Download 2 Technology Overview

University of California at Berkeley
.
Concentrated Solar Power for Santa Barbara
County: Analysis of High Efficiency Photovoltaic
and Solar Thermal Electric
Valerie L. Zimmer
Claire Woo
Peter Schwartz
University of California at Berkeley
Energy and Resources Group/ Materials Science and
Engineering 226
December 12, 2006
Photo credit Stirling Energy Systems
Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
1
Introduction
Concentrated Solar Power (CSP) systems focus the sun’s insolation by means of reflective
troughs or dishes, or lenses. The focused light back be used on a high efficiency photovoltaic
panel (HEPV) for direct electrical conversion, or be used to heat a working fluid that expands to
turn a generator (Solar Thermal Electric, STE). These systems were initially envisioned to
compete with fossil fuels as it was assumed that fossil fuel prices would continue to dramatically
rise as they had in the 1970s. CSP systems concentrate the sun’s power and are thus able to store
the thermal energy. They are associated with high efficiencies and smaller land requirements.
However, CSP systems usually require tracking of the sun, which increases the complexity and
vulnerability of the system. An added difficulty of CSP (compared to conventional
photovoltaics) is that it can only use direct sunlight and thus is only applicable for use in areas
where there is primarily direct insolation. Unfortunately, the long distance of many of these areas
from urban centers causes transmission difficulty and encumbers the use of waste heat for
municipal hot water. Lastly, the unfortunate bankruptcy of Luz International (which should not
be seen as a reflection of inferior technology, or even management. see section 1.2), has left
many investors reluctant to heavily invest in CSP technologies.
Because of the mentioned complexity of the systems, environmental requirements and historical
difficulties, there is presently little power generated by means of CSP. Therefore, future efforts
in CSP development will have significant hurdles to overcome, even if the system is cost
competitive. But inspiringly, after 20 years, the original Luz CSP generator facilities have
proven themselves productive and reliable, and newer promising technologies have besieged the
market. And while these newer technologies may require smaller scale system reliability tests
before investment is likely to be made in a system on the scale of 100MW, we are able to present
several CSP technologies that hold great promise in satisfying a significant portion of Santa
Barbara County’s increasing energy needs.
1.1
Scope of Work
This report is the result of two months of work performed as part of the Energy and Resources
Group / Materials Science and Engineering 226 course. This paper is intended to advise the
Community Environmental Council (CEC) in Santa Barbara, California in assessing and
planning the promotion and construction of local renewable energy resources. This report is an
overview of current CSP technologies, a partial review of literature assessing the potential of
these technologies to compete in the current utilities market, a preliminary assessment of the
price sensitivity of different elements of the technology, and of the added value to CSP
technology that is often neglected in traditional financial analyses. Though we find CSP a very
promising technology for Santa Barbara’s energy needs, it is the recommendation of the authors
of this paper that this work be extended if CSP becomes a serious consideration for the CEC.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
1.2
Historical review
There are two major CSP plants that have demonstrated capability in California, and several
others in the southwest United States. The 9 Solar Electric Generating Systems (SEGS),
constructed between 1984 and 1990 by Luz International in the California Mojave Desert,
constitute the world’s largest solar power plant with a total capacity of 354 MW. They all use
parabolic trough collectors, and their continuous successful operation for the last 20 plus years
up until now has demonstrated the robustness and reliability of the parabolic trough technology
(see Sections 2.1.1 and 2.3.1). The solar company, Luz, filed for bankruptcy in 1991 when it
failed to secure financing for the 10th SEGS due, in part, to unfavorable laws that created a
situation in which approval came too late in the year for the construction to be completed by the
end of the year, as required by state law (pers. comm. D. Kammen, 2006). The unfortunate
bankruptcy of Luz put a lot of people on guard about the economic prospects of CSP plants and
could have been a major cause for the dormant period from 1991 until now during which no new
CSP plants have been built.
The second CSP plant is a 10 MW solar tower plant (see Section 2.1.3) located in Barstow, CA
(NREL report, Stoddard et al, 2006). The first prototype, named Solar One, operated from 1982
to 1988 and produced over 38million kWh of electricity. However, the concentrator units were
more expensive to operate and repair than the value of the energy they could produce. The
second prototype, Solar Two, operated in 1998-1999 and had improved efficiency. The plant
encountered a few technical difficulties of which solutions have been identified; however,
demonstration of the technology is required before commercial financing can be secured to
reopen the plant.
In April this year, Arizona Public Service (APS) completed the construction of Saguaro Solar
Power Plant, a 1MW parabolic trough plant, the first one built in the US in 17 years (APS, 2006).
The $6 million project started construction in June 2004 and was completed in 15 months. The
plant is located on a stretch of desert between Phoenix and Tucson. It produces electricity at
about 12¢/kWh, and it delivers enough power to serve about 200 homes. The plant has more than
100,000 square feet of parabolic troughs which stand more than 15 feet tall. Solargenix was the
parabolic trough system provider and Ormat designed the power conversion unit.
1.3
Current Projects in Development
The dormant period appears to be over as several new and exciting utility-scale CSP plants are in
the planning and construction phase. Solargenix, a subsidiary of Acciona Energia based in Spain,
has signed a contract in 2002 with two Nevada-based utility subsidiaries to build Nevada Solar
One, a 64MW solar thermal electric (STE) generating plant in Boulder City, Nevada (Solargenix,
2006). The plant will use parabolic trough technology. It will be the largest solar electric power
plant built globally in the last 14 years and will be the 3rd largest solar power plant in the world.
The plant is scheduled to begin service in early 2007.
Stirling Energy Systems (SES), an Arizona-based company, secured two huge deals last year to
build the world's first utility-scale Stirling solar dish plants. In August 2005, SES signed a 202
Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
year power purchase agreement with Southern California Edison that would result in the
construction of a 4500-acre 500MW solar project in Southern California, with the option of
expanding its capacity to 850MW. The system, consisting of a 22,000-dish array, will take 4
years to build and will be the world's largest solar facility, providing clean energy for 278,000
homes. In September 2005, SES signed a contract with San Diego Gas & Electric to provide
300MW-900MW solar power from a Stirling solar dish plant. The initial 300MW plant will
consist of 12,000 Stirling solar dishes, and two future phases can add 600MW additional
capacity to the plant.
International projects are also springing up. Solel, an Israeli solar thermal company that also runs
three of the SEGS plants in CA, signed a $890 million agreement in November 2006 with a
Spanish firm to build three 50MW solar power stations with the parabolic trough technology.
With subsidies from the Spanish government, the plant will produce electricity at 30 cents/kWh.
Solar Millennium AG, a Germany company that specializes in the construction of solar thermal
power plants, entered an agreement with the Spain-based construction company ACS/Cobra
group to build two 50MW solar parabolic trough plants in Spain. The parabolic trough plant,
Andasol 1, will have over 510,000 m2 (5.5 million ft2) of collector area and it will use liquid salt
tanks for thermal storage. The collectors can concentrate direct solar radiation 80 times onto the
absorber tubes in the focal line. The first plant is scheduled to come into service in 2007. The
second plant will start up half a year later. Together, they will serve the energy needs of 50,000
households.
Solar Systems, an Australian company, specializes in dish concentrator systems that can
concentrate the sun 500 times. Their concentrator systems track the sun along 2 axes during the
day, and their panels require effective cooling to keep the efficiency high. They claim to use
panels that are 3 times more efficient than standard solar panels. Thus, the output of each PV
surface is 1500 times that of standard PV receiving one solar insolation. Recently, they secured a
$420 million deal to build a 154MW solar concentrator power plant in northern Victoria.
2
Technology Overview
The concentration of solar energy to produce electricity is unique from standard photovoltaic
(PV) technology in that it replaces most of the PV cell area with a set of reflectors in order to
reduce costs, on the theory that the reflectors are cheaper than the PV would have been.
Concentrating systems also add an additional layer of complication: since the system is efficient
only when direct sunlight is reflected, the system must accurately track the sun at all times,
which adds complexity and cost. The required accuracy of tracking and tracking complexity
varies between solar trough (1-D concentration) and dish/tower (point concentration), between
large scales dishes and less-sensitive smaller lens systems (Fresnel, Sol-Focus).
The conversion of energy at the focal point or focal line is also different from standard PV. If
the conversion of energy is done using PV cells, it is best accomplished with high-efficiency,
cooled cells capable of carrying large currents. However, most of the systems tested to-date do
not use PV energy conversion; rather they use different types of solar thermal electric engines
and heat transfer fluids.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
Therefore, in order to understand the costs, sensitivity, reliability, and challenges with CSP, it is
necessary to understand the underlying concepts behind the technology. This section presents
concentration methods, energy conversion methods, the major companies, and a few promising
newer companies.
2.1
Concentrating Methods
2.1.1 Parabolic Trough
Parabolic trough power plants consist of large parallel arrays of parabolic trough solar collectors
aligned on a north-south horizontal axis which make up the solar field (Figure 1). Each parabolic
collector is made of reflectors that focus that sun’s direct radiation on a linear receiver at the
focal line of the parabola. The collectors track the sun from East to West so that the sun’s
radiation is continuously focused on the linear receiver.
Figure 1. Parabolic Trough collectors (Source: NREL report 2006).
2.1.2 Dish Systems
Solar dish systems consist of a dish-shaped concentrator (like a satellite dish) that reflects solar
radiation onto a receiver mounted on a focal point at the center, as shown in Figure 2. The dish
rotates on 2 axes to track the sun during the day. Dish systems can often achieve higher
efficiency than parabolic trough systems partly because of the higher level of solar concentration
at the focal point. Dish systems are said to be more suitable for stand-alone small power systems
due to their modularity.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
Figure 2. Solar dish collectors (source: NREL report 2006).
2.1.3 Solar Tower
Power towers consist of a tower surrounded by a large array of heliostats, which are mirrors that
track the sun and reflect its rays onto the receiver, as indicated in Figure 3. The receiver in the
tower is either a HEPV cell or a heat transfer fluid that absorbs the heat that is then utilized in
driving a turbine electric generator. Solar towers also have higher conversion efficiencies than
parabolic trough systems. They are projected to be cheaper than trough and dish systems, but a
lack of commercial experience means that there are significant technical and financial risks in
deploying this technology now.
Figure 3. Solar Tower (source: NREL report 2006).
2.2
Concentrator Photovoltaics
Concentrator photovoltaics (CPV) refer to a system that replaces normal PV cells with reflectors
(mirrors) that concentrate the solar energy on a high-efficiency PV (HEPV) cell designed to
handle much higher loads and heating. CPV systems tend to use non-silicon solar cells, such as
triple-junction GaAs, which are much more expensive and more efficient than standard silicon
cells. Due to the complexity and expense of optics, trackers, and cooling, the overall cost5
Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
effectiveness is best when the highest efficiency cells are used. A distinct advantage that CPV
has over conventional “one sun” PV is the present bottleneck in the PV industry due to a scarcity
of purified silicon, that will likely persist for two or more years. CPV generally uses 1/500 the
amount of PV cell surface area as does conventional PV, so the price of the PV cell constitutes a
smaller cost consideration for CPV even if those used are expensive, triple junction, high
efficiency gallium arsenide cells.
The employment of mirrors to replace the large surface areas of PV cells present in “one sun”,
conventional PV power systems requires that direct sunlight be reflected onto a tiny PV module.
Diffuse sunlight coming from all directions (on a cloudy day) would be reflected in all directions
as well, largely missing the PV surface. Therefore, the concentrator system is only efficient in
locations that have high direct incident radiation (e.g. deserts) and require an accurate and
precise tracking system. Since the complexity of accurate optics and trackers adds cost to the
project, it makes sense to employ CPV in a manner that maximizes wattage. As a result, these
systems are appropriate for the highest cost PV cells, and are appropriate for utility-scale
application.
2.2.1 Large Dishes and Towers
There are a number of research projects and a few industrial systems being tested using large
concentrating dishes (10-20 m in height). Solar Systems of Australia has deployed thirty 500X
concentration dishes using silicon cells, outputting 20-24 kW per dish. There are plans for a 154
MW plant composed of heliostat towers using high-efficiency Spectrolab cells to be built in
Victoria in 2013.
Figure 4. Solar Systems CS500 concentrator dish (Stoddard (NREL), 2005).
The Ben-Gurion National Solar Energy Center in Israel is sponsoring a parabolic solar energy
concentrator at Sede Boger, in the Negev Desert, for research and development. PETAL (Photon
Energy and Transformation & Astrophysics Laboratory) is a 400 m2 parabolic dish consisting of
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
216 mirror panels that has the theoretical capability of concentrating sunlight up to 10,000X on a
small area (although this would require extremely accurate tracking to be effective, and therefore
costs would be high). For practical purposes, the panels were glazed and installed by the hand of
students and have variable precision. The dish is assumed to have a practical concentration of
400X (i.e., all the incident light on the dish is reflected to an area of 1 m2) for the purpose of
analysis.
The major drawbacks of larger dishes and towers are that they tend to require active cooling,
precise tracking systems for efficiency and safety, and are vulnerable to high winds.
2.2.2 Arrays of Independent Optical Systems
An array of small solar concentrator modules is proposed as an alternative to large dish systems.
The advantages of arrays can be both practical and economic; arrays are lighter and smaller than
dishes, making handling, installation, tracking, and maintenance easier, and are less susceptible
to problems with high winds. The array, consisting of many focal points, is also less likely to
burn something (or someone) at ground level should the tracking system malfunction. The array
is cooled passively by spreading the heat out on copper plates. The entire system is enclosed in
glass, is relatively simple, and consists of few components. Therefore, it is likely to be
compatible with high volume (low cost) production.
Fresnel lenses (Figure 5a) reduce the volume and weight of an optical lens with a slight reduction
in performance and have common historic uses, such as lighthouse beams. Fresnel lenses are
used in the solar field for both passive systems (such as hot water) and more recently, for CPV.
a
b
Figure 5. a. Fresnel lens compared with a regular lens (Wikipedia, 2006) b. Amonix Fresnel concentrator
solar array at the Arizona Public Service’s STAR research center (Amonix, 2006)
There are several groups researching Fresnel CPV, and a complete comparison is outside the
scope of this paper; nevertheless, it is worth mentioning a few of the current projects. The
NASA/JPL Deep Space I satellite is powered, in part, by a CPV array developed by Entech.
Amonix has 547 kW deployed by the Arizona Public Service’s STAR center (Figure 5b).
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
SolFocus has chosen to use reflection in lieu of refraction with a unique 2-mirror system, (Figure
6 & Figure 7). The advantages of SolFocus’s technology is that reflection is inherently less
complicated than refraction and the two mirror optical system is designed so that tracking
tolerance is 2 degrees, or 10 times that of standard CPV. This allows the implementation of
readily available components in the tracking system and higher functional tolerance for windy
days. Furthermore, in the case of a tracking system failure, there is little to no chance that the
reflected beams, if they should miss the second mirror, will concentrate elsewhere (spatially),
such that the risk of inadvertent burning is further minimized.
Figure 6. SolFocus Gen2 module tile showing 2 mirror reflection system (SolFocus, 2006).
Figure 7. SolFocus Gen2 module size (SolFocus, 2006).
2.2.3 Cooling and Excess Heat
Photovoltaic cells are designed for and operate best at relatively low temperatures, like most
electronic components. This is generally not a problem with traditional one-sun PV, but the
concentration of 500 suns generates a much greater amount of heat, which requires an effective
cooling scheme. Cooling can occur passively with the use of metal plates mounted behind the
cell that conduct excess heat to the air, or it can occur actively with the use of a water heat sink.
Arrays use passive cooling, while dishes and towers tend to require active cooling. Because the
cells must remain relatively cool (on the order of 100°C), the cooling water cannot become hot
enough to make an efficient heat engine due to limitations of Carnot's Law. However, municipal
heat or hot water might be a viable application.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
2.3
Solar Thermal Electric
As suggested by the name, solar thermal electric (STE) uses the concentrated heat from solar
radiation to generate electricity. There are several ways to use this heat to generate electricity.
One added benefit of STE is the availability of thermal energy storage (see Section 2.3.3), which
allows electricity generation even when the sun is not shining. STE also does not require cooling
since it is using the heat from the sun. The system is designed to operate at high temperatures.
The cost of STE is often lower than that of HEPV because STE technology uses standard
industrial manufacturing processes and power cycle equipment (heat exchangers, Rankine cycle
turbines etc), as will be explained below. This section will present the conventional methods of
utilizing the sun’s heat after it has been concentrated by the methods described in Section 2.1.
2.3.1 Conventional steam turbines
Parabolic troughs are often coupled with conventional steam turbines to generate power. A heat
transfer fluid (HTF), usually synthetic oil, circulates through the linear receiver at the focal line
of the parabolic trough and is heated up to several hundred degrees Celsius. The HTF then passes
through a series of heat exchangers where the heated fluid is used to generate high pressure
steam, which is then used to drive a steam turbine to generate electricity. The cooled HTF is recirculated through the solar field. An alternative design is to generate steam directly in the
receiver tubes, but this concept has yet to be commercialized. Figure 8 shows a schematic of
solar-trough technology using parabolic trough collectors and a steam turbine for electricity
generation. Solargenix, Solel, and Solar Millennium AG are companies that specialize in this
parabolic trough technology. Currently, this technology has the most commercial experience
compared to other CSP technologies and may offer the cheapest option for a near-term CSP
plant.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
Figure 8. A flow chart of the parabolic trough collectors, heat exchangers, and the turbine/generator system
(Kearney and Price, 2004).
Solar Towers also typically use conventional steam turbines to turn the sun’s heat into electricity.
The two prototype plants in Barstow, CA used this technology. Solar One heated steam directly
whereas Solar Two used a molten nitrate salt as HTF to generate steam for a conventional
turbine to produce electricity.
2.3.2 Stirling Engines
The dish concentrator method described in Section 2.1.2 is typically coupled with a Stirling
engine, which uses the heat to expand gas against a piston. The Stirling engine, fitted into a
canister the size of an oil barrel, is positioned at the focal point of the dish, with the sun’s rays
focusing onto the receiver end of the Stirling engine. The engine, first developed in 1816, works
by repeatedly heating and cooling a sealed amount of working gas, either air, hydrogen, helium,
or other gases. The company Stirling Energy Systems uses hydrogen. The heat from the sun
heats up the gas, which expands. The pressure created by expanding gas drives a piston; when
the gas cools, the piston retreats. This mechanical action turns a generator and produces
electricity. The gas moves between hot and cold heat exchangers. The hot heat exchanger is in
thermal contact with an external heat source (e.g. a fuel burner, or the surface receiving
concentrated solar insolation), and the cold heat exchanger is in thermal contact with an external
heat sink (e.g. air fins). The energy-conversion process does not require any water and is
emission-free since the chambers are all sealed. Tests in the Sandia National Laboratories have
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
shown that the Stirling dish technology is more efficient than HEPV cells and parabolic trough +
steam turbines systems.
Figure 9. Stirling engine (Stirling Energy Systems, 2006).
2.3.3 Thermal Energy Storage
During nighttime or overcast periods when there is no sun, STE technology can use thermal
energy storage (TES) to supplement output. An STE plant can store the heat received from the
sun during peak sun hours and dispatch this stored energy when additional power is required
during nighttime and overcast periods. Potentially the most important benefit of thermal storage
is the displaced cost of an additional peaking plant. We show in section 3.4.1 how peak solar
power leads peak electricity demand by about 4 hours. With the ability to store only a portion of
the solar energy (approximately 30%), a solar facility would completely displace peak power and
displace the need for a peak plant in both use and construction. TES, which has many
application routes, is fundamentally more applicable with a STE system than an HEPV system
because of the increased system temperatures found in STE. One can use a one-tank system or a
two-tank storage system, and there are different storage media, such as mineral oil, hydrocarbon
fluid or molten salts. For example, the Solar Two plant in CA used to store molten salts up to
600 degrees Celsius. The new Nevada plant by Solargenix may also add a salt-based storage
system some time in the future. The possibility is still in a research phase.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
STE Plants with thermal storage have higher capacity factors (up to 60% compared to a baseline
of 25%) and thus have lower overall levelized cost of electricity (Kearney & Price, 2006).
Integration of a thermal storage system also means that the availability of the electricity can be
planned. Figure 10 illustrates the generation scenario of an STE plant with thermal energy
storage. TES allows the plant to store energy during lower demand periods and deliver this
energy during high demand hours. Below we describe how using natural gas combustion is
another, simpler but nonrenewable technology that can be used to augment power conversion on
cloudy days and at night.
Figure 10 Conceptual Generation Scenario of an STE plant with thermal energy storage (NREL report, 2006)
2.3.4 Hybridization with fossil fuel
Another way for STE plants to increase their capacity factors is to operate with hybrid
solar/fossil. In fact, most STE plants built so far (e.g. the 9 SEGS parabolic trough plants in CA)
are hybridized with natural gas to ensure that electricity is still produced when the sun does not
shine for a few days. With a secondary backup fossil-fired capability, the capacity factor
remains high and the levelized cost of electricity is lowered (Kearny & Price, 2004).
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
Figure 11. Performance history of the hybrid solar/natural gas SEGS plants in CA (Western Governors’
Association Solar Task Force Report, 2006).
3
Economic Overview
Utility solar power plants must compete with fossil-fuel power plants at wholesale prices, as
opposed to common rooftop PV, which competes at retail prices. For the sake of simplicity, the
discussion is limited to wholesale electricity generation costs for a new power plant, and
additional benefits such as hot water generation are reserved for the end.
It is common to use levelized cost of electricity (LCOE) as a metric to compare the prices of
various power sources. LCOE can be interpreted as a constant level of revenue necessary each
year to recover all expenses over the expected economic life of the project, assuming all costs are
known. It takes into account the capital cost, the annual operations and maintenance (O&M)
costs, fuel costs, plant lifetime, and the capacity of the plant. LCOE alone is not a sufficient
metric for comparison. We also need to access the availability of the power source (e.g. capacity
factor and peak supply periods, which determines whether to operate as baseload or peaking
power) and the gross capacity of the technology. In addition, one of the major difficulties in
comparing the costs of CSP technology with conventional fossil fuel sources is the variable cost
of fuel, in particular that of natural gas. In this analysis, cost projections for natural gas plants
are made based on gas price fluctuations in previous years while the authors note that the
accuracy of these projections may be compromised due to the highly unpredictable fuel costs.
3.1
Electricity in California
The consumer price of electricity comprises the normal wholesale (generation) price,
transmission costs, and sliding scale prices that fluctuate with higher demand and peak
generation. The average retail price of electricity in California was 11.4 cents/kWh in 2005, and
slightly higher (12.9 cents/kWh) for customers of Southern California Edison (SCE) in Santa
Barbara. SCE produced 78 TWh in 2001. To bring things into perspective, a new 1000MW
power plant would generate 2.9 TWh per year (or 3.7% of SCE demand), assuming that the plant
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
is capable of running at peak power 8 hours per day. California relies on a variety of power
types (Table 1) with highly variable wholesale prices (Table 2).
Table 1: California 2005 Gross System Power in GWh/yr (CEC, 2005).
Fuel Type
Coal
Large Hydro
Natural Gas
Nuclear
Renewables
Biomass
Geothermal
Small Hydro
Solar
Wind
Total
In State
28,129
34,500
96,088
36,155
30,916
6,045
14,379
5,386
660
4,446
225,788
NW
Imports
4,926
12,883
1,786
691
0
SW
Imports
24,796
1,701
10,812
4,861
0
GSP
57,851
49,084
108,686
41,707
30,916
6,045
14,379
5,386
660
4,446
288,244
GSP %
20.1%
17.0%
37.7%
14.5%
10.7%
2.1%
5.0%
1.9%
0.2%
1.5%
Table 2: California 2003 wholesale power prices by utility type (CEC 2003).
Technology
Combined
Cycle
Simple Cycle
Wind
Hydropower
Solar Thermal
Parabolic
Trough
Parabolic
Trough-TES
Parabolic
Trough-Gas
Geothermal
Flash
Binary
Energy
Source Fuel
Operating
Mode
Economic
Lifetime
(years)
20
Gross
Capacity
(MW)
500
Direct Cost
Levelized
(cents/kWh)
5.18
Natural Gas
Baseload
Natural Gas
Wind;
Resource
Limited
Water;
Resource
Limited
Peaking
Intermittent
20
30
100
100
15.71
4.93
LoadFollowing,
Peaking
30
100
6.04
Sun; Resource
Limited
Sun; Resource
Limited
Sun/Natural
Gas; Partially
resource
limited
LoadFollowing
LoadFollowing
LoadFollowing;
Peaking
30
110
21.53
30
110
17.36
30
110
13.52
Water
Water
Baseload
Baseload
30
30
50
35
4.52
7.37
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
The wholesale price is entirely dependant on the specifics of the construction of the power plant,
discount rate, and operation and maintenance for the plant for the year. Fossil-fuel plants are
relatively cheap to build in comparison with solar plants; however, they require considerably
more in yearly O&M cost as they must purchase fuel to run the plant. California produces
approximately 78% of electricity consumed in-state; of which 57% is generated at fossil-fuel
plants (this does not include the actual production of fossil fuels).
Table 2 shows that if CSP were to be cost-competitive with conventional fossil fuel power
sources, its cost has to be reduced by 75%, from the current level of 20¢/kWh to 5¢/kWh. At the
same time, CSP availability often coincides with periods of peak power demand since peak
production matches peak demand when the sun is strongest. Costs at peaking periods are higher
than baseload costs since additional engines/plants have to be operated to provide extra power.
So the levelized cost of CSP does not have to be reduced to the wholesale price of baseload in
order to be cost competitive.
There are many ways to drive the cost of CSP down. The most obvious way is to scale up the
system and increase plant size. Also, cost reduction is achievable through increased plant
deployment. This is commonly known as the learning curve. Typically, the cost is reduced by
20% every time the cumulative capacity of the technology is doubled. Technological advances,
such as increasing the collector size, improvements in collector coatings, and development of
thermal energy storage technologies, can help reduce the cost (Kearny & Price, 2004).
Government policies such as tax credits and market incentives (e.g. renewable portfolio
standards) are often favorable to solar technologies. Another consideration is the hybridization of
CSP with combined cycle power plants (natural gas), as mentioned in Section 2.3.4.
Year in service
Capacity
factor [%]
Nominal
LCOE
[$/kWh]
Real LCOE
[2004 $/kWh]
Trough
solar 100
2006
29.3
Trough
hybrid 100
2006
39.8
Trough with
TES 100
2006
41.2
Trough solar
200
2011
30.6
Trough with
TES 100
2011
57.9
Trough with
TES 200
2011
56.0
0.133
0.135
0.130
0.101
0.099
0.092
0.094
0.096
0.092
0.072
0.07
0.065
Table 3: Projected costs of parabolic trough technology with and without thermal energy storage and
hybridization with natural gas
3.2
CPV Analysis
Several papers have been written on the subject of CPV wholesale costs using a variety of
different scenarios. Swanson (2000) cites several previous studies that show wholesale prices to
be on the order of 6-10 cents/kWh for well-developed concentrator PV systems in the 100kW100MW range. Faiman et al (2007) present a case that solar power could initially charge 10
cents/kWh and drop the rate steadily over time as capital costs are paid. Their model is based on
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
a staggered construction 1 GW plant using Amonix-type Fresnel technology in the southwestern
U.S. and a financial model developed by D. Raviv (Raviv & Rosenstreich, 2003; Faiman, 2005).
Companies developing these technologies offer their own analyses and predictions, which can be
somewhat difficult to quantify with any certainty without commercial installations. The
following estimates are based on conversations with the companies discussed, published wattage
and overall project costs, and assumptions made by the authors. It should be noted that these
numbers were not verified or checked by the companies at stake, and that a priority for
continuation of this work would be a detailed dialogue with these companies.
In order to understand these estimated costs, we attempted to mimic the calculations performed
in some of the reviewed papers and formulate best guesses for existing technology based on the
best information available. The theoretical large dish and Fresnel system costs were calculated
to be 6 – 14 cents/ kWh, which seemed reasonable and consistent. Calculating the cost per
kilowatt hour for existing and proposed systems and future goals of SolFocus and Solar Systems
was the next step, results shown in Figure 12, Table 4, and Appendix A. Our price estimate of
the SolFocus prototype was 44 cents/ kWh (45 cents/kWh was their estimate) using costs of
$10/Watt module, $0.25/W tracking and $0.50/W BOS, all of which were given to us by
SolFocus (pers. comm. S. Horne). Next, we estimated the probable current cost assuming no
changes in the tracking or BOS, but a $2.50/W module (SolFocus’s current cost estimate), which
yielded a price of 12.2 cents/kWh. And finally, we calculated the future price of electricity,
should SolFocus reach their goal of a module price of $1/Watt at 1 GW cumulative capacity, to
be 6.3 cents/kWh.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
CPV Price estimates
100
70
50
40
30
cents/kWh
20
Probable but unproven
10
7
5
4
3
2
SolFocus
Solar Systems
Reseach Papers
Proven Capability
1
0.7
0.5
0.01
0.1 0.2
0.5 1
2 3 45 7 10 20
50 100 200 5001000
5000
MW Installed
Figure 12: CPV preliminary electricity price estimates.
For Solar Systems, we considered both the existing 720 kW dish systems and a 154 MW
heliostat plant proposal. The dishes cost $7M Australian dollars (AUD) at a module cost of
$5/W (USD) (pers. comm. Solar Systems) which result in an electricity price of 50 cents/kWh
(USD). The heliostat plant has been proposed for $450M AUD which yields a projected price of
14.5 cents/ kWh (USD). Note that these estimates are based on very limited data and have not
been reviewed by Solar Systems.
Table 4: Analyses performed for CPV (details in Appendix A), all numbers in real US dollars (2004).
GaAs - Dish
100
33%
500
$2.42
$242,424,242
Dish Systems
Raviv Fresnel*
3-Junct Fresnel
1000
32%
625
$0.16
$160,000,000
$97,500,000
$1,825,000,000
$41,121,000
$339,924,242
$1,985,000,000
$43,851,000
Scenarios
Capital Costs
Capacity (MW)
Efficiency of Module
Concentration
Solar Modules ($/W, conc.)
TOTAL SM for Plant
TOTAL BOS for Plant
TOTAL COST for Plant
Faiman*
PETAL - Si
30
16.50%
>400
$0.091
$2,730,000
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
YEARLY COSTS (1-2%
Capital)
Capacity Factor
Yearly power output MWh
Plant Life (years)
Capital Recovery Factor
Costs per year
Costs per kWh (plant lifetime)
Capital Costs
Capacity (MW)
Efficiency of Module
Concentration
Solar Modules ($/W, conc.)
TOTAL SM for Plant
TOTAL BOS for Plant
TOTAL COST for Plant
YEARLY COSTS (1-2%
Capital)
Capacity Factor
Yearly power output MWh
Plant Life (years)
Capital Recovery Factor
Costs per year
Costs per kWh (plant lifetime)
$5,098,864
$21,900,000
$657,765
25%
219000
30
0.077
$31,129,393
$0.142
25%
2190000
30
0.077
$173,906,223
$0.079
25%
65700
30
0.077
$4,015,762
$0.061
Heliostat
Dish
Tower
Dish
proj. HCPV
Solar Systems, AU
0.72
154
24%
38%
500
500
$5.00
$3.46
$3,600,000
$532,177,215
0.1
38%
500
$10.00
$1,000,000
SolFocus
projected
SolFocus
100
38%
500
$2.50
$250,000,000
$50,000
$50,000,000
$500,000,000
$5,040,000
$1,050,000
$300,000,000
$1,500,000,000
$8,640,000
$532,177,215
$15,750
$4,500,000
$22,500,000
$129,600
$7,982,658
25%
219
30
0.077
$96,156
$0.439
25%
219000
30
0.077
$27,473,233
$0.125
25%
2190000
30
0.077
$137,366,163
$0.063
25%
1577
30
0.077
$791,229
$0.502
25%
337260
30
0.077
$48,735,428
$0.145
prototype
SolFocus
goal
SolFocus
1000
38%
500
$1.00
$1,000,000,000
(incl above)
The development of high efficiency PV cells will also drive down the costs of CPV as a given
power plant will be capable for producing 50% more power in the near future, with potentially
higher gains as theoretical multi-junction PV cell limits of 60-70% become a reality. It will
probably become cost-effective to replace PV cells on older systems with the highest efficiency
cells available. An attempt was made to analyze the potential learning curves; however, the
details regarding the portions of cost attributable to new technology (e.g. modules and optics)
and developed technology (e.g. trackers and BOS) were not clearly divided, and the authors were
wary of comparing the technologies. The unfinished analysis is shown in Appendix B.
The major drawback to CPV at the present time is that there are very few installed systems in
operation, therefore the reliability is unproven and costs are somewhat unknown. However,
since most of these technologies are immature, there is a great deal of room for costs to decrease
from their present values. It is highly likely that the installation of a few more systems will make
it considerably easier to fund additional projects.
3.3 STE Analysis
In this section, we consider the economics of a parabolic trough plant, which is currently the
lowest cost option with the most commercial experience among the different STE technologies.
Table 3 shows the projected baseline cost (excluding investment tax credits) of a 100MW-
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
200MW parabolic trough plants to be built in 2007-2015. The projected capital costs and yearly
costs were obtained from the NREL report (2006), and costs per kWh were calculated based on
our own models. These calculated costs were similar to those predicted by NREL’s model.
Table 5. Cost projections and cost breakdown for parabolic trough plants of 100-200MW capacity in the
near future.
Parabolic trough plant
Year built
2007
2007
2009
2011
2015
Thermal Energy Storage
no TES
6 hrs TES
6 hrs TES
6 hrs TES
6 hrs TES
100
100
100
150
200
Capacity (MW)
Capital Costs
Solar field
$230,856,000 $230,856,000 $205,109,000 $243,059,000 $268,441,000
Balance of Plant
$22,533,000 $22,533,000 $22,533,000 $28,432,000 $33,036,000
Thermal Energy Storage
$0 $57,957,000 $57,937,000 $71,320,000 $89,390,000
Others
$183,040,000 $183,040,000 $172,011,000 $210,573,000 $240,506,000
$436,429,000 $494,386,000 $457,590,000 $553,384,000 $631,373,000
Total Capital cost
$6,713,000
$6,713,000
$6,103,000
$7,445,000
$8,879,000
Yearly Costs (O&M, labor)
Capacity Factor
28.4%
40%
40%
40%
40%
Yearly power output (MWh)
41179
45756
42240
51148
58741
Plant Life (years)
30
30
30
30
30
Capital Recovery Factor
0.079
0.079
0.079
0.079
0.079
Cost per year
$41,179,308 $45,756,373 $42,240,466 $51,147,649 $58,740,710
Cost per kWh
$0.166
$0.131
$0.121
$0.097
$0.084
Table 5 shows that parabolic trough technology has the potential for significant cost reduction in
the next 10 years. A plant built in 2007 will produce electricity at about $0.131/kWh whereas a
plant built in 2015 may be able to produce power at $0.084/kWh. Cost reduction is mainly due
to 2 reasons: technological advances and increased deployment. As mentioned in previous
sections, the learning curve estimates that the cost of a technology is reduced by 20% when the
cumulative capacity doubles. It has been predicted that the cumulative capacity of parabolic
trough STE will be between 2100MW and 4000MW by 2020. The low and high scenarios are
depicted in Figure 13. Taking into account this increase in cumulative capacity and assuming a
20% learning curve, one can estimate the future costs of parabolic trough STE technology.
Figure 14 shows the result of this analysis. The starting cost of $0.14/kWh in 2008 is used.
This number will differ depending on whether thermal storage is used and whether it is a hybrid
solar/natural gas plant. The costs of electricity generation from natural gas are indicated in
Figure 14 for comparison. Due to natural gas price volatility, the price of electricity from simple
cycle and combined cycle plants will span a range, as indicated by the grey band in the Figure
14. We see that the cost of parabolic trough STE is predicted to become cost-competitive with
natural gas in about 2013-2016.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
4000
low deployment scenario
3500
high deployment scenario
cumulative MW
3000
2500
2000
1500
1000
500
0
2008
2010
2012
2014
year
2016
2018
2020
Figure 13. Two deployment scenarios of CSP plants. Current projections predict that the cumulative
capacity will be between 2100 MW (low) and 4000 MW (high) by 2020.
0.2
low CSP deployment scenario
0.18
high CSP deployment scenario
levelized cost of electricity
[2006 $/kWh]
0.16
simple cycle
0.14
0.12
0.1
0.08
combined cycle
0.06
0.04
0.02
0
2008
2010
2012
2014
2016
2018
2020
year
Figure 14. Projected reduction in cost of CSP according to the 2 different deployment scenarios depicted in
Figure 13 above and with a 20% learning curve. The price ranges for simple cycle and combined
cycle (natural gas) are included for cost comparison.
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Thermal Solar Electric, ERG 226, December 2006.
3.4 Added Value of Solar
The value of solar generated electricity is not fully accounted for in traditional cost analyses
which consider the capital costs of building and maintaining the plant, as well as the capital
recovery factor and price of electricity over the lifetime of the plant. Value can be added through
tangible economic means, such as the selling of steam heat or municipal hot water, or through
less tangible means, such as reduced emissions and greater human health. It is beyond the scope
of this report to do complete analyses encompassing all of these benefits; instead, we describe
the types of potential added value and assign a monetary value where we have the necessary
information.
The overall added value of solar ranges between 3.3 and 7.9 cents per kilowatt hour for costs that
are not already accounted for in the current wholesale price, not including hot water. This
increase in solar value might be able to bring the price of utility-scale solar power at or below the
price of coal and natural-gas power plants!
Some of the unpriced value may be converted into real dollars if, for example, a carbon tax is
levied or fossil-fuel plants otherwise penalized for detrimental health conditions, or if municipal
heat or hot water is planned. In addition, the utilities are required by law to produce a certain
percent of energy as renewable; these laws are likely to get stricter with time and the value and
scope of renewable energy credits is likely to increase. Renewable energy credits and similar
incentive programs may bring the tangible economic benefit of solar energy to a competitive
level with fossil fuels. Therefore, the added value estimates of 3.3 to 7.9 cents/kWh may be low.
Table 6: Added value of solar energy replacing fossil fuels. The last two rows
have the added value that isn’t already accounted for in present energy costs.
Source
Peaking Capacity
Fuel Hedge
NOx
PM10
CO2
Health Benefits
Solar Heat/Hot Water
Saved Water Use
Total, no hot water
Total, with hot water
Unaccounted for in Current
Prices, no water
Unaccounted for in Current
Prices with hot water
cents/kWh
Low Est.
2.73
0.41
0.01
0.02
0.19
0.01
3.00
0.01
Middle Est.
3.37
0.68
0.21
0.03
1.06
0.03
6.00
0.03
High Est.
4.01
0.95
0.41
0.04
1.93
0.05
9.00
0.05
3.38
6.37
3.34
5.41
11.38
5.14
7.44
16.39
6.94
6.34
11.14
15.94
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
3.4.1 Peaking Capacity
Solar power plants have great potential to replace peak demand power plants and therefore are
worth more to the utility than their price might suggest. Peak demand in California occurs on hot
and sunny summer days when air conditioners are running. Utilities must put extra power plants
on line during these times; the intermittent and inefficient operation of these peak power plants
can drive wholesale electricity costs upwards of 20 cents/kWh (see Table 2).
Solar power peaks on the same days and nearly the same times (slightly earlier) as the peak
demand, i.e. afternoons of high insolation. The peaks of solar and demand are not exactly
matched, however, and the capability of solar to cover the peak demand is estimated at 65%
(ASPv, 2005) without storage. Economically accounting for the peak capacity coverage shows
that solar is worth an additional 2.73 to 4.01 cents/kWh (ASPv, 2005), or that solar is
undervalued by 50% (Borenstein, 2005), which translates into about 3 cents/kWh.
The peaking capacity could be improved if a few hours of power storage existed on-site, which
could also improve the overall capacity factor by 20% (NREL report, Stoddard et al, 2006). The
additional cost of battery storage has been included in some but not all of the STE analyses
presented and none of the HEPV analyses.
Figure 15. PV power performance compared with prices, July weekday (Borenstein, 2005). The left PV
curve (dotted line) corresponds to a south-facing surface, while the right curve corresponds to a west-facing
surface. The tracking system required for CPS would result in a production curve centered at midday and
broadened (solid red line estimated from NREL Data, Maxwell 1987).
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
3.4.2 Value of Solar Heat or Hot Water
CSP may require active cooling processes which creates an opportunity to use the excess heat for
municipal hot water, steam-controlled building heating, and thermal energy for air-conditioning.
Residential and commercial heating use 40% of the natural gas consumed in the U.S., so the
market is potentially huge. Cogeneration is commonly used for heating and cooling of large
institutions, such as universities, medical facilities, business parks, or factories, who would be
the most likely end-users of power-plant steam (as opposed to residences). The concept of
power-plant waste steam has been tested in the past; a project in the Shenandoah produced 400
kW of power with 114 dishes and 3 MW of thermal energy (in the form of 1380 lb/hour of 175
degree C saturated process steam) which was used to provide 257 tons of 45 degree F water for
air conditioning of a knitwear factory (H. Hewitt, pers. comm. 2006).
The present cost of natural gas is about $8.00/MBtu, or about 1.87cents/kWh. If solar energy is
converted to electricity with 20% efficiency, then 80% is left over for thermal conversion, or 4
times the electrical energy. Because some heat will certainly be lost to the environment
regardless of the choice of technology, it is reasonable to frame the amount of recoverable
energy between 20% and 60%, or between one and three times the electrical energy produced.
Lastly, the thermal efficiency of heating water with natural gas is between 50% and 60% for
household water heaters (DOE, 1995) but is bound to be higher for large industrial complexes.
We can now estimate the amount of money saved by heating water at between 3 cents/kWh, and
9 cents/kWh. This savings is not absolute because the cost of the associated infrastructure has
not been added, the necessary pipes and pumps to take the water to a nearby community.
However, if this SEGS is built in conjunction with a company that needs heated water, such as
the proposed ethanol plant in Santa Maria, the savings would be near absolute, or potentially
even more depending on the price the plant would pay for natural gas. While fossil fuel power
production can also receive the hot water added value, it may be precluded due to specific site
concerns such as local neighborhood, or restriction of desired plant size.
The actual value of this commodity is likely to vary depending on the proximity of developed
areas to the power plant; however, since solar is clean and relatively inoffensive to residential
areas, it has great potential to be collocated with homes and businesses. Furthermore, the
productive use of such heat would add an environmental benefit in the reduction of thermal
pollution to local water resources, which has been shown to harm stream ecology and fish
populations. Because the possibility of using cogenerated heat is unclear, total value of the solar
has been calculated with and without heated water in table 6.
3.4.3 Volatility of Fuel (Natural Gas) Prices
The cost of natural gas or other power plant fuel is captured in the wholesale price of electricity,
however, the volatility of such prices is well-known and there are associated costs with budget
uncertainty and potentially uneconomic projects, especially on a power plant time-scale (ASPv,
2005; E3 & RMI, 2004). The calculation of a fossil fuel hedge is complex which requires
consideration of resources and fixed-price contracts, however, a first order estimate can be
obtained. The value of a fossil fuel hedge is calculated by applying the heat rate end points of
7100 Btu/kWh and 11,100 Btu/kWh (ASPv, 2005) with the electricity forward market price
quotes and NYMEX gas futures prices (E3 & RMI, 2004) for the subsequent 4 years, with
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
greater uncertainty beyond. ASPv estimates the value of the fossil fuel hedge to be 0.41 – 0.95
cents/kWh.
It should also be noted that the overall price of natural gas is rising, but that there is no clear
consensus on projections into the future, and the projected rise in (real dollars) price per year is
well under 1 percent (EIA, 2005). Therefore, we have made no such assumptions in this study,
but it is useful to be aware of it.
3.4.4 Nitrogen Oxides (NOx)
Nitrogen oxide emissions are currently regulated and the cost of these emissions is likely already
captured in the wholesale price of electricity. The Americans for Solar Power (ASPv, 2005)
acknowledge this, but still count it as an added value to solar, depending on how costs are broken
down. We are including it in this discussion since the regulations may change with increasing
environmental pressure, driving the cost of fossil-fuel power higher, with a cautionary note for
future modelers to avoid double-counting. The current cost of NOx emissions is calculated at
0.01 – 0.03 cents/kWh using the heating rates for the two types of gas-fired generators (ASPv,
2005). Using prices and assumptions outlined in the E3 report, we calculate NOx prices to be
currently 0.018 - 0.077 cents/kWh (E3 & RMI, 2004). It should be noted that the E3 report also
project the price of the NOx emission to rise 32% in the next 6 years and 500% by 2024!
Therefore, the price of NOx emissions is potentially as high as 0.41 cents/kWh in 20 years
(Figure 14).
NOx and PM10 projected prices
0.45
0.4
cents / kWh
0.35
NOx 0.05 lb/MWh
NOx 0.22 lb/MWh
PM10 0.033 lb/MWh
PM10 0.072lb/MWh
0.3
0.25
0.2
0.15
0.1
0.05
0
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024
Year
Figure 16. NOx and PM10 price estimates using data from the E3 (2004) and ASPv (2005) reports.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
3.4.5 Particulate Matter (PM10)
Particulate matter of size less than 10μm (PM10) is also currently regulated and this cost is likely
already reflected in the wholesale price of electricity. Using prices and assumptions outlined in
the E3 report, we calculate PM10 prices to be currently 0.016 - 0.035 cents/kWh (E3 & RMI,
2004). It should be noted that the E3 report also project the price of the PM10 emission to rise
32% by 2010.
3.4.6 Carbon (CO2)
There is currently no regulation on carbon emissions, unlike NOx, and therefore it is currently an
unpriced externality not reflected in the wholesale price of electricity. However, with the
increasing environmental pressure, many experts feel that this is unlikely to remain the case over
the 20-30 year lifetime of a power plant. The price on carbon has a variable estimation of
$20/ton C (D. Kammen, pers. comm., 2006), $29/ton C (ASPv, 2005), and $29 ton C rising to
$35 ton C by 2010 (E3, 2004). Furthermore, if the US and the International community were to
make a serious effort to comply with the Kyoto protocol, the price could rise to $65/ton C by
2013 (E3, 2004).
The effective price of carbon at a natural gas plant will therefore be a function of the efficiency
of the plant. Currently, it is estimated that carbon would be priced about $30 / ton C, resulting in
an added value of 0.3 to 0.6 cents/kWh (or higher, depending on efficiencies). Future rises in
carbon tax should also be considered, and have the potential of driving the carbon price much
higher, although some of this may be offset by efficiency gains in a natural gas plant.
Added Value of Carbon (Natural Gas)
1.5
700 lb/ MWh
1500 lb/MWh
1.4
1.3
1.2
cents / kWh
1.1
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
20
25
30
35
40
45
50
55
60
65
$ / ton Carbon
Figure 17. Added Value based on future carbon tax.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
3.4.7 Health Benefits
The value of health benefits is documented in the ASPv (2005) report as a measure of avoided
health-related incidents in the state of California from a study by Abt Associates (2000). The
health benefits are related to reduced NOx and SO2 power plant reductions assuming the value is
$1.94/lb and is estimated to be between 0.01 – 0.05 cents/kWh.
3.4.8 Avoided Water Use Cost
Natural gas combined-cycle generators consume water in the cooling process while many solar
electric plants consume no water in the generation of electricity, instead using passive cooling or
a cooling and heating cycle thermal engine. Americans for Solar Power (2005) has estimated
that a natural gas plant uses 0.18 gal/kWh and that water costs $0.51 - $2.19 per hundred cubic
feet, translating into a direct cost of 0.053 – 0.012 ¢/kWh. (ASPv, 2005)
This avoided water use cost does not account for the societal and environmental cost of water
used: therefore, it can be inferred that the actual value is higher. On the other hand, the cost of
water is likely already included in the yearly maintenance costs of the natural gas plant, and
therefore already accounted for in the wholesale price.
4
Conclusions
We present a preliminary analysis of Concentrated Solar Power (CSP) technologies for both
a utility and small industrial potential application in Santa Barbara County. While the present
technologies of trough solar thermal electric are more expensive than conventional combined
cycle natural gas, the added solar value due to natural gas price volatility and displacement of
peak electrical production already make the trough technology competitive in cost-effectiveness
while contributing to California’s climate change policy goals. Additional value would be
realized with thermal energy storage (TES) allowing solar to completely displace peak power
production. With additional advances in solar thermal efficiencies, improvements in associated
tracking and conversion technologies, increasing prices of natural gas, and concern (and
associated legislation) over CO2 emissions, one would expect trough focused and the newer dish
focused STE to become more advantageous. High efficiency photovoltaic (HEPV) technologies
forecast electrical production at well below the price of conventional fossil fuel methods. There
has been no significant HEPV power production as yet, so these predictions can carry little
weight. However, this very new field is advancing quickly, and we recommend continued
analysis as the first demonstration plants are put into place.
Although we have found both Solar Thermal Electric (STE), and High Efficiency
Photovoltaic (HEPV) technologies to be competitive with fossil fuel power production in the
long term, we endorse neither over the other. The fit of the individual attributes of each
technology to the specific application will be the deciding factor between the two. HEPV will
most likely have an ultimate better efficiency. STE has a proven track record and is more easily
adaptable to thermal energy storage. Both technologies have potential for significant additional
cost reduction. The use of waste heat for hot water or air conditioning figures pivotally into the
cost balance. While both technologies can benefit from this added value, the addition is most
simple in an STE system. Lastly, local deployment of CSP in a community or business would be
exceedingly cost effective, as it would both displace electrical use at the retail rate, and be able to
supply hot water or steam to the community or business.
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Zimmer, V.L., Woo, C., & Schwartz, P., Concentrated Solar Power for Santa Barbara County: Analysis of High Efficiency Photovoltaic and
Thermal Solar Electric, ERG 226, December 2006.
By the time Santa Barbara is ready to begin construction, there will be significant
improvement in CSP. Santa Barbara has the tangible opportunity to lead the world in developing
an infrastructure that significantly contributes to the county’s energy needs, saves money, avoids
dangerous climate change, and builds local expertise that will be a valuable commodity as the
rest of the world emulates.
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