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7
Scenarios
This chapter considers the extent to which renewable technologies might
contribute to the future U.S. electric power supply. To come to conclusions about the
level that renewables might contribute to electricity generation, we focus on scenarios of
the technologic, economic, environmental, and implementation-related characteristics
that may enable a greater fraction of renewable electricity. How much these factors
might affect the market penetration of any individual renewable resource would depend
on the rate at which generation from additional renewables is introduced. Under business
as usual conditions without major policy initiatives to speed deployment, the introduction
of renewables into electricity markets can continue to at a moderate pace, with the growth
rate and technology learning following a conventional S curve. But if policymakers or
external conditions were to bring a sense of urgency to addressing concerns such as
energy security or climate change, the question would become how to accelerate the
market penetration of renewables, while minimizing impacts on electricity’s price, the
environment, the reliability of electricity service, and the ability of industry to
manufacture and deploy relevant technologies. The scenarios selected by the panel allow
exploration of such issues.
These scenarios discussed below in this chapter were chosen to represent
aggressive but achievable rates of renewables deployment in the U.S. electricity sector,
provided that significant policy and financial resources are devoted to the effort.
Scenarios do not represent a simple extrapolation of historical growth rates, but instead
reflect a more integrated perspective on the conditions required to scale up renewables
deployment. The panel’s criteria in choosing the particular scenarios it presents were
whether the scenario was developed with input from multiple stakeholder groups and
whether it underwent peer review. The panel also considered the degree to which each
scenario assessed not simply deployment rates and cumulative levels of generation but
also economic, financial, human, and environmental facets. Many of the scenarios
described here have been released over the past few years, which helps ensure that inputs
to the scenarios reflect recent conditions.
OBJECTIVES FOR SCENARIOS
Scenarios provide conceptual and quantitative frameworks to describe and assess
how renewable resources’ contribution to electricity supply might be significantly
increased. Such scenarios are a primary way to quantify materials and manufacturing
requirements, human and financial resource needs, and environmental impacts that come
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with greatly expanding electricity generation from renewable electricity sources. These
scenarios typically use qualitative analysis, quantitative assumptions, and computational
models of the energy, economic, and/or electricity systems. They attempt to integrate the
environmental, technologic, economic, and deployment-related elements into an
internally-consistent analytical framework. The panel considered two types of scenarios.
The first type analyzes increased market penetration of a single resource, such as solar or
wind. A prominent example is the 20 percent wind study (DOE, 2008) described in more
detail in the following section. Examples for solar energy include the DOE Solar
America Initiative (SAI; DOE, 2007b), the Photovoltaics Industry Roadmap (SEIA,
2001, 2004), and the 10 Percent Solar Study (Pernick and Wilder, 2008). The scenarios
described here are used to assess issues such as:
• Land-use impacts, manufacturing and employment requirements, and
economic costs associated with an assumed market penetration of a single renewable
resource (e.g., 20 percent electricity generation from wind power and more than 50
percent electricity generation from solar);
• The additional transmission, distribution, and other technologies needed to
incorporate or enhance the use of intermittent renewable resources in the electricity
market; and
• The cost-reduction trajectories needed to make solar electricity widely
competitive with other electricity sources.
A second type of scenario examines how renewables interact with other sources
of electricity, other sources of energy, and end-use energy demands (CCSP, 2007; EIA,
2008a). Through the use of long-term energy-economic models, these scenarios enable
assessment of the potential impacts of demographic, economic, and regulatory factors on
renewable electricity within a framework that considers the whole energy sector. The
scenarios described here are used to explore issues such as:
• How wider energy-economic interactions and the electricity market could
affect market penetration by renewables;
• The impacts of environmental, economic, and/or energy policies on end-use
demand and electricity generation from renewables and other sources.
These scenarios, as with the reference case scenario presented in Chapter 1, are
not predictors of the future, and the results of scenarios are not forecasts. Rather, they are
descriptions of one set of conditions that could result in significantly increased market
penetration by one or several renewables over what is estimated based on present-day
conditions and a business-as-usual future. They demonstrate the costs, benefits, and scale
of the challenges associated with increasing the integration of renewables into the
electricity sector.
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EXAMPLES OF HIGH PENETRATION SCENARIOS
20 Percent National Wind Penetration Scenario
The American Wind Energy Association and DOE’s National Renewable Energy
Laboratory (NREL) developed a scenario assuming that 20 percent of electricity
generation would come from wind power by 2030 (DOE, 2008). The scenario included
assessments of the wind resource base, materials and manufacturing requirements,
environmental and siting issues, transmission and system integration, costs, and public
policy drivers (Smith and Parsons, 2007). The scenario estimated that more than 300
GW of new wind power capacity would be needed to meet a goal of 20 percent market
penetration by wind, of which about 250 GW would be installed onshore and 50 GW
installed offshore. Under this scenario, in 2030 wind power would produce about 1.2
million GWh out of a total U.S. electricity generation of 5.8 million GWh. All impacts
for the 20 percent wind scenario (such as costs and impacts on CO2 emissions) were
estimated through a comparison to a base case that assumed no new wind capacity
additions after 2006, which is a more pessimistic base case in terms of wind power than
both the AEO2007 and AEO2008 versions (EIA, 2008b,c). Because the 2008 DOE
report contained “influential scientific information” as defined by the Office of
Management and Budget’s (OMB’s) Information Quality Bulletin for Peer Review, it
was subjected to interagency peer review.
Manufacturing, Materials, and Resources
Manufacturing and other requirements to implement a 20 percent wind scenario
are significant. Figure 7-1 shows the amount of annual installed capacity needed to
increase to 300 GW by 2030 from approximately 12 GW in 2006. Though the scenario
limited the annual capacity increase to 20 percent, it assumed an extremely large
expansion of manufacturing, materials, and installation capacities. It projected that by
2018 the amount of annual installed capacity in the United States would be over 16 GW,
compared to a global wind turbine manufacturing output of about 15 GW in 2007, of
which approximately 2.5 GW went to the U.S. market (DOE, 2007a). As discussed in
Chapter 1 of the panel’s report, an additional 5 GW of capacity was added in the United
States in 2007 and over 8 GW in 2008, both exceeding the trajectory for the 20 percent
wind scenario. Even assuming that growth outside the United States would be more
modest, this scenario would require a continued large expansion of the manufacturing
base. Global growth in wind power is likely to continue to be strong. For example, the
Commission of the European Communities’ roadmap for renewables proposes that the
European Union establish a mandatory target of 20 percent for renewable energy's share
of energy consumption in the EU by 2020, much of which would be met with wind
power (Commission of the European Communities, 2007).
The 20 percent wind scenario also contains critical challenges to fulfill materials,
capital, and employment requirements. Table 7-1 shows the level of raw materials
needed to meet this scenario. While some quantities would be small relative to global
production, Smith and Parsons (2007) concluded that supplying fiberglass, core materials
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(balsa and foam), and resins could be difficult, as would supplying a sufficient number of
wind turbine gearboxes. Assuming that the average-sized wind turbine would be in the
1-3 MW range, with modest introduction of large 4-6 MW turbines, there could be a total
of almost 100,000 wind turbines installed (Wiley, 2007; DOE, 2008). The average
number of turbines installed would have to increase from its present level of 2,000 per
year to 7,000 per year by 2017 (DOE, 2008).
TABLE 7-1 Raw Materials Requirements for 20 Percent Wind Scenario (thousands of tons per
year)
Glass- Carbon
reinforced Fiber
Year Concrete Steel Aluminum Copper Plastic Composite Adhesive Core
2010 6,800 460 4.6 7.4 30 2.2 5.6 1.8
2015 16,200 1,200 15 10 74 9 15 5
2020 37,000 2,600 30 20 162 20 34 11
2025 35,000 2,500 28 19 156 19 31 10
2030 34,000 2,300 26 18 152 18 30 10
SOURCE: Adapted from material in Wiley (2007).
The NREL Wind Development System (WinDS) model, which simulates
generation capacity expansion in the U.S. electricity sector for wind and other
technologies through 2030, estimates that the 20 percent wind scenario would result in a
direct increased cost for the total electricity sector of $43 billion dollars (U.S.$2006) in
net present value (NPV) over the no-new-wind case. Table 7-2 shows the breakdown of
direct electricity sector costs for the 20 percent wind scenario and the no-new-wind
scenario. Overall, increases in wind power generation costs (capital and operation and
maintenance expenses) would be partially offset by lower capital, O&M, and fuel costs
for other electricity sources. The total capital costs for wind under this scenario would be
$236 billion NPV, and O&M cost would be $51 billion NPV. These cost estimates do
not consider the total capital required for potential investments in manufacturing
capacity, expanded employment training, or other needs, and do not represent the indirect
costs to the economy. According to the scenario, in 2030, 20 percent market penetration
by wind would provide well over 140,000 direct manufacturing, construction, and
operations jobs, as indicated by DOE’s Job and Economic Development (JEDI) model
(Goldberg et al., 2004; Wiley, 2007; DOE, 2008). This projection would include more
than 20,000 jobs in manufacturing, almost 50,000 jobs in construction, and more than
75,000 jobs in operations (DOE, 2008).
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TABLE 7-2 Net Present Value Direct Electricity Sector Costs for 20 Percent Wind Scenario
and No-New-Wind Scenario
NPV Direct Costs for No
New Wind After 2006
NPV Direct Costs for 20
Scenario
Percent Wind Scenario
(billion US$2006)
(billion US$2006)
Wind Technology O&M Costs $51 $3
Wind Technology Capital Costs $236 $0
Transmission Costs $23 $2
Fuel Costs $813 $968
Conventional Generation O&M $464 $488
Conventional Generation Capital Costs $822 $905
Total $2,409 $2,366
NOTE: NPV, net present value; O&M, operation and maintenance.
SOURCE: DOE (2008).
Integration of Wind Power into the Electricity System
Under this high-market-penetration scenario, integrating 20 percent wind power
into the electricity system would require investment in the electricity grid and other parts
of the electricity system. Transmission could be the biggest obstacle to seeing levels of
wind power rise to 20 percent. Studies of wind integration at the utility and state level
show that incorporating significant amounts of wind power into the electricity grid, while
feasible, would require improvements in the transmission grid, wind forecasting, and
other modifications to the electricity system, which would impose additional costs
(Zavadil et al., 2004; GE Energy, 2005; DeMeo et al., 2005; UWIG, 2006; Parson, 2006).
The 20 percent wind integration study included a conceptual framework of the regional
transmission system upgrades needed to move electricity from high- resource to high-
demand areas (Figure 7-2). The study estimated the cost of expanded transmission at $23
billion, though it recognized the barriers to installing new transmission in general. This
estimate is lower than other estimates. Separately, American Electric Power (AEP)
developed a conceptual interstate transmission plan for integrating over 300 GW from
wind power and for reducing existing transmission bottlenecks. AEP estimates such a
system would include 19,000 miles of new high- voltage (765 kV) transmission lines and
require investments on the order of $60 billion (AEP, 2007). The more recent Joint
Coordinated System Plan (JCSP), discussed below in this section, estimated that
integrating 20 percent wind into most of the eastern U.S. electricity system would require
15,000 miles of new extra high-voltage lines at a cost of $80 billion (JCSP 2009).
Though these studies have differing assumptions resulting in varying estimates, they all
indicate the magnitude of investment in transmission required to integrate large amounts
of wind power into the electric grid.
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Environmental and Energy Impacts
The 20 percent wind power scenario would cause significant land use and
atmospheric emissions impacts. The estimated land area needed to realize this scenario
would be 50,000 km2, which includes the land used directly for the turbines and other
land requirements. Only about 2 to 5 percent of the land use would be for the turbines
themselves, with the rest of the area between turbines that could be available for
agricultural or other uses.
Figure 7-3 shows reductions of CO2 emissions with 20 percent wind compared to
the reference case. Atmospheric emissions of carbon dioxide (CO2) and other pollutants
would be significantly reduced. The scenario estimates that wind power would replace
coal- and gas-fired electricity generation and reduce CO2 emissions to 800 million tons
per year in 2030. Also shown in Figure 7-3 is the trajectory required to reduce electricity
sector CO2 emissions by 80 percent, which is the overall target for reductions of
greenhouse gas (GHG) emissions necessary to maintain CO2 at or below 450 parts per
million. Increasing wind power generation would also result in reductions of other
atmospheric pollutants associated with fossil fuel electricity generation, though there
would be emissions from natural-gas-fired power plants needed for back-up generation.
However, the impact on NOx and SO2 emissions is less than what would be expected
from assuming that electricity generation from fossil fuels is replaced with a non-carbon-
emitting technology such as wind power. Because emissions of NOx and SO2 are subject
to caps on emissions, reductions of emissions from wind-generated electricity might be
reallocated to other plants. Other toxins emitted from coal and natural gas electricity
generation are not capped and would be reduced in replacing fossil fuel electricity
generation with wind power.
The impact on the energy mix would be largest for natural gas, with the 20
percent wind scenario displacing about 50 percent of electric utility natural gas
consumption compared to 18 percent of coal consumption in 2030 (DOE, 2008). The 20
percent wind scenario would also greatly reduce the need for imported liquefied natural
gas. However, maintaining electricity system reliability would require additional
capacity from natural gas combustion turbines that could respond to wind fluctuations in
some combination with the transmission upgrades.
Joint Coordinated System Plan
Following the national 20 percent wind study, a multi-stakeholder group within
the Eastern Interconnection prepared a report looking at wind integration issues from a
regional perspective. As with the 20 percent wind study, it included multiple
stakeholders in a collaborative that held numerous public workshop meetings. The Joint
Coordinated System Plan (JCSP, 2009) looked at two scenarios, one a reference case
with 5 percent market penetration by wind and the second with 20 percent wind. For the
5 percent wind scenario, the study estimated a need for 10,000 miles of new extra high-
voltage (EHV) transmission lines at an estimated cost of $50 billion. For the 20 percent
wind scenario, the projected transmission requirement was 15,000 miles of new EHV
lines at an estimated cost of $80 billion. In both cases, the additional transmission
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allowed renewable and base-load steam energy from the Midwest to be transmitted to a
wider area. The study assumed that increased wind generation would primarily offset
base-load steam production, while requiring more production from fast-response, gas-
fired combustion turbines. The JCSP study did not envision electricity storage as having
a role in integrating this level of wind power. That report is intended to be part of an
ongoing set of studies that examine the reliability and economic impacts of alternative
combinations of supply- and demand-side resource technologies, densities and locations,
and transmission infrastructure options. The group also plans to conduct sensitivity
analyses to determine the implications of varying assumptions such as fuel and
technology costs, load projections, plant retirements, and carbon regulation options and
costs (JCSP, 2009).
Summary of High Wind Power Penetration Scenarios
It is clear that the high wind penetration scenarios outlined above represent a
departure from present conditions. For manufacturers to make the investments needed to
develop such capacities and supply chains, substantial capital and a stable policy
environment would be required. These scenarios also would require significant land area
for the spacing needed between wind turbines, though the actual area occupied by the
turbines is a small portion of the land. Realizing the scenarios would entail substantial
economic activity, including the addition of thousands of new manufacturing and
construction jobs in the wind industry, and would provide significant carbon reductions.
DOE’s 20 percent wind study estimated a reduced demand for natural gas for electricity
generation, though 20 percent wind would increase the need for the use of high-cost
combustion-turbine natural gas capacity. The 20 percent wind scenarios of both the DOE
and the JCSP demonstrate the need for substantial increases in transmission capacity.
There are sufficient resources, technologies, and generally positive economics to increase
wind power’s contribution to the electricity sector. What these 20 percent wind
penetration scenarios emphasize are the scale of the challenges and the benefits for the
future.
High Solar Electricity Penetration Scenarios
A variety of scenarios discuss increased market penetration by solar photovoltaics
(PV) and concentrating solar power (CSP). Examples range from the comparatively
modest DOE Solar America Initiative (SAI; DOE, 2007b) to the more optimistic U.S.
Photovoltaics Industry Roadmap (PV Roadmap; SEIA, 2001, 2004) and the Solar Grand
Plan (Zweibel et al., 2008). Another study examined a scenario for reaching 10 percent
electricity generation from solar by 2025 (Pernick and Wilder, 2008). These scenarios
consider issues similar to those addressed in the 20 percent wind power scenarios, such as
the potential impacts of renewables’ high market penetration on manufacturing,
implementation, economics, and the environment. Further, solar electricity can provide
insights into attributes of distributed energy sources. Because of the higher costs
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associated with solar energy, all scenarios consider the significant cost reductions that
would have to occur to make solar electricity competitive with other electricity sources.
Distributed Solar Power⎯SAI and PV Roadmap Scenarios
The SAI and the PV Roadmap scenarios assume that 100-200 GWp (Wp indicates
peak power) of solar PV would be introduced by 2030 and that a majority of the newly
installed generation would be distributed in residential, commercial, and industrial
applications.1 Tables 7-3 and 7-4 provide the assumptions used in these scenarios. As
shown in Table 7-3, the SAI considered two scenarios: a low-penetration scenario
assuming that a total of 5 GWp of PV would be installed by 2015 and 70 GW by 2030,
and a high-penetration scenario assuming that a total of 10 GWp of PV would be installed
by 2015 and 100 GWp by 2030. In the PV Roadmap scenario, installed capacity would
reach 200 GWp by 2030, and 670 GWp by 2050. In order for solar PV to be competitive
with other electricity sources, both scenarios assumed that the installed system cost of PV
would decrease significantly. For example, in both SAI scenarios, costs would decrease
from the 2005 value of $8/Wp to $3.3/Wp in 2015 and $2.5/Wp in 2030 (Grover, 2007).
The PV Roadmap assumed costs would decrease to $3/Wp in 2020 and $1.9/Wp in 2050
(SEIA, 2004). Table 7-3 compares the estimated PV electricity generation for these
scenarios and total U.S. electricity generation under the Energy Information Agency’s
reference case AEO2008 (EIA, 2008b). Assuming a capacity factor of 19 percent, the
SAI scenarios would represent between 2 and 3 percent of the total 2030 electricity
generation in the AEO2008 case. The electricity generation under the PV Roadmap
scenario would represent almost 8 percent of the estimate from AEO2008.
Providing solar PV as distributed electricity generation, as opposed to wholesale
generation to the grid, has several advantages. Reducing the need to integrate this portion
of PV-generated electricity into the transmission grid would reduce the costs of
developing and maintaining transmission facilities. And localized use of electricity would
eliminate the losses that occur during transmission. Distributed PV is also easier to site
and eliminates land-use impacts. Because available solar energy tends to peak in the
afternoon, solar PV delivers electricity directly to residences and businesses close to the
time of peak electricity demand. A 19 percent capacity factor has been estimated for a
4.6 MW PV array operated by Tucson Electric Power that was sited to maximize sun
exposure (Curtright and Apt, 2008). However, a goal of 19 percent capacity would be
high for residential, commercial, and industrial applications where installation of solar
panels would have to use existing rooflines and orientations.
1
The SAI scenarios assume that all PV installations are distributed electricity sources, and the PV
Roadmap assumes that 1/6 of installed capacity is grid (wholesale) generation.
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TABLE 7-3 Electricity Capacity and Generation Under SAI and PV Roadmap Scenarios and
Total U.S. Electricity Generation Estimated Under AEO2008 Out to 2030
U.S. Electricity
Generation from PV Percent of
Cumulative PV
AEO2008 Total Generation
PV Capacity Generation
(TWh/yr) from AEO2008
(GW) (TWh/yr)
Scenario
2015 SAI Low 5 8.3 4485 0.2
2015 SAI High 10 16.6 4485 0.4
2015 PV Roadmap 9.6 15 4485 n/a
2030 SAI Low 70 116.5 5235 2.2
2030 SAI High 100 166.4 5235 3.2
2030 PV Roadmap 200 410 5235 7.8
2050 PV Roadmap 670 1400 n/a n/a
NOTE: AEO2008, Annual Energy Outlook 2008 (EIA, 2008b); n/a, not applicable; PV, photovoltaics;
SAI, Solar America Initiative.
SOURCE: Data from Grover (2007) and SEIA (2004).
TABLE 7-4 Annual Installations, System Costs, and Performance for Solar
America Initiative High-Penetration and Photovoltaics Roadmap Scenarios
2015 2030 2050
Annual Installed Capacity
SAI High (GW) 2.74 10.4 n/a
PV Roadmap (GW) 2.3 19 31
System Costs
SAI High ($/W) 3.3 2.5 n/a
PV Roadmap ($/W) 3.68 2.33 1.93
NOTE: n/a, not applicable; PV, photovoltaics; SAI, Solar America Initiative.
SOURCE: Data from Grover (2007) and SEIA (2004).
Both the SAI scenarios and the PV Roadmap require substantial increases in
manufacturing capacities. As shown in Table 7-4, annual U.S. installations of PV over
the 2005-2030 time period would grow at a 20 percent rate to 2.7 GWp in 2015 and 10
GWp in 2030 under the SAI high scenario. Annual U.S. installations of PV over the
2005-2030 time period for the PV Roadmap would grow at a 22 percent rate to 19 GWp
in 2030. Both cases would result in large increases in manufacturing capabilities.
Bradford (2008) estimated that 2007 global PV production was 3.7 GW and grew at an
annual average rate of more 45 percent from 2001 to 2007. But global demand also
continues to be strong. For example, Bradford (2008) projected that demand for PV in
Europe would increase to 4.5 GWp by 2010.
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These scenarios pose significant materials, employment, and capital needs. The
primary concern regarding PV materials would be the availability of sufficient
polysilicon supplies to produce crystalline silicon PV cells. Global polysilicon supplies
were tight in 2007, but there is evidence that supply conditions should improve in 2008
and later (Prometheus Institute, 2007). Though using thin film technologies would
require fewer materials, some shortages might occur; for example, technologies using
copper indium gallium selenide (CIGS) could be limited by the amount of naturally
occurring indium. The SAI scenarios in 2030 would produce about 120,000 jobs in the
manufacturing and installation of PV systems and require $26 billion for manufacturing
and installation costs (Grover, 2007). The PV Roadmap in its scenario estimated that its
scenario would produce 260,000 jobs for the manufacturing and installation of PV
systems in 2030 and 350,000 jobs in 2050.
Environmental impacts under the SAI scenarios include reductions in atmospheric
emissions of CO2 and other pollutants, as well as potential waste-generation impacts
associated with PV manufacturing. SAI estimated reductions in CO2 and other
atmospheric emissions, assuming that PV generation of electricity would replace fossil
fuel generation on a one-to-one basis, and that 75 percent of the fuel displaced would be
natural gas and 25 percent would be coal (Grover, 2007). Using this assumption, the SAI
low scenario would reduce annual CO2 emissions by almost 70 million tons in 2030,
while its high scenario would reduce annual CO2 emissions by almost 100 million tons in
2030. These reductions would be about 2 to 3 percent of estimated annual CO2 emissions
for the electricity sector under AEO2008 (EIA, 2008b). As with wind power, the impact
on NOx and SO2 emissions would be less than might be expected from replacing fossil
fuels with solar PV for the generation of electricity, because of cap and trade policies.
Solar electricity scenarios such as the SAI or Roadmap scenarios might not have any
impact at all. Emissions of both NOx and SO2 are subject to caps on emissions and thus
credit for reductions of emissions from solar electricity generation might be reallocated to
existing fossil fuel plants. Other air toxics emitted from coal and natural gas electricity
generation are not capped, however, and would be reduced by replacing fossil fuel
electricity generation with solar PV. As noted in Chapter 5, other impacts related to solar
PV not incorporated in this scenario include the waste generation associated with its
production and the energy payback time, or the number of years before the PV system
becomes a net energy producer.
Grid Solar⎯CSP and Grand Plan Scenarios
Expanding CSP in California
Expanding the market for concentrating solar power (CSP) represents an approach
to providing solar electricity to the electricity grid. Stoddard et al. (2006) described
scenarios for increased cumulative market penetration of CSP at two different levels,
2,100 MW or 4,000 MW, by the year 2020, and the associated economic, energy, and
environmental impacts of CSP in California. The report concluded that the size of the
resource in California would offer even greater potential. Plants between 100 and 200
MW in size with parabolic trough technology and 6 hours of storage were assumed. It
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was estimated that with the solar resource in California, each 1,000 MW of CSP would
produce 3,600 GWh/yr. The report concluded that the levelized costs of energy from the
CSP plants would make them competitive with natural gas combustion turbines by 2015.
The 4,000 MW scenario estimated reductions in CO2 by 7.6 million tons per year,
compared with natural gas combined cycle plant, and provision of 3,000 permanent jobs
associated with the operation of the plants.
The Solar Grand Plan
The Solar Grand Plan scenario proposed meeting approximately 70 percent of
electricity demand by 2050 through the development of large-scale solar PV farms and
CSP plants (Zweibel et al., 2008). The plan also envisioned an extensive direct current
(DC) transmission system and compressed air storage facilities distributed throughout the
country to enable solar electricity to provide base-load capabilities nationally. It assumed
that system costs for thin film cadmium telluride would fall to $1.20/Wp and that
efficiencies would increase to 14 percent. Almost 3,000 GWp of capacity would be built,
covering 30,000 square miles in the southwestern United States. This scenario assumed
that only 10 percent of the generation would come from distributed PV installations.
Another 560 GW of capacity would use CSP technologies, which would require 16,000
square miles of land area, also in the southwestern United States. Electricity would be
delivered nationally over 100,000 to 500,000 miles of high-voltage DC transmission lines
and partially stored in compressed-air storage facilities to provide power for turbines to
generate year-around power. The scenario called for 400 storage facilities with a total
capacity of more than 500 billion cubic feet (for information on feasibility, see Chapter
3). It was estimated that a cumulative $420 billion subsidy from the federal government
would be required for the overhaul of the energy infrastructure. Under the plan’s
scenario, it was projected that U.S. carbon dioxide emissions would be reduced by 3.6
billions tons per year in 2050, meaning that CO2 emissions in 2050 would be 62 percent
lower than CO2 emissions in 2005.
The Solar Grand Plan would require large cost reductions, efficiency
improvements, and the development of massive storage and transmission infrastructure.
The land requirements alone, more than 42,000 square miles, are enormous. One limiting
factor would be whether sufficient tellurium exists for manufacturing solar cells at the
scale necessary. Approximately 30,000 square miles of CdTe cell area would be used to
reach this level of electricity generation, and a typical cell width of 2 × 10-6 meters would
require slightly less than the total resource base shown in Figure 6-2 and more than the
resource base estimated by the U.S. Geological Survey (USGS, 2007). The USGS
resource base is estimated from the only economical source of tellurium, which is a
byproduct of producing copper, lead, and bismuth. Estimates from both the USGS and
Feltrin and Freundlich (2008) have indicated that such a scenario would require most if
not all of the world’s tellurium production.
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impacts of GHG reduction policies (EIA, 2003). This module solves for the energy-
economy equilibrium by iteratively interrelating the energy supply, demand, and
conversion modules of NEMS. Thus, NEMS is sensitive to energy prices, energy
consumption, and allowance revenues, and solves for the effects of policy such as that
legislated in the CSA on macroeconomic and industry-level variables.
Energy Market and Electricity Mix
As expected, the projected greenhouse gas emissions in scenarios with emissions
regulations are significantly lower than those in the reference case. The EIA’s core CSA
scenario described above would result in an 85 to 90 percent reduction of CO2-equivalent
emissions by 2030, and its high-cost case in a 50 to 60 percent reduction during the same
timeframe. The majority of the emissions reduction would come from the electric power
sector, a projection that is relevant to this panel’s work. These reductions would be
achieved by deployment of new nuclear, renewable, and fossil with CCS facilities. Major
determinants of the energy and economic impact of the CSA bill include the potential for
and the timing of the development and commercial marketing of low-emissions
electricity generation technologies. Another determinant is the degree to which
companies might be able to purchase emission reduction credits overseas, a topic that is
not discussed further here.
Figure 7-7 shows the impact of EIA’s core and high-cost CSA scenarios on the
overall electricity mix. With the regulation of greenhouse gas emissions in place, coal
consumption, especially for electricity generation, would be significantly reduced by
2030. Many coal power plants without CCS would be forced to retire early, because
retrofitting with CCS technology is generally impracticable, and so is not simulated in the
model. The energy-generation mix for the EIA’s core CSA scenario would be composed
of coal with CCS, nuclear, and renewable technologies, primarily wind and biomass.
One important characteristic of the core case is the strong growth in nuclear power. If
these low-emission technologies face trouble in deployment, as in the high-cost case,
there would be a shift to electricity generation from natural gas to offset the reduction in
coal generation.
The EIA estimated that renewable electricity generation would be significantly
higher under the provisions of the CSA, with the vast majority of the increase from wind
generation, followed by generation from biomass (EIA, 2008a). How each renewable
energy resource would contribute to the total supply of electricity generated in the three
scenarios (AEO2008, core, and high cost) is shown in Table 7-8. The increase in total
renewable generation is especially strong in the high-cost case. Table 7-9 shows the
projected average annual growth rates of each renewable resource from 2005 to 2030.
With GHG emissions-regulating legislation in place, the NEMS model shows a sharp
increase in the growth rate of biomass, solar, and wind generation, especially for the
high-cost case, Wind generation would increase significantly, averaging annual growth
at 16 percent in the high-cost case, and would grow to constitute 14 percent of the U.S.
electricity mix by 2030. Despite this projected rapid growth, NEMS does not indicate a
20 percent contribution by wind energy to the U.S. electricity mix, as is projected in the
20 percent wind scenario discussed above in this chapter. Interestingly, despite the rapid
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growth rate for solar electricity in all cases, averaging 19 percent annually, solar would
still contribute less than 1 percent of total U.S. electricity generation. These values are
much smaller than the 10 percent solar generation described in the DOE study discussed
above (DOE, 2008). Finally, the EIA estimates significant growth in the use of biomass
for electricity generation: by 2030 biomass it would be used to generate 4 to 5 percent of
the U.S. electricity supply.
TABLE 7-8 Percent of Total U.S. Electricity Generated from Renewable Sources as Projected in
Energy Information Administration Analysis of Three Scenarios
2020 2030
Reference Core High-Cost Reference Core High-Cost
Case Case Case Case Case Case
Hydropower 6.87 7.18 7.37 6.23 6.63 7.13
Geothermal 0.55 0.98 1.21 0.65 1.14 1.45
Municipal Waste 0.44 0.56 0.65 0.44 0.54 0.89
Biomass 1.79 5.54 5.30 1.72 3.74 4.58
Solar 0.059 0.06 0.061 0.066 0.068 0.095
Wind 2.33 5.76 6.73 2.57 5.63 13.94
Total Renewable 12.0 20.1 21.3 11.6 17.8 28.1
Total Non-Hydro
5.13 12.92 13.93 5.37 11.17 20.97
Renewable
SOURCE: Data from EIA (2008a).
TABLE 7-9 Average Annual Growth Rate (Percent) from 2005-2030 for Each Source of Renewable
Electricity Generation
Municipal
Hydropower Geothermal Waste Biomass Solar Wind
Reference Case 0.49 3.05 1.88 9.45 18.51 8.78
Core Case 0.57 5.38 2.93 18.02 18.51 12.03
High-Cost Case 0.71 6.34 5.08 21.94 19.4 15.85
SOURCE: Data from EIA (2008a).
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Summary of Macroeconomic Impacts and Model Uncertainties
EIA’s estimates of the macroeconomic impacts of the CSA include an increase in
energy prices for consumers, especially in the cost of electricity, with increases of 11 to
64 percent, mainly as a result of high GHG allowance prices. Also projected by EIA is a
reduction of total electricity consumption (5 to 11 percent). The large increases in energy
costs would reduce economic output, lessen purchasing power, and lower aggregate
demand for goods and services. In the core CSA case, the gross domestic product would
fall by approximately 0.2 percent and would fall by approximately 0.8 percent in the
high-cost case.
Many major uncertainties are associated with the EIA projections. It is difficult to
foresee how existing technologies might evolve or what new technologies might emerge
as market conditions change, particularly when those changes are e fairly dramatic. To
meet greenhouse gas emission reduction targets, future electricity providers will have to
rely on technologies that today play a relatively small role or have not been built in the
United States in some time. The actual cost of implementing legislation such as the CSA
would depend on unknowns such as future reductions in the cost of renewable
technologies, the potential for successful commercialization of CCS, and future costs for
nuclear power, all of which cannot be predicted by the model.
FINDINGS
Shown in bold below are the most critical elements of the panel’s findings, based
on its examination of previously produced scenarios, regarding the future expansion of
renewable electricity and factors affecting renewables expansion and integration into the
U.S. electricity supply system.
Scale of Deployment
An understanding of the scale of deployment necessary for renewable
resources to make a material contribution to U.S. electricity generation is critical to
assessing the potential for renewable electricity generation. Large increases over
current levels of manufacturing, employment, investment, and installation will be
required for non-hydropower renewable resources to move from single-digit- to
double-digit-percentage contributions to U.S. electricity generation.
The scenarios described in this chapter indicate some of the characteristics and
impacts associated with accelerating the integration of more renewable generation in the
U.S. electricity market. Wind power, an intermittent source of electricity, would be the
largest contributor in the near term. DOE (2008) shows that 20 percent of U.S. electricity
generation could be obtained from wind and integrated into the nation’s electricity
system. Follow-up studies such as JCSP (2009) assess the impacts of 20 percent wind at
a regional level. Solar PV and CSP could also contribute to attaining additional
renewable electricity generation by 2035. Solar electricity is the only renewable resource
that has a sufficiently large resource base to supply a majority of the electricity demands
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of the United States. Today’s prices prevent solar electricity from being a widespread,
economic option at this time. However, the ability of solar PV to produce electricity at
the point of consumption means that it competes with the higher retail price of electricity
as opposed to the wholesale price of electricity. Solar CSP can provide utility-scale solar
power at lower costs than solar PV, though it is limited to favored sites in the U.S.
Southwest that have normally abundant direct solar radiation. Additional contributions
could come from biopower and hydrothermal resources, which can provide base-load
power. Thus, if renewables were to contribute an additional 20 percent or more of all
U.S. electricity generation by 2035, the largest portion of new renewable electricity
generation would come from wind power, but other renewables would also contribute to
making this goal a reasonable possibility.
The numbers from the 20 percent wind penetration study (DOE, 2008)
demonstrate the challenges and opportunities. To reach the 20 percent target would
require installing 100,000 wind turbines; incurring $100 billion dollars’ worth of
additional capital investments and transmission upgrades; and requiring 140,000 jobs be
filled. Achieving this goal could reduce CO2 emissions by 800 million metric tons. The
high solar market penetration scenarios also present challenges associated with scaling up
this resource. The 10 percent solar study (Pernick and Wilder, 2008) would require that
annual installation of PV increase to almost 50 GW in 2025 and installation of CSP to
almost 7 GW, with prices for installed PV declining to $1.48-$1.82/W and prices for
installed CSP declining to $0.88/W in the same timeframe. The cost estimates for
reaching the 10 percent solar goal are $26 billion to $33 billion per year, with a total cost
of $450 billion to $560 billion.
In the panel’s opinion, increasing manufacturing and installation capacity,
employment, and financing to levels required to meet the goals for greatly increased
solar or wind penetration goals is doable. However, to do so would require
aggressive growth rates, a large increase in manufacturing and installation capacity,
and a large infusion of capital. The magnitude of the challenges is clear from the
scale of such efforts.
Integration of Renewable Electricity
The cost of new transmission and upgrades to the distribution system will be
important factors when integrating increasing amounts of renewable electricity. The
nation’s electricity grid needs major improvements regardless of whether renewable
electricity generation is increased. Such improvements would increase the reliability of
the electricity transmission system and would reduce the losses incurred with all
electricity sources. However, because a substantial fraction of new renewable electricity
generation capacity would come from intermittent and/or distant sources, increases in
transmission capacity and other grid improvements are critical for significant penetration
of renewable electricity sources. According to the Department of Energy’s study
postulating 20 percent wind penetration, transmission could be the greatest obstacle to
reaching the 20 percent wind generation level. Transmission improvements can bring
new resources into the electricity system, provide geographical diversity in the
generation base, and allow improved access to regional wholesale electricity
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markets. These benefits can also generally contribute positively to the reliability,
stability, and security of the grid. Improvements in the system’s distribution of
electricity are needed to maximize the benefits of two-way electricity flow and to
implement time-of-day pricing. Such improvements would more efficiently
integrate distributed renewable electricity sources, such as solar photovoltaics sited
at residential and commercial units. A significant increase in renewable sources of
power in the electricity system would also require fast-responding backup
generation and/or storage capacity, such as that provided by natural gas
combustion turbines, hydropower, or storage technologies. Higher levels of
penetration of intermittent renewables (above about 20 percent) would require batteries,
compressed air energy storage, or other methods of storing energy such as conversion of
excess generated electricity to chemical fuels. Improved meteorological forecasting could
also facilitate increased integration of solar and wind power. Hence, though
improvements in the grid and related technologies are necessary and valuable for other
objectives, significant integration of renewable electricity will not occur without
increases in transmission capacity as well as other grid management improvements.
Time Frames for Renewable Technologies
For the time period from the present to 2020, there are no current
technological constraints for wind, solar photovoltaics and concentrating solar
power, conventional geothermal, and biomass technologies to accelerate
deployment. The primary current barriers are the cost-competitiveness of the
existing technologies relative to most other sources of electricity (with no costs
assigned to carbon emissions or other currently unpriced externalities), the lack of
sufficient transmission capacity to move electricity generated from renewable
resources to distant demand centers, and the lack of sustained policies. Expanded
research and development is needed to realize continued improvements and further cost
reductions for these technologies. Along with favorable policies, such improvements can
greatly enhance renewable electricity’s competitiveness and its level of deployment.
Action now will set the stage for greater, more cost-effective, penetration of renewable
electricity in later time periods. It is reasonable to envision that, collectively, non-
hydropower renewable electricity could begin to provide a material contribution
(i.e., reaching a level of 10 percent level or more with trends toward continued
growth) to the nation’s electricity generation in the period up to 2020 with such
accelerated deployment. Combined with hydropower, total renewable electricity could
approach a contribution of 20 percent of U.S. electricity by the year 2020.
In the period from 2020 to 2035, it is reasonable to envision that continued
and even further accelerated deployment could potentially result in non-
hydroelectric renewables providing, collectively, 20 percent or more of domestic
electricity generation by 2035. In the third time frame, beyond 2035, continued
development of renewable electricity technologies could potentially provide lower
costs and result in further increases in the percentage of renewable electricity
generated from renewable resources. However, achieving a predominant (i.e., >50
percent) level of renewable electricity penetration will require new scientific
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advances (e.g., in solar photovoltaics, other renewable electricity technologies, and
storage technologies) and dramatic changes in how we generate, transmit, and use
electricity. Scientific advances are anticipated to improve the cost, scalability, and
performance of all renewable energy generation technologies. Moreover, some
combination of intelligent, two-way electric grids; scalable and cost-effective methods
for large-scale and distributed storage (either direct electricity energy storage or
generation of chemical fuels); widespread implementation of rapidly dispatchable fossil-
based electricity technologies; and greatly improved technologies for cost-effective long-
distance electricity transmission will be required. Significant, sustained, and greatly
expanded R&D focused on these technologies are also necessary if this vision is to be
realized by 2035 and beyond.
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Appendixes
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