This chapter provides very brief descriptions of the energy resource technologies as they were considered by the National Renewable Energy Laboratory/Colorado School of Mines (NREL/CSM) team. Included as well are the committee’s findings and recommendations related to the NREL/CSM team’s analysis. A more in-depth discussion of these resources and the technologies, with national data and appropriate citations, is found in Appendix D.
The first of the two solar power technologies considered in this section, solar photovoltaic (PV) technologies, use solid-state semiconductor materials to convert sunlight to direct current (dc) electricity, enabling broad geographic applicability. Flat-plate PV includes mono- and polycrystalline silicon (Si) and thin-film technologies. PV offers a high degree of modularity and flexibility, allowing use in rooftop and ground-mounted arrays and central-station plants. PV systems may be deployed rapidly, with larger plants built and brought online in phases. Operation and maintenance requirements and costs are modest. Fixed-tilt arrays are the most common systems in use today. A second type, those with tracking systems that track the Sun, generate more energy and, although more costly, can be economical in areas with high-quality solar resources. Flat-plate PV technologies convert direct and diffuse sunlight to dc electricity, while concentrating PV (CPV) technologies use lenses or mirrors to concentrate direct sunlight onto multi-junction semiconductor cells (containing different material layers optimized for different portions of the solar spectrum). CPV technologies offer high conversion efficiency but need direct sunlight and must include tracking systems to maintain precise solar alignment. The reduced requirements for semiconductor materials create the potential for cost reductions through manufacturing scale-up. Inverters convert the DC output of flat-plate PV and CPV systems to alternating current electricity.
One of the issues for large-scale penetration of residential and commercial PV is the intermittency of PV, even in the daylight due to cloud cover. This, and issues related to the large percentages of PV systems installed on some distribution lines in Hawaii (over 250 percent of minimum daily load), cause two-way flows for which the lines are not accustomed. As NREL noted, their analysis, focused as it was on LCOE, did not consider the difference of dispatchable versus non-dispatchable power.
Concentrating solar (thermal) power (CSP) systems use the Sun’s energy to raise the temperature of a transfer medium using mirrors that redirect and focus the solar energy onto receivers. In most CSP systems, a working fluid that is the transfer medium is heated. The working fluid is used to generate steam that drives a turbine to produce electricity. Depending on the technology and system configuration, the working fluid can be a heat-transfer fluid (HTF), such as synthetic oil or molten salt, steam, or gas.
CSP technologies include parabolic trough, central receiver (power tower), compact linear Fresnel reflector, and dish engine.
The time of day of peak insolation (i.e., incident flux of solar energy) often coincides with peak energy demand. During periods of lower solar energy flux, supplementary systems such as thermal energy storage (TES) or a fossil-fuel-fired HTF heater or steam generator can allow for continued generation of electricity. The geographic locations best-suited for CSP—those with consistently high insolation, such as in deserts—can be relatively easily acquired owing to the dearth of alternative uses. However, the need for a source of cooling water for the power block can be an issue. State and federal laws and regulations on threatened and endangered species can be a further complication to siting CSP (Black and Veatch, 2008).
NREL conducted a high-level screening analysis using the Renewable Energy Optimization (REopt) tool for PV and the System Advisory Model (SAM) for CSP. The SAM model has a CSP module, while the REopt model does not. Results from the analysis were sorted based solely on LCOE. In Chapter 0, the committee identified significant concerns regarding the use of LCOE as the primary criterion to downselect the preferred list of projects for energy development. These concerns are described in more detail below.
PV deployment on DOE-managed lands was not found to be among the lowest LCOE energy options of the 30 lowest-cost projects.1 This is not consistent with prior analyses by NREL that suggested the potential for broad PV development on DOE sites (see, for example, Elgqvist et al., 2014) and does not resonate with industry data on the costs of solar deployment. The NREL analysis did not consider the rapid reduction in the costs of PV technology, including system, installation, and balance-of-plant costs. The NREL analysis did consider nominal TES capacity when evaluating CSP potential. However, the LCOE analysis performed did not consider the value that CSP with TES could provide in terms of added generation revenue during high-demand periods, more efficient generation dispatch, and grid support. Additionally, the NREL analysis did not consider the ability to couple PV with storage and evaluate the potential benefits as described above for CSP with TES.
FINDING 3.1. The analytical results presented for solar are not a fair representation of potential resource development on DOE sites. The value of solar (both PV and CSP) is potentially underrepresented in LCOE; adding storage to PV and allowing for dispatchability could potentially improve their economics. Thus, the committee is concerned that PV or CSP projects might be rejected owing to factors not included in the REOpt analysis, such as cost of environmental remediation, transmission costs, energy storage, land constraints, etc.
RECOMMENDATION 3.1. In follow-on work, the Department of Energy should conduct an expanded analysis of photovoltaics and concentrating solar power. Such analysis should go beyond the criterion of levelized cost of electricity employed in the NREL study and include consideration of technical, economic, and market potential. Based on the findings of this initial analysis, additional sites may be evaluated utilizing the criteria in the expanded analysis.
1 Alicen Kandt, “DOE Large-Scale Power Production Study: May Meeting with NAS,” presentation to the committee, May 20, 2015.
The conversion of the wind’s kinetic energy to shaft work in the turbine and then to electricity continues to be one of the fastest-growing forms of renewable electricity generation in the world. The extent to which the wind’s kinetic energy is harnessed for electricity production depends on the conversion efficiency and wind speed. The power output of the wind turbine follows the cube of the wind speed, so that a 25 percent increase in wind speed roughly doubles the power. This sensitivity to wind speed underscores the importance of an accurate resource assessment. Similarly, the higher wind speeds are accessed by taller wind turbines.
Two important initial considerations in the development of wind generation are project scale and capital intensity. Wind project costs decline rapidly with project scale. In “good” wind regimes (International Electrotechnical Commission Class 1 or 2), projects of 100 MW and larger can typically deliver energy at costs below competing new thermal generation. Wind project operation and maintenance (O&M) requirements and costs are following the trends in other generating technologies and becoming increasingly predictable. More sensors are being used to gather statistical performance data on turbines and subcomponents, and around-the-clock remote monitoring is becoming the norm.
The NREL analysis removed from consideration a production tax credit (PTC) for wind after the authorization for such credit had expired.2 Congress later renewed the PTC in December 2015.3 The final report by Kandt et al. (2016) does include a sensitivity analysis that evaluates the LCOE, both with and without the PTC, although the central scenario does not include it.
NREL results from analysis of the 55 sites indicated the key limiting factors for wind development was the quantity of land available at the DOE site or the assumption of 100 MW maximum project size.
RECOMMENDATION 3.2. The Department of Energy (DOE) should perform a sensitivity study that illustrates the potential for wind development on DOE-managed lands addressing federal incentives such as investment tax credits, production tax credits, renewable energy credits, and so forth.
FINDING 3.2. Wind energy project economies of scale continue to decrease above 100 MW.
RECOMMENDATION 3.3. The 100 MW limit on project size should be reconsidered to more accurately assess the potential for wind development.
Geothermal energy is a renewable resource that provides energy employing various applications and resource types. Geothermal plants using deep resource temperatures between ~200°F and 700°F have been producing commercial power in the United States since the 1960s (GEA, 2012). A geothermal system requires heat, permeability, and water. Familiar instances of hot geothermal water include hot
2 Alicen Kandt, “DOE Large-Scale Power Production Study: May Meeting with NAS,” presentation to the Committee, May 20, 2015.
3 U.S. Department of Energy, undated, “Renewable Electricity Production Tax Credit,” http://energy.gov/savings/renewable-electricity-production-tax-credit-ptc, accessed November 11, 2016.
springs or geysers, but the majority of the water remains deep underground in cracks and porous rock—the geothermal reservoir. Power plants generate electricity from such reservoirs. Deep wells are drilled into underground reservoirs that provide steam to drive turbines that generate electricity.
Geothermal power plants occupy small land areas and do not require storage, transportation, or combustion of fuels. Geothermal plant development is complex, with unusual exploration and drilling and longevity risks. Also, steam production can be corrosive to certain materials, given the chemical composition beneath the Earth’s surface. This means that geothermal plants often require large sustaining capital investment to maintain production. Geothermal plants can operate nearly emissions free and provide dispatchable source power with relatively high capacity factor. They are thus able to provide baseload power unlike renewable sources such as wind and solar.4
CSM evaluated sites for geothermal energy resource development by overlaying DOE sites with a geothermal resource map, focusing on commercial hydrothermal systems. CSM found four sites to have geothermal energy resource potential. The resources available were not quantified, in contrast to the other renewable resources examined by NREL. All four of these sites were explored in a technical and market barriers analysis of potential development sites.
FINDING 3.3. CSM performed an effective analysis on the relatively limited potential for geothermal development on the DOE sites that were evaluated.
RECOMMENDATION 3.4. Given the limited number of private sector groups involved in geothermal development, any future development can occur by direct talks between these firms and the Department of Energy (DOE). Thus, DOE should discuss future development with them directly.
Coal and uranium are important contributors to the current U.S. electricity system and economy. Coal is the product of the deposit and transformation over time of organic matter under high temperatures and pressures in Earth’s crust. Uranium is a naturally occurring element in Earth’s crust, and one isotope, uranium-235, can be separated and used in power generation. Uranium is used in nuclear fission reactions that liberate energy that is thermalized in a moderator and transferred to steam in the form of heat, driving generators to produce electricity. Both resources are predominately used to generate electricity.
Both coal and uranium can be mined from underground deposits. The most efficient and productive coal operations are extremely large, on the order of 40 to 50 square miles, and are mined as surface operations with open pits. Coal resources alternatively can contribute to the development of coal-bed methane. Uranium can be mined either as a uranium ore (U3O8) and milled to produce uranium concentrate or it can be extracted as a solution underground in a process called in situ leaching.
Coal resource development is confronting a variety of challenges, both from how it is mined as well as from electricity markets using the resource. Coal resources on federal lands have become increasingly
4 Energy Information Administration, 2014, “Geothermal Resources Used to Produce Renewable Electricity in Western States,” September 8, http://www.eia.gov/todayinenergy/detail.php?id=17871.
subject to conversations about whether the resource, when used in electricity generation with the added effect of producing greenhouse gas (GHG) emissions, should continue to be mined. GHG emissions produced in the combustion of coal are leading to reductions in coal development and use. Market forces include the electric utility sector’s interest in pursuing renewable energy as well as lower natural gas prices. Additionally, various regulatory initiatives, including those regulating fine particulates, air toxics, and coal ash from existing coal-fired generation, impact the economics and interest in additional coal-fired generation.
Challenges for uranium resource development include regulations specific to this mineral, especially in relation to health and environmental protection standards. End-of-life reclamation and long-term impact, especially as it relates to water quality, are also of concern to operators. Specific rules apply to groundwater chemistry characterization and monitoring before, during, and after operations, with particular attention given to in situ leach mining.
Coal was included in the NREL/CSM analysis by way of a cursory review by CSM, but it might have been included in greater depth because it was included in the request for the study in the Omnibus Appropriations Act of 2009. The CSM analysis used regional resource maps rather than site characterizations. The main point of the analysis was to note that successful coal mining operations require a very large amount of land.
While not specifically called for in the legislation, a high-level analysis of the potential for uranium resources was conducted. CSM selection criteria for sites with geologic potential included size (acreage), proximity to uranium or thorium claim(s) or mining site(s), production status of local mining sites, and whether the primary product was uranium or thorium. No other location-specific geologic information was used. This approach appears reasonable for a high-level screen. A total of 18 sites were identified by CSM, of which 5 were selected as having the highest potential for nuclear resources. These sites, chosen by CSM using the above criteria, were the locations of historical uranium mining and/or processing and are managed by the Office of Legacy Management.
RECOMMENDATION 3.5. The Department of Energy should eliminate fossil and uranium resource sites from further consideration for development when compelling factors exist related to current and foreseeable use for environmental, legal, or other reasons.
RECOMMENDATION 3.6. The Department of Energy should consider site-specific geologic information when deciding which sites should be included in a short list for energy resource development. Such geologic expertise could be obtained from the U.S. Geological Survey, state geological surveys, and other public or private sources.
Biomass is organic matter that contains stored energy. Examples of biomass include wood, dried vegetation, crop residue, and aquatic plants. Sources can include waste material as well as material purpose-grown for fuel. Biomass can be combusted directly to fuel heat, industrial processes, or electricity generation, or it can be converted into other forms of fuel, such as gaseous or liquid biofuels. Biomass constitutes the largest share of renewable energy. Following industrial process use, the second largest use is in transportation, primarily as ethanol blended at 10 percent into most gasoline sold in the United States. Roughly one-tenth of the biomass, calculated on an energy basis, is used for retail electricity generation.
Currently on DOE properties, there are at least two sites with biomass energy development that produce heat and electricity for on-site use. The more successful of these two projects is at the Savannah River Site in South Carolina. That site replaced an existing coal-fired CHP plant with a biomass-burning CHP plant, financed through an energy savings performance contract. The plant generates 20 MW of electricity and 240,000 pounds of steam per hour.
In some site-specific cases, biomass may be a less costly fuel for electricity or heat generation than fossil fuels, especially if abundant biomass waste products are available nearby. In a presentation to the committee, the Savannah River Site representatives noted that when their biomass plant was built, it had less expensive fuel than the coal-fired boiler it was replacing.5 However, they noted that at current prices, a natural gas-fired power plant would be competitive, or possibly cheaper, to fuel than a biomass plant. Another advantage of biomass plants is their high capacity factors, estimated at 80 percent, relative to other renewable plants.
A significant problem with using biomass is the low energy density of biomass relative to fossil fuels. This low density makes transportation and storage more difficult. Resources outside a 50-mile radius may be uneconomical. This incentivizes co-location of biomass power plants near biomass sources, as is done in the pulp and paper industries. Another consideration for electricity generation from biomass is that biomass can have greater emissions of other air pollutants, such as black carbon and carbon monoxide, than fossil fuels that are replaced.
NREL used its REopt tool to model biomass systems on DOE sites for generation of electric power. Assumptions included that the biomass was to be purchased, brought on-site, and combusted to generate electricity. The electric power was to be used for export off-site to the electric grid. Two biomass projects appeared in the down-select list of 17 projects.
FINDING 3.4. Transportation costs for biomass are an important driver in determining the economics of siting a biomass plant on a DOE site.
FINDING 3.5. The existing biomass plants on DOE sites are producing both heat and power. Many active DOE sites have needs for steam generation that can be well served by CHP systems.
RECOMMENDATION 3.7. In analyzing the possibility of building a biomass plant on one of its sites, the Department of Energy should consider the relative efficiencies and economics of combined heat-and-power biomass systems relative to those of electricity-only plants.
5 James DeMass, U.S. Department of Energy, “Biomass Cogeneration Facility: Savannah River Site; Aiken, SC,” presentation to the committee, November 13, 2014.
While the term “waste-to-energy” (WTE) may apply to a number of technologies and feedstocks, in the context of the analysis of DOE-managed lands, it refers to the combustion of municipal solid waste to produce electricity. Given the amount of waste that is discarded in the United States, the basic feedstock for WTE projects is plentiful. Studies have shown life-cycle GHG benefits from using this technology rather than dumping waste into landfills. Despite its benefits, WTE has not been popular in the United States due to its combustion of trash containing possible toxic substances.
A particular concern for DOE sites is the constant need to transport waste on-site for incineration. This may not be acceptable to some sites for security reasons. The economics of WTE production depend primarily on the local “tipping” fees—that is, how much the municipality will pay the facility to take its waste. Another major driver affecting the economics of WTE is the availability of sufficient waste. Without a reliable, steady stream of waste to fuel the plant, the plant will be unable to operate at sufficiently high capacity. A reduction in output raises the cost per unit of electricity generation. WTE plants need an agreement with local municipalities or waste management companies to capture a minimum amount of waste on a regular basis.
The NREL analysis concluded that WTE was the most economic renewable option in its top 14 sites, with a LCOE ranging from $0.025 to $0.035. While NREL used estimates of capital and operating costs for each WTE technology they considered, the estimates were derived from NREL-chosen industry experts, so it is difficult to assess their robustness. Further, NREL posited that all waste generated within 25 miles of their facility would be available to fuel a WTE plant. That amount of trash was calculated as the per capita average for the state multiplied by the population within a 25-mile radius. Presumably, although not explicitly stated, the local tipping fees were also applied.
These LCOE estimates contain multiple uncertainties based on assumptions for capital and operating costs, garbage generation, garbage delivery capability, landfill fees, and tipping fees. A change in any one of these factors could alter the results significantly. Also, as noted above, the permitting of WTE plants is likely to be controversial, even on DOE land. In order to win approval for the construction of a new plant, its developers may have to incur additional costs for technology upgrades.
Landfill gas (LFG) generation starts when waste is first put in place and continues for 20 or more years after the landfill is closed. The use of LFG for power generation offers an opportunity to reduce GHG emissions from these facilities. Three principal options for utilizing LFG energy include (1) electricity generation, (2) direct heating and use by an industry, and (3) transportation of treated LFG through a pipeline. The most common means of LFG utilization is conversion to electricity generation through internal combustion engines, turbines, microturbines, and fuel cells.
LFG gas is typically unsuitable as a combustion fuel unless treated to remove moisture, gas impurities, and particulates from the landfill stream. Characterization of LFG candidate facilities is necessary to identify a consistent gas quality and quantity over the energy production time period. A particular concern for DOE sites is the additional cost to transport the LFG from the landfill source to a nearby DOE facility for power production and various right-of-way issues.
The NREL analysis focused on the most common means of LFG power generation, use of an internal combustion engine to generate electricity. Potential DOE sites were screened by proximity to a landfill resource of 15 miles or less. Only eight candidate sites were identified for additional analysis.
Pipeline construction costs for delivering LFG from the resource to the DOE site were considered in NREL’s LCOE analysis. The potential impacts of surrounding geography, infrastructure, and land uses were not considered. It is not clear if the NREL evaluation considered the quality or quantity of LFG that could potentially be produced by the resource locations analyzed. However, based primarily on right-of-way issues, the NREL analysis determined that many of the sites would likely be infeasible for LFG development.
FINDING 3.6. The NREL/CSM analysis determined that waste-to-energy resources could be viable in some DOE-managed lands that are near urban areas. However, this analysis would need to include an evaluation of competing private-sector activities.
RECOMMENDATION 3.8. Given the limited potential for the development of waste-to-energy resources, the Department of Energy should not conduct further analyses.
FINDING 3.7. The analysis determined that LFG resources could be viable in some DOE sites, provided those sites were located within 15 miles of the necessary landfill. The analysis correctly notes that factors that are not related to LCOE, such as permitting and rights-of-way, will be dispositive. NREL’s analysis showed that while there were eight sites that met the proximity criterion, access to these sites would be infeasible due to development, waterways, and transportation infrastructure.
RECOMMENDATION 3.9. Given the difficulties associated with connecting landfill gas from its source to a Department of Energy (DOE) site where it would be utilized, DOE should not conduct further analyses.
Oil and natural gas are each forms of stored energy that may underlie DOE properties. Methane is a gas at room temperature and pressure. Oil is produced mainly from reservoirs that contain crude oil in a liquid form; some oil is produced as condensate from reservoirs containing liquid rich natural gas. Natural gas is produced in association with crude oil (associated gas) and from reservoirs containing gas (non-associated gas). After extraction, oil is refined to produce a variety of products, including most organic chemicals, plastics, and fuels, such as gasoline and diesel. Natural gas is used in electricity generation, for heating buildings, and as a feedstock for chemicals and other industrial processes.
Domestic oil and gas production increases have led to decreased prices for these commodities in the United States as well as increased manufacturing in the United States due to lower costs for energy and raw materials. Profitable oil and gas production depends on price, and U.S. exploration and production has slowed in response to the oil price drop.
The areas suitable for oil and natural gas production have increased with new methods of extraction. Until recently, much of the natural gas produced in the United States was associated with oil production
and subject to price volatility in response to global oil price volatility. Recent success in producing non-associated natural gas from shale plays has resulted in lower and more stable gas prices, making natural gas more suitable for electricity generation than coal.
The evaluation of oil and natural gas resources on DOE lands was undertaken by CSM. Screening criteria for the DOE sites were as follows: land area greater than 160 acres, land in a sedimentary basin, active drilling in the basin, and active drilling nearby to the site. Sites were ranked by priority from low to high. The only high-priority site was identified for oil production.
FINDING 3.8. The CSM analysis utilized proximity to current oil and gas development. This is sufficient for a preliminary screen of potential for oil and gas development on DOE lands and showed limited opportunities on DOE lands due to the size of property necessary for development.
RECOMMENDATION 3.10. The Department of Energy should not conduct further analyses, given the National Renewable Energy Laboratory/Colorado School of Mines study findings.
Another opportunity for use of DOE lands is siting nuclear reactors on DOE properties. A clear attribute of nuclear energy is the fact that its life cycle produces very low GHG emissions. A major issue for nuclear power is capital costs. Current estimates for the completion of facilities under construction run from $6 billion to $8 billion for a 1 GW plant. Once a facility is completed, operational and fuel costs are low.
Several power reactors are under construction in the United States on the sites of existing nuclear reactors. Construction began on four new reactors in 2013—all of them large, pressurized water reactors (with light-water moderator to thermalize the neutrons created by the fission process). These units are the AP 1000 by Westinghouse Electric Company and are being acquired by utilities in Georgia and South Carolina at power plants that already had nuclear power reactors.
Key issues to consider when siting new nuclear power plants include the size of the emergency planning zone (EPZ) and cooling water requirements. Such considerations are to some degree mitigated by newer reactor technologies. For example, small modular reactors (SMRs) might lead to reductions in the size of the EPZ, and the so-called Generation IV reactors, which operate at higher temperatures, will have smaller requirements for cooling water. All of these new reactors are also being designed to have greater flexibility in changing power output, versus older generation reactors that favored base-load operation.
Because of the advantages of continuing to use nuclear power in a low carbon future, coupled with the ongoing concerns related to waste disposal and public perceptions, DOE continues to fund the development of advanced reactors, particularly the development of SMRs. The term “modular” refers to the ability to fabricate major components of the nuclear steam supply system in a factory environment and ship to the point of use. SMRs provide simplicity of design, enhanced safety features, the economics and quality afforded by factory production, “plug and play” use, and more flexibility (financing, siting, sizing, and end-use applications) compared to larger nuclear power plants. Most nuclear energy research and development has been at Idaho National Laboratory and, thus, other possible locations for SMRs on DOE lands were not pursued.
RECOMMENDATION 3.11. Given the status of the Department of Energy’s (DOE’s) nuclear reactor development at Idaho National Laboratory, DOE should not conduct further analyses.
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