United States
Environmental Protection
Agency
National Risk Management
Research Laboratory
Cincinnati, OH 45268
Research and Development
EPA/600/SR-96/130
November 1996
&EPA Project Summary
Demonstration of the
Environmental and Demand-side
Management Benefits of
Grid-connected Photovoltaic
Power Systems
Edward C. Kern, Jr. and Daniel L. Greenberg
This project investigated the pollut-
ant emission reduction and demand-
side management potential of 16 pho-
tovoltaic (PV) systems installed across
the country in 1993 and 1994. The
project was sponsored by the U.S. EPA
and 11 electric utilities. This report pre-
sents analyses of each system's ability
to offset emissions of sulfur dioxide,
nitrogen oxides, carbon dioxide, and
participates, and to provide power dur-
ing peak load hours for the individual
host building and the utility. Results of
simulations of battery storage systems
powered by each PV system are also
presented.
The analysis indicates a very broad
range in the systems' abilities to offset
pollutant emissions, due to variation in
the solar resource available and the
marginal emission rates of the partici-
pating utilities. Use of dispatchable
storage would reduce emission offsets
due to energy losses in charging and
discharging the batteries. Each
system's ability to reduce building peak
loads was dependent on the correla-
tion of that load to the available solar
resource. Most systems operated in ex-
cess of 50% of their capacity during
building peak load hours in the sum-
mer months, but well below that level
during winter peak hours. Similarly,
many systems operated above 50% of
their capacity during utility peak load
hours in the summer months, but at a
very low level during winter peak hours.
The addition of dispatchable energy
storage significantly increases each
system's peak load matching ability,
raising capacity factors to 100% for
most systems during the utility's high-
est load hours.
This Project Summary was developed
by the National Risk Management Re-
search Laboratory's Air Pollution Pre-
vention and Control Division, Research
Triangle Park, NC, to announce key
findings of the research project that is
fully documented in a separate report
of the same title (see Project Report
ordering information at back).
Introduction
Photovoltaic (PV) conversion of sunlight
to electricity has become substantially less
costly and more efficient in recent years.
Since its first application in the space pro-
gram in the 1950s, the cost of PV mod-
ules has fallen approximately 70% per
decade, and module manufacturers con-
tinue to make progress in reducing costs
further. Although technological innovation
has been responsible for much of the de-
cline in costs, an international market for
remote, off-grid power, growing at the rate
of 20 to 30% annually, has resulted in
expansion of module production capacity.
This, in turn, has led to production econo-
mies which have driven module prices
down still further.
Despite these cost reductions, modules
remain the dominant factor in the cost of
a grid-tied PV power system accounting
for approximately 70% of the total. The
power converter (inverter), necessary for
transforming the direct-current (DC) power
output from a PV array to grid-synchro-
nous alternating-current (AC) power, is an-
other significant component of system cost,
accounting for about 15% of total cost.
Because the market for grid-tied AC power
-------
from PV systems has been relatively small,
there has been little progress in reducing
the cost of the inverter.
However this project and other similar
projects are increasing the demand for
inverters, and will likely result in techno-
logical improvement and cost reduction.
The remaining cost components of PV
systems are the array mounting structure,
wiring, and switchgear, collectively referred
to as the balance of system (BOS).
Although electricity generated by PVs
remains too expensive to compete with
conventional power sources in most grid-
connected applications, there is a growing
niche of cost-effective applications (most
of them remote from the power grid) which
will expand as the cost of PV power falls.
A 50% drop in module prices is expected
within the decade which has the potential
to greatly expand the grid-connected mar-
ket. Against this background of falling costs
is a heightened public awareness of the
threats to environmental quality posed by
the by-products of electricity production.
The most notable concern today is the
possibility that emission of carbon dioxide
(CO2) resulting from the combustion of
fossil fuels may lead to climatic changes
on a global scale. As a result of this height-
ened concern regarding environmental
quality, many consumers have shifted their
consumption patterns, and some are will-
ing to pay premiums for products that
have lower environmental impacts. Sev-
eral recent surveys suggest that about
half of electric utility customers would be
willing to pay a $10 monthly premium for
electricity generated by renewable re-
sources. Given this context, it is very likely
that the domestic market for grid-tied PV
power systems will expand substantially
within the next decade, and continue to
grow rapidly.
The potential environmental benefits
from PV power generation are quite large.
If PV systems were installed where pos-
sible on the rooftops of the U.S. inventory
of residential, commercial, and industrial
buildings, they could produce roughly 20%
of the Nation's electricity. Currently, fossil
fuels used for electric power generation in
the U.S. account for approximately 34%
of the CO2, 67% of the sulfur dioxide (SO2),
and 37% of the nitrogen oxide (NOx) emis-
sions into the atmosphere from control-
lable sources within the U.S.
In September 1991 the EPA issued a
solicitation for the installation of grid-tied
PV systems with the goal of measuring
their environmental and demand-side ben-
efits. Ascension Technology developed a
proposal in response to this solicitation,
with the support and participation of utili-
ties across the nation. Eleven utilities sup-
porting the proposal to EPA were (1) New
England Electric System (NEES) with ser-
vice areas in Rhode Island, Massachu-
setts, and New Hampshire; (2) New York
State Electric and Gas (NYSEG) in up-
state New York; (3) Northeast Utilities (NU)
with service areas in Connecticut, Massa-
chusetts, and New Hampshire; (4) Atlan-
tic City Electric (ACE) in southern New
Jersey; (5) New York Power Authority
(NYPA) with customers throughout New
York State; (6) Arizona Public Service
(APS) in central and northern Arizona; (7)
Wisconsin Public Service (WPS) in south-
eastern Wisconsin; (8) Northern States
Power (NSP) with service areas in Minne-
sota, Wisconsin, Michigan, and the Dako-
tas; (9) Pacific Gas and Electric (PG&E),
serving most of northern California; (10)
the City of Austin Municipal Utility (COA);
and (11) Southern California Edison (SCE)
serving much of southern California. In
addition to the geographic diversity of the
service areas represented by these utili-
ties, their pollutant emission characteris-
tics also proved to be quite divergent.
Ascension Technology's partners from the
PV industry were Siemens Solar Indus-
tries, which provided PV modules, and
Omnion Power Engineering Corporation,
which provided the inverters.
EPA awarded the contract for this project
to Ascension Technology in the third quar-
ter of 1992. The final system design effort
began shortly thereafter, and the first sys-
tem was installed and operating in April
1993. Ten of the systems were operating
by the end of August 1993, and the last
was completed by mid-January 1994.
Monitoring of each system began con-
currently with initial system operation, al-
though the "official data start date" was
delayed where there were initial technical
problems with either instrumentation or
PV system hardware. At each site, 15-
minute average values of solar irradiance,
ambient temperature, PV system power
output, and building load were recorded
and stored for subsequent retrieval by
modem. Monitoring of each site (for the
purposes of this study) continued through
September 1994.
Emission rate and load data provided
by each participating utility were used in
conjunction with the data collected from
each system to conduct analyses of (1)
the emission offsets resulting from opera-
tion of the PV systems; (2) the ability of
each PV system to reduce the peak power
demand of the building on which it was
installed; and (3) the chronological corre-
lation of each PV system's power output
to the respective utility's peak loads. In
addition, a model was developed to simu-
late the operation of each system in con-
junction with dispatchable battery storage.
This simulation shifted each system's daily
generation to the utility's daily peak load
hour(s), thus increasing the peak load cor-
relation and reducing emission offsets (due
to battery charging and discharging
losses).
Chapter 1 of the full report is a general
introduction to the project. Chapter de-
scribes the design, installation, and cost
of each system. Chapter describes the
data acquisition system and presents data
collection and review procedures. System
performance history is described gener-
ally in Chapter (details are provided in
appendix D). Chapter discusses the model
used to simulate the behavior of the PV
systems with dispatchable battery stor-
age. The marginal emission rate models
developed for each participating utility are
described in Chapter 8, as are the site-by-
site emission offset estimates. Chapter 6
discusses each system's impact on the
load of the building it is installed on, and
utility-level load matching results are pre-
sented in Chapter 7. Conclusions from
this project are summarized in Chapter.
Procedure
System Design
Designs were developed for nominal 4-
kW "building block" PV systems for this
project, capitalizing on the project staff's
experience with roofmounted PV arrays in
prior projects. The majority of the project's
sites use either one system (4 kW) or a
group of three systems (12 kW total). Note
that the nominal system size refers to the
inverter AC rating. The actual power out-
put of the PV systems under standard
operating conditions (1000 W/m2 irradi-
ance (full sunlight) and an ambient tem-
perature of 20°C) is limited by the PV
array to multiples of 3.5 kW AC.
PV arrays were configured using 12 PV
panel assemblies. Each PV panel assem-
bly contains seven modules, electrically
wired in series. A PV source circuit is
formed with four PV panel assemblies,
wired in series. A 4-kW PV array consists
of three PV source circuits.
Both pitched- and flat-roof installations
utilize Ascension Technology RoofJack PV
array supports, which have been used to
install more than 1 MW of PV systems.
PV arrays are held in place by ballast on
flat roofs; this approach requires no roof
penetrations to hold down of the PV ar-
rays. System design details were devel-
oped in close cooperation with Siemens
Solar Industries of Camarillo, CA, the PV
module supplier. Omnion Power Engineer-
ing was selected as the supplier of power
conditioners. The PV systems were de-
-------
signed to accommodate the specifications
of the 4 kW-rated Omnion Series 2200
unit.
System Installation
System installation began in April 1993,
and was complete by the end of January
1994, although instrumentation and hard-
ware problems delayed the initiation of
monitoring at some sites. The systems
were installed on a variety of residential,
commercial, and industrial buildings. In-
stallation costs for each system varied by
system size (4-, 8-, or 12-kW) and a num-
ber of site-specific factors. Table 1 sum-
marizes the size and cost of each system.
PV System Performance
History
Of the 16 PV systems installed by this
project, all but two suffered events during
the study period which temporarily limited
system output or prevented generation al-
together. Inverter-related problems were
the most vexing of the generation-limiting
events. In all, 27 inverter-related events
resulted in a generation loss of 12,740
kWh, approximately 9% of the combined
generation of these systems over the rel-
evant time periods.
As a result of the inverter-related out-
ages experienced in this project, the in-
verter manufacturer made several design
changes and increased product testing
across their full line of inverters. In addi-
tion, they extended the product warrantee
for the EPA project installations.
Snow cover was also a frequent cause
of PV system outages for those systems
located in northern locations or at high
Table 1. System Size and Cost
Site
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Utility
NYSEG
NU
ACE
ACE
NYPA
APS
APS
WPS
WPS
NSP
PG&E
COA
APS
SCE
SCE
SCE
Size
kW
12
4
12
4
4
8
4
12
4
4
12
12
4
4
4
12
Total
Cost'
101.9
36.0
105.0
31.1
35.2
64.2
31.3
101.0
31.2
38.0
104.9
97.5
32.2
30.9
31.1
96.7
Cost*
per
AC
Watt
9.69
10.26
9.98
8.87
10.04
9
8.94
9.61
8.91
10.83
9.40
9.27
9.19
8.81
8.89
9.20
' Costs are in $1,000s
altitude. Of the systems in such locations,
the estimated energy loss as a result of
snow cover ranged from less than 1% to
16% of measured annual generation.
A variety of other outages occurred dur-
ing the study period, not all of which have
identified causes. Of those "other" out-
ages for which a cause was identified, the
most frequent was, by far, fuse failure in
the DC disconnect switch. Such failures
occurred 17 times at 11 sites. It was de-
termined that the original fuses in the DC
disconnect switches did not have the
proper surge rating. As they failed, they
were replaced by "slow-blow" fuses which
were rated for 600 V DC. None of the
replacement fuses has failed to date.
Battery Storage Model
Where peak loads do not coincide with
peaks in the available solar resource, the
value provided by a PV system can some-
times be greatly enhanced by the addition
of dispatchable battery storage. Although
some energy is lost both in charging and
discharging a battery array, the ability to
dispatch energy generated by the PV sys-
tem during utility peak loads (or, for that
matter, the peak loads of a transmission
line or distribution feeder) allows the PV
generation to be used to reduce genera-
tion by a utility's highest operating cost
units, which are typically used only during
peak periods.
To investigate the degree to which
dispatchable battery storage would im-
prove the ability of each PV system to
offset load during utility peak load hours,
a simple model was developed to simu-
late battery charging, discharging, and dis-
patch. The approach taken was to maxi-
mize the contribution of each PV system
during the highest utility load hours of
each day, by simulating the daily opera-
tion of each system's inverter(s) at its
(their) peak capacity for as long as pos-
sible. The duration of operation each day
was determined by the amount of energy
actually generated each day and the AC
rating of the inverter. The addition of
dispatchable battery storage affects both
pollutant emission offsets (due to battery
charging and discharging losses) and the
system's operation during utility peak load
hours.
Results
Pollutant Emission Offsets
Models of marginal emission rates (i.e.,
emission rates of load following units) were
developed for each utility based on utility
provided data. The hourly emission rates
of SO2, NOx, CO2, and particulates were
then combined with hourly PV system gen-
eration data (and simulated PV/storage
dispatch data) to determine hourly emis-
sion offsets.
Annual emission offsets are presented
in Figures 1 through 4. Annual SO2 offsets
ranged from 4 g/kW to 16 kg/kW of sys-
tem rating under standard operating con-
ditions (SOC) (1000 W/m2 irradiance and
20° C ambient temperature). NOx offsets
ranged from 110 g/kW to 8.7 kg/kW. The
range in annual CO2 emission offsets was
from 700 to 2,300 kg/kW of system rating,
and that for particulates was 20 g/kW to
600 g/kW annually. The lighter shaded
area in each figure is an estimate of the
pollutant offset achievable by a PV sys-
tem with average insolation, using aver-
age U.S. emission rates based on data
collected by the Energy Information Ad-
ministration for 1993.
The extreme variability in these results
is due to two factors: (1) variability in the
local solar resource and (2) variability in
utility marginal emission rates. Factor (2)
is far more influential than (1), as can be
seen by comparing the range for CO2 to
those of the other pollutants. Since there
are currently no mitigation measures in
place for CO2, variation in utility CO2 emis-
sion rates is due only to the relatively
small (about 2:1) variation in the carbon
content of fuels used and variation in the
heat rates of the power plants. The range
of the highest to lowest annual offset is
relatively small (3.3). For the other pollut-
ants, variations in the pollutant content of
the fuel as well as inter-utility differences
in installed pollution mitigation equipment
give rise to the tremendous differences
between utility emission rates which un-
derlie the differences in emission offsets
described above.
The results of the PV-powered
dispatchable storage system simulations
indicate that pollutant offsets would be
reduced by at least 25% were storage
added to these systems. This is largely
due to energy losses in charging and dis-
charging batteries, but is also influenced
by marginal emission rates which are typi-
cally lower during utility peak load hours
when cleaner, more efficient power plants
are often used to follow load.
Building-Level Load Reduction
Each PV system's ability to provide
power during building peak load hours
was analyzed by comparing each building's
net (of PV generation) and gross load
duration curve (LDC). The LDC is con-
structed by sorting all load values for a
given period in descending order, and plot-
ting each value against its rank in the
sort. Differences in a building's net and
gross LDC for the highest load values
-------
Annual Sulfur Dioxide Offset
20
15
i
i
10
I
nn
1 23 456 78 9 10 11 12 13 14 15 16 17
Site Number
Figure 1. Annual SO2 offsets.
10
\ Annual NOX Offset |
I.
i
§
c 4
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
Site Number
Figure 2. Annual NO offsets.
-------
Annual Carbon Dioxide Offset
2500
2000
£
7500
| 7000
500
7 2345 6 7 8 9 10 11 12 13 14 15 16 17
Site Number
Figure 3. Annual CO2 offsets.
Annual Particulate Offset
0.8
0.6
0.2
1 23456 7 8 9 10 11 12 13 14 15 16 17
Site Number
Figure 4. Annual particulate offsets.
-------
indicate the PV system's ability to reduce
building peak loads.
As one would expect, reductions in net
building load were generally higher in the
summer months and lower in the winter
months, with the difference being particu-
larly pronounced for systems installed in
northern states. Most systems reduced
the building's LDC by more than 50% of
system AC rating during the highest load
hours in the second and third quarters of
the year. In the winter months, PV output
during building peak load hours dropped
below 10% of rating for some systems,
although many systems in the southern
and western states performed as well or
even better during winter peak load hours.
Two general conclusions may be drawn
from the analysis. The first is the relatively
self-evident conclusion that, if reduction of
customer net demand is the primary moti-
vation for the installation of a PV system,
it is critical to investigate the correlation of
building peak loads to solar irradiance.
The set of host buildings participating in
this project included some with loads which
were very well matched to the solar re-
source as well as some for which the
match was very poor. The systems in
Ashwaubenon, Wl, and Scottsdale, AZ,
are examples of systems which reduced
host building LDCs by a substantial frac-
tion of their SOC rating. The highest loads
in these buildings occurred during midday
hours, when the solar resource peaks.
The systems in Barstow, CA, and Den-
mark, Wl, on the other hand had very little
effect on the host building's LDC, despite
ample solar resource. Many of the highest
building loads at these sites occurred near
or after sunset.
The second general conclusion to be
drawn from the data is that the generation
by a PV system during an individual
building's peak load hour provides little
information regarding that system's ability
to reduce the building's peak monthly load,
or to reduce demand charges. Even if the
system generates at full power during the
monthly peak, there may be hours during
which building load is slightly below the
monthly peak and during which the PV
system operates at a much lower level. In
such cases there may be very little change
in the building's net LDC and correspond-
ingly small changes in demand charges.
The monthly peak load will have simply
been shifted to another hour.
Utility Coincident Peak Load
Reduction
Each PV system's ability to provide
power during utility peak load hours was
analyzed by simultaneously sorting hourly
PV generation data and hourly utility load
data in descending order, with utility load
level determining the sort order. The re-
sult was a utility load duration curve with
a value of PV generation for each corre-
sponding hour on the LDC. A "cumulative
average PV capacity factor curve" (CACF
curve) was then created by dividing each
hourly PV generation value by the system's
capacity rating (resulting in hourly capac-
ity factors) and then averaging each hour's
capacity factor with the capacity factors of
all hours higher in the sort-order (i.e., all
hours in which utility load was higher).
The resulting curve illustrates the PV
system's average capacity factor for the
highest n load hours, where n is read off
the ordinate.
By plotting this curve on the same axes
as the normalized LDC, one can deter-
mine for each point on the LDC, the aver-
age PV system capacity factor for all hours
up to and including that hour. For ex-
ample, the CACF curve in Figure 5 indi-
cates that the PV system's average ca-
pacity factor during the utility's 10 highest
load hours was about 40%. CACF curves
were calculated using both measured PV
system performance data and the perfor-
mance data generated by the dispatchable
storage simulation.
Charts displaying the utility LDC and
the PV system's CACF curves (both with
and without storage) were created for each
calendar quarter during the study period.
An additional chart showing the same data
for the 100 highest load hours encoun-
tered during the study period was also
created. These charts provide a measure
of each PV system's peak shaving capac-
ity.
Load Reduction Without
Storage
Not surprisingly, load matching for PV
systems installed in northern states is
greatest in the spring and summer months,
with the capacity factor during the highest
load hours typically averaging above 40%.
Several of these sites achieved capacity
factors well in excess of 60% of their SOC
rating during the highest load hours in
these months. The northern systems in-
variably generated little or no power dur-
ing winter peak hours, most or all of which
occurred at night.
Utility peak loads in the southern and
western parts of the U.S. invariably oc-
curred during the summer months when
the solar resource is greatest, although
these peaks consistently occurred in the
mid- to late-afternoon. Most of the sys-
tems installed in these regions operated
at capacity factors in excess of 40% dur-
ing the highest load hours in the summer
months. Some systems consistently oper-
ated at capacity factors above 60% during
these hours. The one exception to this is
the system in Flagstaff, AZ, which oper-
ated at only about 30% capacity factor
during the peak load hour. This low result
is most likely explained by the fact that
the load and weather patterns in Flagstaff
Third Quarter 1993
0.9
^
o
•a 0.8
£,
! °-7
o
i> 0.6
Q.
System load
Cumulative average
capacity factor
10,000
Figure 5. Example utility load duration and cumulative average capacity factor curves.
-------
are quite different from those in Phoenix
which is about 1 mi (1.6 km) lower in
elevation and 140 mi (225 km) south.
Loads in the Phoenix area probably domi-
nate the APS system load.
As did their counterparts in the Midwest
and Northeast, systems in the southern
and western states typically operated at a
lower level during winter peak hours. Ex-
cept for systems in southern California,
systems in the West operated at or near
a zero % capacity factor during peak hours
in the first quarter of the year.
Load Reduction With Storage
Except where the power output was
limited by a system outage, results from
the storage simulation indicate that stor-
age can provide system operation at the
full inverter rating during the peak load
hours in the summer months at all sites.
In regions (such as the NU service area)
where peak utility loads are highly corre-
lated to the solar resource, the addition of
a dispatchable storage system may do
little to improve the PV system's load
matching capability, since it will already
be quite good. Systems in northern states
are much less able to provide power dur-
ing peak load hours in winter due to their
limited solar resource and snow cover.
Even with storage, some of these sys-
tems were unable to provide power at
more than a few percent of inverter rating
during winter peak load hours. However,
daytime generation at other northern sites
was sufficient to allow inverter operation
well in excess of 50% of inverter rating
during winter peak hours.
Unlike many systems installed in north-
ern climates, the addition of dispatchable
storage to systems installed in the south-
ern and western states would allow them
to operate at high capacity factors during
winter peak hours. The results of the simu-
lation indicate that most of the systems
installed in this part of the U.S. would
operate at or near 100% of inverter rating
during the highest winter load hours.
It is important to recognize that these
results are substantially determined by the
storage charging/dispatch algorithm. An
algorithm which stores generation from 1
or more days and dispatches only when
load exceeds a predetermined threshold
(as opposed to dispatching during the peak
hours of each day) might substantially im-
prove the load matching characteristics of
all systems.
Conclusions
This project has provided an initial dem-
onstration of the effectiveness of grid-con-
nected PV energy systems in reducing
the pollutant emissions of electric utilities.
The broad range of emission offsets
achieved by these systems reflects differ-
ences in both the available solar resource
at each site and differences in emission
rates among utilities. The results demon-
strate that the latter factor is far more
important in determining the pollution miti-
gating potential of a PV system than is
the former. Given current and projected
costs of PV systems, it is unlikely that this
technology will be employed solely for its
pollution mitigating potential. While there
is certainly substantial value in this poten-
tial, PV's environmental benefits must be
considered in conjunction with the other
benefits provided by the technology for
grid-connected applications to be consid-
ered cost-effective. These benefits include
conventional energy and power benefits
as well as more subtle and less well-
recognized advantages over central-sta-
tion generators.
The report documents case studies of
the peak load reduction benefits, for utili-
ties and for individual customers at sites
across the country. While PV will not pro-
vide substantial power during peak load
periods at every location, it will at many,
with or without storage. If a PV system is
interconnected on the customer side of
the meter, this translates into energy- and
demand-charge savings. On the utility side
of the meter, distributed generating re-
sources such as PV which provide power
during peak load hours can defer costly
and under-utilized additions to generation
and transmission capacity. In addition, ev-
ery kilowatt-hour generated by a PV sys-
tem reduces utility fuel and variable op-
eration and maintenance costs.
As the electric utility industry enters the
world of retail competition, the high cost
of providing power during peak hours is
likely to be much more clearly reflected in
the prices paid by consumers. The value
provided by resources such as PV that
generate power during such times is there-
fore likely to increase substantially for cus-
tomers that cannot alter their consump-
tion patterns, and for utilities hoping to
retain such customers.
Retail competition at the generation level
will also bring the costs of maintaining the
transmission and distribution (T&D) sys-
tem under closer scrutiny. Already, sev-
eral studies have demonstrated that such
costs are not homogeneous across a ser-
vice area, but are typically highly differen-
tiated. Communities in which load growth
necessitates an increase in the power de-
livery capacity of local distribution re-
sources may have T&D costs many times
the average for the utility service area. In
such areas distributed generating re-
sources such as PV might defer or elimi-
nate the need for T&D capacity additions,
to the degree that they are able to provide
power at the time when the existing distri-
bution system is stressed.
In addition to its environmental, energy,
and capacity benefits, PV technology pos-
sesses a variety of characteristics which,
although less easily quantifiable, contrib-
ute additional real value. Among these
are (1) its reliance on a limitless, indig-
enous resource, which could reduce grow-
ing dependence on imported oil; (2) its
modularity and speed of installation, al-
lowing generating capacity to be added
as needed rather than tying up large
amounts of capital in conventional power
plants, the need for which may not materi-
alize; (3) the relative ease of siting PV
power plants, as opposed to the permit-
ting hurdles and public opposition that utili-
ties typically encounter in attempting to
site conventional power plants and trans-
mission lines; and (4) its ability to fulfill
consumers' desire for non-polluting, re-
newable resources, which may have stra-
tegic value to utilities in addition to envi-
ronmental benefits.
Taken collectively, the benefits of grid-
connected PV power may already out-
weigh its costs in some applications. As
PV costs continue to decline, the range of
such applications is certain to grow, but
much work remains in the effort to fully
quantify the benefits of the technology.
Projects such as the one this report docu-
ments are an essential component of that
effort.
-------
E.C. Kern, Jr. and D.L Greenberg are with Ascension Technology, Inc., Lincoln
Center, MA 01773.
Ronald J. Spiegel is the EPA Project Officer (see below).
The complete report, entitled "Demonstration of the Environmental and Demand-
side Management Benefits of Grid-connected Photovoltaic Power Systems,"
(Order No. PB97-117618; Cost: $41.00, subject to change) will be available only
from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Air Pollution Prevention and Control Division
National Risk Management Research Laboratory
U. S. Environmental Protection Agency
Cincinnati, OH 45268
United States
Environmental Protection Agency
Center for Environmental Research Information (G-72)
Cincinnati, OH 45268
Official Business
Penalty for Private Use $300
BULK RATE
POSTAGE & FEES PAID
EPA
PERMIT No. G-35
EPA/600/SR-96/130
------- |