossil based, the less
Rhode Island businesses can spend or invest, and
the more likely existing jobs will be lost to pay for
these higher costs.”
[77]
Of course, alternatives to IPEC will require new construction, which would create short-term economic
lift. For example, building new combined-cycle generators would mean hiring construction workers,
purchasing supplies, and so forth. However, these
short-run economic impacts would not offset the
long-run economic impacts of higher electric prices,
which would reverberate throughout the New York
State economy. Because the focus of this report is
these long-run economic impacts, we did not model
the economic impacts of one-time construction projects triggered by an IPEC closing.
A. Modeling Economic Impacts
Because the U.S. economy is complex, it is probably
impossible to predict how specific policies will
change output and employment in every industry
over many years. (Some 20 years ago, for example, it
would have been difficult to estimate the economic
impacts of the Internet, which has created whole
new industries.)
The challenges of modeling a constantly changing
economy are so complex that many economic
impact studies rely on so-called static models, which
are based on a snapshot of the economy at a single
moment in time. These models are called “inputoutput” models (I/O).
[78]
Often, I/O models are used to estimate the economic
impacts of constructing and operating new facilities,
including electric generating facilities.
[79]
For example,
to estimate the economic impacts of building a new
combined-cycle generator, an I/O model would
allocate the expenditures for that construction to
various sectors of the economy (cement, turbine
manufacturing, wire, wages for construction workers,
etc.) and then determine how those expenditures
would ripple through the economy.
How an Input-Output Model Works
Input-output analysis traces the interdependencies of
an economy—specifically, the sales and purchases of
goods among all sectors of an economy.
[80]
For example, constructing a new high-voltage transmission
line will require the purchase of concrete that will be
used as foundations for transmission towers. But to
manufacture that concrete, firms must purchase inputs including sand, gravel, and electricity. Similarly,
transmission towers will be made of steel that is
manufactured in steel mills that use iron ore, which
is mined by other firms. Moreover, construction requires the use of many workers who then spend
their wages on all varieties of goods and services. An
input-output framework is designed to trace all those
relationships. Figure 9 shows the general analytical
framework for an I/O model.
 In an I/O model, a local economy (which can be a
county, state, or multicounty or multistate region)
is broken down into manufacturing and mining,
commercial services, and agriculture. There is also
a household sector and, in some cases, a separate
government sector. Purchases outside the local
economy are considered “leakages.” On the other
hand, sales by business and industry of goods and services to outside the local economy are treated
as external demand. External demand increases the level of economic activity within the local
economy.
There are also household impacts. Households in the
local economy purchase goods and services from local
industries, as well as from the broader external economy. Moreover, households outside the area purchase
goods and services from firms within the local economy. A model that does not include this household
spending represents only impacts from activity among
businesses and the government (these are designated
“Type I impacts”). If households are included in the
model, they represent “Type II impacts”: all Type I
impacts plus the effects of consumer spending. Type
II impacts include changes in household spending
that result from policy changes, such as changes in
income-tax rates, as well as how changes in industrial
output affect wages paid and expenditures that households make on goods and services.
For each sector of the economy, the I/O model traces
employment and wages. Thus, concrete manufacturing within the local economy may require an average
of, say, ten employees for every million dollars of
concrete produced, while grocery stores may employ
30 people for every million dollars of retail sales.
The IMPLAN Model
We have adopted one of the most well-known
economic impact models, the IMpact for PLANning
(IMPLAN) model.
[81]
IMPLAN is the most widely used
I/O model and is frequently employed by federal and
state government agencies.
The IMPLAN model divides the U.S. economy
into more than 500 separate economic sectors in
agriculture, manufacturing, commercial services, and
government. With these units of data, the model
creates state- and county-level values by adjusting
the national-level data to account for local conditions.
The model estimates imports and exports, using what
are called “regional purchase coefficients” (RPCs).
An RPC measures the proportion of the total supply
of a commodity or service that is produced locally.
The larger the RPC value, the higher the percentage
of total regional demand that is met through local
supplies and the fewer expenditures that “leak out”
of the local economy. Naturally, the larger the local
economy, the larger will be the RPC values. RPCs
are important for estimating the economic impacts
of higher electricity prices because the greater the leakages out of the New York economy, the less the
overall impacts will be in the state.
B. The Economic Impacts of Higher
Electric Prices
We used IMPLAN, combined with the CRA analysis, to
estimate the annual economic impacts to New York
State from higher electric prices, as a consequence of
a closure of IPEC, from 2016 to 2030.
[82]
Specifically,
we estimated how higher prices will lead directly
to reduction in overall output in the state and to
reduction in state employment. Table 3 presents the
estimated decreases in overall state economic output
under the four CRA scenarios.
As Table 3 shows, the alternative in which combinedcycle units were built in the LHV near IPEC and in
New York City would result in an average annual
loss of economic output of $1.8 billion over the 15-
year period. Failing to replace Indian Point, which
would lead to higher electric prices and reliabilitystandard violations, would reduce state output by an
average of $2.7 billion over the 15-year period. The
low-carbon alternative would result in just over $2.0
billion per year in lost economic output.
Table 4 presents our estimate of consequent annual
job losses throughout New York State.
[83]
As shown,
under the alternative in which combined-cycle units
are built in the Lower Hudson Valley and New York
City, the average annual job loss due to IPEC closure
in the region would be more than 26,500. If IPEC
is not replaced with other generating capacity, job
losses would average more than 40,000 per year. The
low-carbon alternative would raise electric prices and
lead to almost 30,000 lost jobs per year.
Some have criticized I/O modeling for failing to
account for how consumers and businesses adjust to
changing prices. If the price of electricity increases, a
manufacturer is more likely to install higher-efficiency
motors, while consumers may be more likely to
purchase more energy-efficient appliances. Since I/O
models use a static snapshot of economic activity
on a particular date, they cannot, by definition,
account for cascades of change as people respond to
economic signals.
[84]
This objection does not apply to our analysis. First,
we have also used the CRA model, which does
account for the impacts of changing electric prices
and technologies over time, by incorporating the energy-efficiency savings estimated by NYISO. Thus,
over the 15-year modeling period, energy-efficiency
improvements are already reflected in how goods
and services are produced, including the amount of
electricity required. Second, although the total dollar
impacts are large in our model, the marginal increases
in electricity prices are fairly small. Therefore, priceinduced changes in electricity consumption would be
small, as well.
[85]
V. Conclusions
New York’s electric system is highly complex,
and IPEC is a critical component of that
system. Not only does IPEC provide 30
percent of New York City’s electricity; it helps ensure
that the system operates safely and reliably.
If the plant is to be closed, New York must have
alternative resources in place by the time IPEC-3’s
operating license expires in 2015. Doing nothing to
replace IPEC would result in all New York electricity
consumers—not just those in southeastern New York
and New York City—spending over $30 billion more
for electricity over the subsequent 15 years. It would
also increase chances of blackouts, causing the state’s
system to violate its own standards for reliability.
All alternatives for replacing IPEC are limited and
costly. Each comes with its own set of challenges
and trade-offs. But each will result in higher electric prices for everyone in New York State. Those
higher electric prices will have adverse impacts on
the state’s economy, resulting in the loss of thousands of jobs. Moreover, the alternatives—whether
building new gas-fired generating plants or new
transmission lines to bring in power from upstate
New York and beyond—would all face major siting
and infrastructure issues, as well as opposition from
various constituencies.
Whether these trade-offs are greater than the benefits
of closing IPEC is for New York politicians and policymakers to decide. But they should be under no illusions that closing IPEC will be painless. It will not be.
Appendix (View PDF)
ENDNOTES
1. Based on data published by the U.S. Energy Information Administration (EIA), average use per residential customer in the
New York metropolitan area in 2010 was about 7,300 kWh.
2. In response to the Fukushima disaster, the U.S. Nuclear Regulatory Commission (NRC) released a new seismic study on
January 31, 2012, to help nuclear plant owners assess the ability of their plants to withstand earthquakes.
http://www.nrc.gov/reading-rm/doc-collections/news/2012/12-010.pdf.
3. See, e.g., ISE Panel, Indian Point Independent Safety Evaluation, July 31, 2008. See also NRC, Generic Environmental
Impact Statement for License Renewal of Nuclear Plants, Supplement 38, Regarding Indian Point Nuclear Generating Unit
Nos. 2 and 3, Final Report, Main Report and Comment Responses, NUREG-1437, December 2010. See also
http://www.nrc.gov/reactors/operating/licensing/renewal/applications/indian-point/ipec_lra_1_2.pdf.
4. See Mireya Navarro, “Pipeline Plan Stirs Debate on Both Sides of Hudson,” New York Times, October 26, 2011.
5. E.g., a typical electric circuit in a home is rated at 20 amps, which means that it will not trip unless the current flow is
greater than that. If a refrigerator draws, at most, 15 amps of power on such a circuit, all will be well. However, if a
10-amp circuit breaker is mistakenly installed on the circuit, the circuit breaker will trip when the refrigerator compressor
switches on. In essence, this is the trouble that caused the 1965 blackout.
6. In 2006, NERC became the North American Electric Reliability Corporation.
7. For a discussion, see Final Report on the August 12, 2003 Blackout in the United States and Canada: Causes and
Recommendations, U.S.-Canada Outage Task Force, April 2004. https://reports.energy.gov/BlackoutFinal-Web.pdf.
8. In 2006, FERC issued a Notice of Proposed Rulemaking (NOPR), accepting many of the reliability standards proposed by
NERC. See Mandatory Reliability Standards for the Bulk-Power System, Docket No. RM06-16-000. The “bulk” power
system refers to the system of generators and high-voltage transmission lines, which deliver electricity to local retail
distribution systems that provide electricity to individual customers.
9. See NYISO, “Locational Minimum Installed Requirements Study,” January 12, 2012.
http://www.nyiso.com/public/webdocs/services/planning/resource_adequacy/LCR_OC_report_final.pdf.
10. A recent study by Synapse Energy Economics downplays IPEC’s need to maintain reliability because of additional
generating capacity in New York City and Long Island. See “Indian Point Energy Center Nuclear Plant Retirement
Analysis,” October 17, 2011 (hereafter, “2011 Synapse study”). http://www.synapse-energy.com/Downloads/SynapseReport.2011-10.NRDC.Indian-Point-Analysis.11-041.pdf. The report fails to acknowledge generator retirements,
such as the New York Power Authority’s 926 MW Poletti unit, which was retired on January 31, 2010, as part of an
agreement to address environmental concerns. NRG plans to retire its seven Astoria units at the end of 2014. See NYISO
2011 Load & Capacity Data, Gold Book, p. 63. http://www.nyiso.com/public/webdocs/services/planning/planning_data_
reference_documents/2011_GoldBook_Public_Final.pdf.
11. PlaNYC 2011, p. 117. http://nytelecom.vo.llnwd.net/o15/agencies/planyc2030/pdf/planyc_2011_planyc_full_report.pdf.
12. CRA study, pp. 63–64, table 35. http://www.nyc.gov/html/dep/pdf/energy/final_report_d16322_2011-08-02.pdf.
13. For a discussion of demand-response resources, see Potomac Economics, 2010 State of the Market Report for the New York ISO Markets, July 2011 (hereafter, “2010 SOTM report”).
http://www.potomaceconomics.com/uploads/nyiso_reports/NYISO_2010_Final.pdf.
14. A number of potential legal issues are associated with closing IPEC, involving both state and federal jurisdictional
issues and power system reliability. Discussion of these issues is beyond the scope of this report.
15. The 2011 Synapse study misleadingly concludes that, if IPEC is retired, “there is likely to be no need for new capacity
to meet reserve margin requirements until 2020 at the earliest” (p. 26). This conclusion is based on a comparison
of statewide reserve margins with and without IPEC (see, e.g., Figures 2.3 and 2.4, pp. 10–11, of the 2011 Synapse
study). This comparison entirely ignores the transmission constraints into SENY, which is precisely why “doing
nothing” is not an option if IPEC is shuttered.
16. NERA Economic Consulting, Independent Study to Establish Parameters of the ICAP Demand Curve for the New York
Independent System Operator, July 1, 2010. http://www.nyiso.com/public/webdocs/committees/bic_icapwg/meeting_
materials/2010-07-16/Demand_Curve_Study_Report_DRAFTV1_07_16_2010.pdf.
17. See http://www.eif.com/newsNeptune070207.html.
18. Natural gas is the primary fuel for most of these plants. However, many burn no. 2 fuel oil as a backup. A few plants,
including Poletti, burn no. 6 fuel oil. Because of state and federal environmental regulations limiting particulate
emissions, burning oil is severely restricted.
19. For Category 3 generating plants, the cost of capital improvements to comply with environmental standards is much
higher than routine maintenance-related annual capital expenditures. See NYISO 2010 Reliability Needs Assessment,
pp. 44–45.
20. See NYISO, “Steps in the NYISO Large Facility Interconnection Process,” rev. 2010. (This process applies to new
generating plants larger than 20 MW and all new merchant transmission lines.) http://www.nyiso.com/public/
webdocs/services/planning/other_nyiso_interconnection_documents/steps_nyiso_large_facility_interconnection_
process.pdf.
21. Because proposed facilities can interact, the additional transmission upgrades needed for a single facility can change,
depending on what else is developed. Hence, NYISO examines all facilities proposed for a given year, and determines
the upgrades that will be needed for all of them together.
22. See 2009 New York State Energy Plan, pp. 68–69.
http://www.nysenergyplan.com/final/New_York_State_Energy_Plan_VolumeI.pdf.
23. Adding thousands of MW of new gas-fired generating capacity will further expose New York electric consumers to
greater volatility from natural gas price swings. Although natural gas prices have dropped precipitously because of
lower economic growth and the increase in shale gas supplies, New York policymakers have expressed concern about
a too-heavy reliance on natural gas–fired generation. E.g., in 2009, NYSEP stated: “Based on the natural gas modeling
runs, the natural gas system appeared to be strained with conditions such as: (1) Indian Point being retired and replaced
by a combined cycle natural gas plant; (2) a significant amount of repowering of downstate dual fuel units that use
residual oil as a backup; (3) a much colder than normal winter; and (4) and a combination of the three.” (NYSEP, Energy
Infrastructure Issue Brief, p. 2; italics added). http://www.nysenergyplan.com/final/Energy_Infrastructure_IB.pdf.
24. U.S. Energy Information Administration, "Natural Gas Pipeline Capacity & Utilization."
http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/usage.html and author calculations.
Published EIA data reflect pipeline capacity through 2008. We have updated these data to incorporate subsequent
pipeline capacity additions—notably, the expansions on the Algonquin and Tennessee systems, as well as the
Millennium Pipeline, which commenced operation in late 2008.
25. See http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/northeast.html.
26. For a map of the proposed project, see http://www.spectraenergy.com/content/inline-images/Maps/map_NJ-NY_full.
jpg. The project is designed to deliver Marcellus shale gas into New York City and is opposed by environmentalists and
several New York City Council members.
27. Millennium replaced an existing 261,000 MMcf/day on the Columbia Pipeline.
28. Includes the Tennessee 300 expansion.
29. NYSEP, Natural Gas Assessment (2009), p. 33. http://www.nysenergyplan.com/final/Natural_Gas_Assessment.pdf.
30. Ibid. The “extreme cold” scenario models natural gas demand based on the weather conditions that prevailed in
the winter of 1977–78. Under this scenario, unmet natural gas demand is lower than the “reference” scenario
because the NYSEP model assumes that correspondingly high natural gas prices will reduce natural gas demand
for electric generation. In light of greater environmental restrictions on burning fuel oil, retirements of coal-fired
units in PJM, a Regional Transmission Organization (RTO), due to new EPA regulations governing mercury, and
generally lower natural gas prices because of shale gas production, we expect that this assumption will no longer
hold. Thus, we expect unmet demand to be greater than projected by NYSEP under an “extreme cold” scenario.
31. Ibid., p. 43.
32. With or without Indian Point, capacity will not be enough to meet demand. It is important to distinguish natural
gas supply from natural gas capacity. While the natural gas may be there, pipelines need to be able to handle the
increased volume of natural gas.
33. See NYSEP, Natural Gas Assessment (2009), p. 43. http://www.nysenergyplan.com/final/Natural_Gas_Assessment.pdf.
34. 49 C.F.R. § 192.903 provides the definition of a “high consequence area.”
35. E.g., there is significant opposition to Spectra Energy’s proposed NJ-NY expansion, which would be built under the
Hudson River. There have been previous attempts to site pipelines under the Hudson; but because of environmental
opposition, none has succeeded.
36. Combined-cycle generating units typically have heat rates (i.e., the number of Btus of energy input required to produce
one kWh of electricity) of 7,000–8,000 Btus/kWh. (The actual operating efficiency depends on numerous factors, including
outside air temperature and whether the plants are operating continuously or cycling on and off.) Assuming 7,000 Btus/
kWh, 2,000 MW would require (2,000 MW) x (1,000 kW/MW) x (24 hours) x (7,000 Btus/kWh) = 336 billion Btus/day.
Because one cubic foot of natural gas is approximately 1,030 Btus, that translates into about 330 MMCF per day.
37. Another issue that has arisen on very cold days, when the demand for natural gas is highest, is lack of sufficient
pressure to operate gas-fired generators. Because so much gas is diverted for direct usage—such as for residential
customers—that pipeline pressure drops below the level that the generators can operate.
38. ICF International, Natural Gas Pipeline and Storage Infrastructure Projections Through 2030, Report prepared for
INGAA Foundation, October 20, 2009 (ICF 2009). http://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&c
d=3&ved=0CDMQFjAC&url=http%3A%2F%2Fwww.ingaa.org%2FFile.aspx%3Fid%3D10509&ei=DJBCT5rrBuqkiQL
bk-DxDg&usg=AFQjCNE0Fak_mTvwQHZb1Co-SvpOy-gfLg&sig2=EkeIOrFCkVKcJc3wQfLQ8g.
39. Ibid., p. 49. E.g., at $60,000 per inch-mile, a 30-inch pipeline would have a construction cost of $1.8 million per mile.
In 2008, average costs were $100,000 per inch-mile, owing to the high cost of steel.
40. According to the U.S. Energy Information Administration, the average compressor motor was just over 14,000
horsepower (hp). At an average cost of $1,800 per hp (based on the ICF 2009 report for the Northeast), that implies a cost of $25 million for a compressor. Typically, compressors are needed every 40–100 miles along a pipeline,
depending on the pipeline pressure.
41. The author of this report testified on behalf of NYRI in a proceeding before the New York State Department of
Public Service. A copy of that testimony can be found at http://documents.dps.ny.gov/public/Common/ViewDoc.
aspx?DocRefId={5EDB6D60-3CD7-4F6E-9504-E706A6B3D07A}.
42. New York Department of Public Service, In the Matter of New York Regional Interconnect, Inc., Case No. 06-T-
0650. “New York Regional Interconnect: An Impact Analysis,” Charles River Associates, December 6, 2008. http://
documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId={63EA9E7A-22AE-4597-ACF6-5D583A108DC8}.
43. The other major projects are the Long Island Cable, which was originally scheduled to be energized in 2013 but now
shows an in-service date of 2016. Moreover, LI Cable is listed as a wind project because it is designed to bring power
from a proposed offshore wind development. Although a feasibility study for that project has been completed, none of
the other required NYISO studies has been. Additionally, the Poseidon Transmission project is listed in the NYISO queue as
having a scheduled in-service date of 2016. However, none of the required studies for that project has been completed.
44. Because the project is a DC line, wind resources located in upstate New York CHPE would not be able to interconnect
to it, unless they were interconnected through the line’s origination at the Quebec–New York border. CHPE is opposed
by the Sierra Club, which regards the project as “greenwashing” and one that will undermine the renewable energy
market in New York. http://newyork.sierraclub.org/SA/Vol40/CHPE_greenwashed.htm.
45. NYPSC, Proceeding on Motion of the Commission Regarding a Retail Renewable Portfolio Standard, Case 03-E-0188,
order, September 24, 2004. http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId={B1830060-
A43F-426D-8948-F60E6B754734}. In an order issued on January 8, 2010, the NYPSC revised its 2004 renewable
portfolio standard (RPS) energy goals to 30 percent by 2015, or about 10.4 million MWh. See Order Establishing New
RPS Goal and Resolving Main Tier Issues, January 8, 2010. http://documents.dps.ny.gov/public/Common/ViewDoc.
aspx?DocRefId={30CFE590-E7E1-473B-A648-450A39E80F48}.
46. Integrating large amounts of new wind generation into the NYISO transmission system poses a number of operational
challenges to ensure system reliability. For a discussion, see NYISO, “Integration of Wind into System Dispatch,”
white paper, October 2008. http://www.nyiso.com/public/webdocs/documents/white_papers/wind_management_
whitepaper_11202008.pdf. See also New York State Energy Resource Development Agency, “The Effects of
Integrating Wind Power on Transmission System Planning, Reliability, and Operations,” March 4, 2005.
www.uwig.org/nyserdaphase2.pdf.
47. 660 MW of this is the aforementioned LI Cable project, which is designed to connect offshore wind. The specific
offshore wind project—a joint venture between the New York Power Authority, ConEd, and Long Island Power
Authority—was in NYISO’s queue but was withdrawn in 2011, citing an inability to meet milestones.
48. Several years ago, NYPA considered reconfiguring its Marcy South transmission line into a DC circuit. However, that
project has never appeared in the NYISO queue.
49. See, e.g., S. Bolton, “Do Offshore Wind Farms Need a New Maintenance Model?,” Renewable Energy World
(November 28, 2011). http://www.renewableenergyworld.com/rea/news/article/2011/11/do-offshore-wind-farmsneed-a-new-maintenance-model?page=1.
50. See 2011 Synapse study, p. 19. A full analysis of Assembly Bill 5713-C is beyond the scope of this report. The Synapse
study states that this bill would lead to the development of 2,500 MW of solar resources in the SENY region because
SENY accounts for 50 percent of total New York State retail electric loads. This is simply incorrect because AB 5713-C
would not require solar generation to be procured by each retail utility from local sources.
51. 2010 SOTM report, pp. 167–68.
52. The U.S. Commerce Department has recently imposed countervailing duties on the import of photovoltaic cells from
China, ranging from 2.9 percent to 4.73 percent, depending on the producer. The implication is that this would
increase domestic (U.S.) cost of PV generation. See “Commerce Department Imposes Tariffs on Chinese Photovoltaic
Cells,” Ballard Spahr, March 20, 2012. http://www.ballardspahr.com/alertspublications/legalalerts/2012-03-20_
commerce_department_imposes_tariffs_on_chinese_photovoltaic_cells.aspx.
53. See “$17.2M Solar Farm Constructed at the Village at Manalapan,” Manalapan Patch, February 14, 2012.
http://manalapan.patch.com/articles/17-2m-solar-farm-constructed-at-the-village-at-manalapan.
54. For a detailed explanation of UCAP calculations, see NYISO, Installed Capacity Manual, version 6.20, January 24,
2012. http://www.nyiso.com/public/webdocs/products/icap/icap_manual/icap_mnl.pdf.
55. UCAP for solar energy is based on the angle at which the panels are situated. Ibid., pp. 4-17–4-21. The maximum
summer UCAP is 43 percent of ICAP. Maximum winter UCAP is 2 percent of ICAP.
56. See 2011 Synapse study, pp. 13–16.
57. See NYISO’s summary of DR programs.
http://www.nyiso.com/public/markets_operations/market_data/demand_response/index.jsp.
58. 2010 SOTM report, pp. 167–75. Unlike ICAP/SCR DR resources, EDRP resources are not required to curtail loads if
called on by NYISO.
59. NYISO, Supplement and Errata to Annual Report in Docket No. ER01-3001-000, January 25, 2011, attachment III,
p. 8. http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12545228.
60. NYISO, Errata to Annual Report in Docket No. ER01-3001-000, January 25, 2012, attachment II, p. 7.
http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12875394.
61. These are resources acquired under the Targeted Demand Response Program (TDRP) and the Day-Ahead Demand
Response Program (DADRP).
62. NYPSC, Proceeding on Motion of the Commission Regarding an Energy Efficiency Portfolio Standard, Case 07-M-
0548, order, June 23, 2008.
63. Ibid., appendix 1, p. 5, table A-5. The savings figures are based on the “Jurisdictional Gap,” i.e., electric utility
programs that the NYPSC can oversee. Other programs, such as national appliance efficiency standards, are not
controlled by the NYPSC.
64. Small portions of the SENY region are also served by Orange and Rockland, Central Hudson, and New York State
Electric & Gas.
65. NYDPS, “Energy Efficiency Portfolio Standard Program Review White Paper,” July 6, 2011. Corrected Table 2 (Staff
Responses to O&R and Con Edison Corrections to EEPS White Paper Appendix Tables—July 13, 2011, table 2, p. 2).
Includes all savings from ConEd, Orange and Rockland, Central Hudson, and New York State Electric & Gas. http://
documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId=BDD432F1-2C88-4375-A18D-A2047CCCAFF4.
66. This is one advantage that solar PV has over wind generation, as there is usually little wind on the hottest summer days.
67. See 2011 NYISO Gold Book, p. 18, table I-3a: Econometric Forecast of Annual Energy & Peak Demand.
68. Ibid., p. 17, table I-2f: Energy Efficiency Savings.
69. The 2011 Synapse study (pp. 13–14) asserts that the state can reduce electric consumption by 1.5 percent per year.
However, Synapse states that its estimate is based on a review of studies of energy-efficiency potential, not actual
savings achieved. Moreover, Synapse focuses on statewide savings, not the SENY savings required to replace IPEC.
70. For a detailed description of the production simulation approach, see CRA study, pp. 31–36.
71. CRA study, p. 24, tables 2–3. Costs for NYC are also included in the total cost to NYS.
72. As discussed in the CRA study (p. 23, table 1), another option would involve only one 500 MW combined-cycle unit.
However, this would result in violation failure to meet reliability standards in 2020.
73. CRA estimated that the subsidies needed would total nearly $700 million for the two-unit proposal and over $2 billion
for the HVDC and offshore wind proposal. See CRA study, p. 26, table 6.
74. For a brief discussion of nuclear plant decommissioning, see Nuclear Regulatory Commission, “Fact Sheet on
Decommissioning Nuclear Power Plants.” http://www.nrc.gov/reading-rm/doc-collections/fact-sheets/decommissioning.html.
75. Nuclear Energy Institute, Economic Benefits of Indian Point Energy Center: An Economic Impact Study by the Nuclear Energy
Institute, April 1, 2004 (hereafter, “NEI study”). http://www.nei.org/filefolder/economic_benefits_indian_point.pdf.
76. U.S. EIA, State Energy Data System, table E9, 2009. http://www.eia.gov/state/seds/hf.jsp?incfile=sep_sum/html/sum_ex_tx.html.
77. In Re: Review of New Shoreham Project Pursuant to R.I. Gen Laws § 39-26.1-7, Docket No. 4111, report and order,
April 2, 2010, p. 82. Subsequent to rejecting the proposed contract, the Rhode Island legislature passed a law that, in
essence, mandated the Rhode Island Public Utilities Commission (PUC) to approve the contract.
78. The Appendix contains a mathematical introduction to I/O models.
79. E.g., the NEI study used an I/O framework to estimate the economic impacts stemming from annual operation of IPEC.
80. Nobel Prize–winning economist Wassily Leontief is generally considered to be the father of input-output analysis. For
an introduction to I/O modeling, see his treatise Input-Output Economics, 2nd ed. (New York: Oxford University Press,
1986).
81. IMPLAN was first developed in the late 1970s by the U.S. Forest Service to analyze the economic impacts of various forestry
policies. The current version of IMPLAN is maintained by MIG Inc., formerly known as the Minnesota IMPLAN Group.
82. A detailed description of the analytical methodology is provided in the Appendix.
83. I/O models estimate lost jobs in terms of “job-years.” One job-year is one full-time equivalent for one year.
84. It is possible to change what are called the “production coefficients” in IMPLAN. However, doing so requires an
analysis of how those coefficients should change, which requires complex econometric models of so-called production
functions (i.e., the mix of resources used to produce a good or service). This type of modeling is far beyond the scope
of this report.
85. Economists call this the “price elasticity” of electricity. Many studies have estimated price elasticity and found that
electricity is “price inelastic,” i.e., a percentage change in the price of electricity leads to a smaller percentage change
in consumption. See, e.g., L. Taylor, “The Demand for Electricity: A Survey,” Bell Journal of Economics 6, no. 1 (spring
1975): 74–110.
86. For a more detailed discussion, see Leontief, Input-Output Economics. See also R. Miller and P. Blair, Input-Output
Analysis: Foundations and Extensions (Englewood Cliffs, N.J.: Prentice-Hall, 1985), chap. 2.
87. For a much more detailed discussion, see Miller and Blair, Input-Output Analysis, chap. 2, n. 1, from which these
examples are drawn.
88. I.e., i
j
is a 1xN unit vector having value 1 for industry j. The term i
j
is called the transpose of i
i
and is a Nx1 column vector.
89. For a complete discussion of how SAM multipliers are derived, see G. S. Alward and S. Lindall, “Deriving SAM
Multipliers Using IMPLAN,” paper presented at the 1996 National IMPLAN Users Conference, Minneapolis, August
15–17, 1996. http://implan.com/v3/index.php?option=com_docman&task=doc_download&Itemid=138&gid=127.
90. The jobs multiplier is just the output multiplier weighted by jobs per million dollars of output.
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