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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 at a moderate pace, with the growth rate and technology learning following a conventional S curve. But if policy makers 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.
The 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; instead, they 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
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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 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 Solar America Initiative (DOE, 2007b), the U.S. Photovoltaic 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 or 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.
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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.
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.
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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 AEO 2007 and AEO 2008 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
FIGURE 7.1 Annual and cumulative generation needed to achieve 20 percent wind generation of electricity by 2030.
Source: Lawrence Berkeley National Laboratory; presented in Wiser, 2008.
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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 more than 16 GW, compared to a global wind turbine manufacturing output of about 15 GW in 2007 (DOE, 2007a). As discussed in Chapter 1 of the present report, an additional 5 GW of capacity was added in the United States in 2007 and more than 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 (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- to 6-MW turbines, there could be a total of almost 100,000 wind turbines installed (Wiley, 2007; DOE, 2008). The average number of turbines
TABLE 7.1 Raw Materials Requirements for 20 Percent Wind Scenario (thousands of tons per year)
Year
Concrete
Steel
Aluminum
Copper
Glass-Reinforced Plastic
Carbon Fiber 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.
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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 20 Percent Wind Scenario (billion U.S. 2006$)
NPV Direct Costs for No-New-Wind-After-2006 Scenario (billion U.S. 2006$)
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.
installed would have to increase from its present level of 2,000 per year to 7,000 per year by 2017 (DOE, 2008).
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 $43 billion (U.S. 2006$) 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 [O&M] 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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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; Parsons, 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,
FIGURE 7.2 Map indicating potential new transmission corridors for integrating 300 GW of wind power.
Source: DOE, 2008.
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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 more than 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.
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 2–5 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 carbon dioxide (CO2) emissions with 20 percent wind compared to the reference case. Atmospheric emissions of 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 backup 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
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FIGURE 7.3 Reductions in CO2 emissions resulting from 20 percent wind scenario compared to the no-new-wind reference case. Also shown is the trajectory for reducing CO2 emissions by 80 percent.
Source: DOE, 2008.
be reallocated to other plants. Other air toxics 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.
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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 allowed renewable and baseload steam energy from the Midwest to be transmitted to a wider area. The study assumed that increased wind generation would primarily offset baseload 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-
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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 Solar America Initiative (SAI; DOE, 2007b) to the more optimistic U.S. Photovoltaic 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 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 electric-
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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technologies, such as nuclear, fossil fuel with carbon capture and storage (CCS), and renewables, would be developed and deployed in the timeframe for emissions reduction set by the CSA without facing any major problems. The EIA’s high-cost scenario used the basic assumptions of the core case, except that it applied a 50 percent higher cost of nuclear, fossil fuel with CCS, and biomass-generating technologies to reflect a more pessimistic perspective regarding the costs of these technologies and the feasibility of introducing them rapidly on a large scale.
The EIA used the National Energy Modeling System (NEMS) for its analysis of the CSA (EIA, 2003). NEMS calculated changes in energy-related CO2 emissions for the various cases by adjusting the cost of fossil fuels and the GHG allowance prices variables that affect energy demand, the energy mix, and energy-related CO2 emissions. The NEMS Macroeconomic Activity Module is used for analyzing the macroeconomic impacts of GHG reduction policies. This module solves for the energy–economy equilibrium by iteratively interrelating the energy supply, demand, and conversion modules of NEMS (EIA, 2003). Thus, NEMS is sensitive to energy prices, energy consumption, and allowance revenues, and it 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 85–90 percent reduction of CO2-equivalent emissions by 2030, and its high-cost case in a 50–60 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 fuel 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
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FIGURE 7.7 Mix of electricity generation from EIA core and high-cost analysis of CSA bill compared to electricity mix in 2006 and to the AEO 2008 reference.
Source: EIA, 2008b.
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 (AEO 2008, 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
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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 Case
Core Case
High-Cost Case
Reference Case
Core Case
High-Cost 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-hydropower renewable
5.13
12.92
13.93
5.37
11.17
20.97
Source: Data from EIA, 2008a.
TABLE 7.9 Average Annual Growth Rate (Percent) from 2005 to 2030 for Each Source of Renewable Electricity Generation
Hydropower
Geothermal
Municipal 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.
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 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
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growth in the use of biomass for electricity generation: by 2030 biomass it would be used to generate 4–5 percent of the U.S. electricity supply.
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 11–64 percent, mainly as a result of high GHG allowance prices. Also projected by EIA is a reduction of total electricity consumption (5–11 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 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
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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 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 abundant direct solar radiation. Additional contributions could come from biopower and conventional geothermal resources, which can provide baseload 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 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 $26–33 billion per year, with a total cost of $450–560 billion.
In the panel’s opinion, increasing manufacturing and installation capacity, employment, and financing to levels required to meet the goals for greatly
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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 z 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 renewable resources into the electricity system, provide geographical diversity in the generation base, and allow improved access to regional wholesale electricity 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.
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Timeframes 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 timeframe, 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 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,
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sustained, and greatly expanded R&D focused on these technologies is also necessary if this vision is to be realized by 2035 and beyond.
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