Energy & Technology
- Enhanced geothermal systems utilize advanced, often experimental, drilling and fluid injection techniques to augment and expand the availability of geothermal resources, which can be used to generate electricity from the heat in the earth’s crust.
- Enhanced geothermal systems, when recharged, can provide near continuous output, making the technology a renewable, zero-carbon option for supplying baseload electricity generation.
- While no commercial-scale enhanced geothermal plants exist today, a panel of geothermal experts convened by MIT in 2006 estimated that, with the proper incentives, enhanced geothermal systems could provide 100,000 megawatts (MW) of generating capacity by 2050, equivalent to 10 percent of today’s generating capacity.
The term enhanced geothermal systems (EGS), also known as engineered geothermal systems (formerly hot dry rock geothermal), refers to a variety of engineering techniques used to artificially create hydrothermal resources (underground steam and hot water) that can be used to generate electricity. Traditional geothermal plants (see Climate TechBook: Geothermal Energy) exploit naturally occurring hydrothermal reservoirs and are limited by the size and location of such natural reservoirs. EGS reduces these constraints by allowing for the creation of hydrothermal reservoirs in deep, hot geological formations, where energy production had not been economical due to a lack of fluid or permeability. EGS techniques can also extend the lifespan of naturally occurring hydrothermal resources.
Given the costs and limited full-scale system research to date, EGS remains in its infancy, with only research and pilot projects existing around the world and no commercial-scale EGS plants to date. The technology is promising, however, as a number of studies have found that EGS could quickly become widespread. One MIT study projected that EGS could reach an installed capacity of 100,000 MW in the United States by 2050—for comparison the United States currently has roughly 319,000 MW of coal-fueled generating net summer capacity. Were the United States to realize a significant fraction of this potential, it would make EGS one of the most important renewable energy technologies.
According to the U.S. Geologic Survey, the western United States has sufficient geological resources for over 517,800 MW of EGS capacity—roughly the equivalent of half the current total U.S. installed electric generating capacity from all energy sources. Nonetheless, the technologies needed to utilize this energy reserve are not yet commercially viable. According to the MIT report, realizing the theoretical potential of EGS will require consistent investment in research and development for up to 15 years before commercial viability and deployment are achieved. 
Figure 1: EGS resources at depth of 10km
Similar to traditional geothermal generation, EGS technologies use the heat of the earth’s crust to generate electricity. Traditional geothermal plants draw on naturally occurring hydrothermal resources at relatively shallow depths. EGS, however, attempts to artificially reproduce the conditions of naturally occurring hydrothermal reservoirs by fracturing impervious hot rocks at 3 to 10 kilometers depth, pumping fluid into the newly porous system, and then extracting the heated fluid to drive an electricity-generating turbine (see Figure 2). Artificially creating hydrothermal reservoirs gives EGS greater siting flexibility than traditional geothermal power plants, which can only be developed at sites with naturally occurring hydrothermal resources that may be limited in their size and their proximity to end-users of electricity.
The backbone and most difficult elements of EGS are the creation of the hydrothermal reservoir and a flow of fluid—typically water--through the fractured rock. In order to operate continuously, a geothermal plant must have access to a steady stream of heated fluid. This requires the creation of a reservoir that not only holds enough fluid but also allows it to readily move through the system. However, the hot rocks best suited for EGS are rarely porous enough, as they are buried so deep that they become compressed by the weight of the earth. As a result, EGS begins with increasing the natural porosity of a geological structure—often referred to as “stimulation.” Upon drilling an initial bore hole, highly pressurized water is pumped underground. As pressure mounts, the water stimulates fractures that branch out through the geological formation, creating a hydrothermal reservoir. Stimulation can be assisted by treatments involving the injection of various acids into the reservoir to corrode accumulated debris. 
After stimulation, EGS operators must estimate the volume and shape of the newly created reservoir. A variety of technologies, from seismic imaging to radioactive tracers, can then be used to design the best array of injection and production wells. In proposed designs, the injection well will be placed near the center of the reservoir, with multiple production wells flanking either edge of the reservoir. This allows water to flow outward from the injection well in all directions, optimizing flow rate and minimizing fluid loss. Once the reservoir has been established, it is functionally similar (with exceptions for well cost, restimulation and fluid replenishment) to traditional hydrothermal systems. An EGS power plant operates almost exactly like a traditional geothermal plant. Water is injected into the man-made hydrothermal reservoir, heated as it percolates through the stimulated fractures, and finally extracted at a production well, where it travels to the surface to drive an electricity-generating turbine. It is projected that the majority of EGS plants will use binary cycle geothermal technology to convert hydrothermal resources to electricity.
Figure 2: EGS Cutaway Diagram
Source: U.S. Department of Energy Geothermal Technologies Program. 2008. An Evaluation of Enhanced Geothermal Systems Technology.
The widespread application of EGS, however, will ultimately depend on advances in drilling technology. While oil and gas drilling techniques apply to geothermal drilling (both traditional and EGS), temperatures above 250°F that are necessary for geothermal reservoirs complicate the process. The high heat increases the probability of well failure due to collapse, mechanical malfunction, loss of telemetry, and casing failure.,, These limitations apply doubly to EGS wells, as EGS drilling requires drilling deeper, into harder and hotter rock than traditional geothermal plants.
Environmental Benefit / Emission Reduction Potential
EGS, like traditional geothermal energy, constitutes a source of electricity that is almost entirely free of greenhouse gas (GHG) emissions. Only small traces of carbon dioxide and other GHGs might be released from geological formations during the drilling phase of an EGS plant’s life. 
The greatest environmental benefit of EGS comes from its ability to satisfy baseload electricity demand. Unlike intermittent renewable energy technologies, such as wind and solar power, EGS could provide a consistent electricity supply similar to carbon-intensive coal-fired power plants. Replacing the generation from a typical 500 MW coal-fired power plant with electricity from geothermal plants would avoid about 3 million metric tons of CO2 emissions per year (roughly 0.1 percent of total U.S. CO2 emissions from electricity generation).
The installation of EGS would likely be expanded under a national climate or energy policy. Unfortunately, projections of renewable energy innovation under climate policies typically do not include predictions about EGS growth, given the experimental nature of the technology.
These same projections, however, expect traditional geothermal to grow under a climate policy. The overlap of the two geothermal technologies means that innovations in traditional geothermal should bolster the prospects of EGS as well. According to a panel of experts convened by MIT in 2006, EGS could reach an installed capacity of 100,000 MW by 2050—roughly a third of today’s installed coal capacity.
Abandoned or unproductive domestic oil fields could be adapted to EGS. The unproductive oil fields of Texas, for example, not only have already drilled bore holes, but also have verified thermal and geological information. Retooling these fields to produce hot water, instead of oil, could greatly expand the installed capacity of EGS once it reaches commercial deployment.
The experimental nature of EGS technology makes it difficult to evaluate the costs of a commercial scale EGS power plant. Initial estimates suggest that with current technology, the capital costs of an EGS plant would be roughly twice that of a traditional geothermal plant. While the capital costs of an EGS plant currently exceed those of a traditional fossil fuel power plant, one must look at the actual cost of generating electricity. Unlike a coal or natural gas plant, EGS facilities do not need to purchase fuel to generate electricity. This difference can be accounted for through a levelized cost analysis. Estimates of the cost of EGS vary and are uncertain because the cost of reservoir creation varies greatly depending on the geological formations at each EGS site. Using current drilling technology at an ideal site (marked by high temperatures at shallow depths and easily drillable geology), would allow for electricity generation at an estimated levelized cost of 17.5 to 29.5 cents per kilowatt-hour (kWh). At less suitable, yet still technically feasible locations (that require deeper drilling, often through hard granite formations), EGS could generate electricity at a cost of as much as 74.7 cents per kWh.
EGS costs are especially difficult to calculate given that current EGS plants are small pilot facilities designed for research, not power production. Subsequent commercial-scale plants are expected to achieve economies of scale. As such, the costs of currently operating plants provide limited insight into the costs of a commercial-scale EGS facility. Cost reductions seen for similar technologies used in the oil and gas industry in the past indicate the potential for significant cost reductions for EGS. With time, as EGS nears commercialization, EGS is projected to competitively produce electricity at 3.6 to 9.2 cents per kWh.,
The variability in cost estimates is largely attributable to the risks and inherent variability involved in the drilling and reservoir development stages of EGS. Drilling alone is estimated to be more than one-third of the capital costs of an EGS plant. EGS drilling is especially expensive given the greater depths often required to reach geological formations of sufficient heat. Deeper bore holes require more materials and have higher risks of failure, causing drilling costs to increase nonlinearly with depth. At a depth of 6,000 meters, drilling the initial bore hole for EGS is projected to cost $12 million to $20 million—roughly two to five times greater than oil and gas wells of comparable depth. Furthermore, these estimates do not include the cost of exploratory well drilling, a necessary but expensive step in developing a geothermal site that entails both risk and uncertainty.
Current Status of Enhanced Geothermal Energy
EGS remains in the research and development stage. Experimentation with EGS first began in the 1970s with a series of pilot projects at Fenton Hill, New Mexico. While the projects did not operate on a commercial scale, they did demonstrate the feasibility of the geologic engineering and drilling techniques needed to artificially create hydrothermal reservoirs. Since then, experimental EGS plants and pilot projects have been undertaken around the world. Realizing the full potential of EGS will take some time, and the International Energy Agency (IEA) believes that substantially higher research, development, and demonstration (RD&D) efforts are needed to ensure EGS becomes commercially viable by 2030.
In the United States, there has been growing interest in EGS. In 2009, the American Recovery and Reinvestment Act included $80 million for research and development of EGS technologies. The U.S. Department of Energy’s (DOE) Geothermal Technologies Program oversees on-going research and development related to EGS with the goal of improving the performance and lowering the cost of EGS technologies. The Geothermal Technologies Program partners with national laboratories, universities, and the private sector on EGS component technology research and development projects and EGS system demonstration projects. Two prominent EGS-related research projects are wastewater injection at The Geysers in California (the oldest geothermal field in the United States and largest geothermal venture in the world) and Desert Peak in Nevada, where EGS capacity will be added to an existing geothermal field. Finally, the Bureau of Land Management leases land in eleven Western states for continued geothermal resource development.
The European Union has long been involved in the efforts to research and develop enhanced geothermal systems technologies. France and Germany have operational EGS demonstration projects (1.5 to 2.5 MW), while Iceland and Switzerland are members of the International Partnership for Geothermal Technology (IPGT). The United States and Australia are also members of the IPGT, which is working to identify effective methodologies and practices for EGS development.
Obstacles to Further Development or Deployment of EGS
Need for Technology Research, Development, and Demonstration (RD&D)
A lack of RD&D constrains the deployment of EGS power plants. Most technologies used in EGS, such as drilling and geologic imagery techniques, are not yet adapted for specific use in EGS development.
High-Risk Exploration Phase
The exploratory phases of a geothermal project are marked by not only high capital costs but also a 75 percent chance of failure, when high fluid temperatures and flow rates are not located . The combination of high risk and high capital costs can make financing geothermal projects difficult and expensive.
Knowledge of Geothermal Geology
The ability to artificially create geothermal reservoirs consistently is greatly limited due to a lack of understanding of how geothermal reservoirs occur in nature. Researching the geological characteristics of natural geothermal resources is essential to adapting stimulation and drilling techniques in such a way that drives down the costs of EGS development.
Geographic Distribution and Transmission
Despite the siting flexibility of EGS technologies, the most promising EGS sites often occur great distances from regions of large electricity consumption, or load centers. The need to install adequate transmission capacity can deter investment in geothermal projects.
Policy Options to Help Promote EGS
Price on Carbon
A price on carbon would raise the cost of electricity produced from fossil fuels relative to the cost of electricity from renewable sources, such as EGS, and other lower-carbon technologies. A price on carbon would increase both deployment of mature low-carbon technologies and R&D investments in less mature technologies.
Clean Energy Standard
A clean energy standard is a policy that requires electric utilities to provide a certain percentage of electricity from designated low carbon dioxide-emitting sources. At present, 31 U.S. states and the District of Columbia have adopted clean energy standards, and clean energy standard has been proposed at the federal level. Clean energy standards encourage investment in new renewable generation and can guarantee a market for this generation.
Research, Development and Demonstration
Rapidly moving along the EGS technological “learning curve” requires sustained funding of further research efforts in the form of pilot plants and basic research in geology, drilling techniques and other associated EGS technologies.
Streamline Government Leasing and Permitting Procedures
Quickly deploying EGS will require federal agencies to more efficiently process applications for the development of EGS plants on public lands. Accelerating the speed of siting, leasing and permitting decisions will help make already risky EGS projects more attractive to investors.
Development of New Transmission Infrastructure
Improving transmission corridors to areas with geothermal reservoirs would facilitate investment in geothermal energy. Policies to build new transmission to areas with significant renewable energy resources are already proposed for accessing the wind-rich regions of the central plains and the extensive solar resources of the desert Southwest. Such policies could also promote expanded transmission to reach the geothermal fields of the West.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading / Additional Resources
U.S. Department of Energy (DOE). 2008. The Basics of Enhanced Geothermal Systems.
DOE’s Geothermal Technologies Program website
Geothermal Energy Association. 2012. “Geothermal Basics.”
International Energy Agency (IEA). 2011. Technology Roadmap - Geothermal Heat and Power
International Partnership for Geothermal Technology’s website
 “Tester, J., et al. 2006. The Future of Geothermal Energy: Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century. Massachusetts Institute of Technology.
 U.S. Department of Energy. 2008. “The Basics of Enhanced Geothermal Systems.” Accessed 22 August 2012. http://www1.eere.energy.gov/geothermal/pdfs/egs_basics.pdf
 Williams, E., et al. 2007. A Convenient Guide to Climate Change Policy and Technology. http://www.nicholas.duke.edu/ccpp/convenientguide/cg_pdfs/ClimateBook.pdf
 U.S. Energy Information Administration (EIA). 2011. “Table 8.11a Electric Net Summer Capacity: Total (All Sectors), 1949-2010.” Accessed 2 May 2012.
 Williams, C., et al. 2008. Assessment of Moderate-and High-Temperature Geothermal Resources of the United States. United States Geological Survey. http://pubs.usgs.gov/fs/2008/3082/pdf/fs2008-3082.pdf
 Tester et al., 2006.
 For an illustrated explanation, see the U.S. Department of Energy’s Geothermal Technologies Program’s webpage: “How an Enhanced Geothermal System Works” http://www1.eere.energy.gov/geothermal/egs_animation.html
 U.S. Department of Energy (DOE). 2008a. An Evaluation of Enhanced Geothermal Systems Technology. http://www1.eere.energy.gov/geothermal/pdfs/evaluation_egs_tech_2008.pdf
 DOE, 2008a.
 Tester et al., 2006.
 Rather than using hydrothermal steam to drive a turbine, a binary cycle geothermal plant uses heated water from the hydrothermal reservoir to vaporize a “working fluid,” any fluid with a lower boiling point than water (e.g., iso-butane). The vaporized working fluid drives a generator while the geothermal water is promptly reinjected into the reservoir, without ever leaving its closed loop system. To learn more about the conversion of hydrothermal resources to electricity see C2ES Climate TechBook: Geothermal Energy, 2009.
 DOE. 2008c. Multi-year Research, Development and Demonstration Plan: 2009-2015 with program activities to 2025. http://www1.eere.energy.gov/geothermal/pdfs/gtp_myrdd_2009-complete.pdf
 DOE, 2008a.
 A well’s casing is the pipe placed in a wellbore as an interface between the wellbore and the surrounding formation. It typically extends from the top of the well and is cemented in place to maintain the diameter of the wellbore and provide stability. Telemetry refers to the transmission of data from the drill bit to the operators on the surface.
 Fridleifsson, I.B., et al. 2008. The possible role and contribution of geothermal energy to the mitigation of climate change. In: O. Hohmeyer and T. Trittin (Eds.) IPCC Scoping Meeting on Renewable Energy Sources, Proceedings, Luebeck, Germany, 20-25 January 2008, 59-80.
 Kagel, A., Bates, D. and Gawell, K. 2007. A Guide to Geothermal Energy and the Environment. Yet these emissions should not be considered a disadvantage to geothermal energy. In fact, the gases released through geothermal energy production would have eventually entered the atmosphere, regardless of production in the area. In other words, the production of geothermal energy essentially generates zero net GHG emissions. (See Williams, E., et al. 2007). http://geo-energy.org/reports/environmental%20guide.pdf
 U.S. Environmental Protection Agency (EPA). 2011. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009.
 Assuming a coal-plant capacity factor of 70 percent and an emissions rate of 1 metric ton CO2 per MWh.
 For example, the U.S. Energy Information Administration (EIA) models proposed climate and energy policies but does not include EGS as a technology choice in its model, stating that EGS are not included as potential resources since this technology is still in development and is not expected to be in significant commercial use within the projection horizon [by 2030].” See EIA, Assumptions to the Annual Energy Outlook 2009: Renewable Fuels Module. http://www.eia.gov/oiaf/aeo/assumption/pdf/0554(2009).pdf
 EIA, 2011.
 This practice involves creating hydrothermal reservoirs within the geological structures of abandoned oil fields. This allows the EGS plant operators to take advantage of verified thermal and geological data in order to more cheaply create a hydrothermal reservoir. For more information, see McKenna, J., et al. “Geothermal electric power supply possible from Gulf Coast, Midcontinent oil field waters.” The Oil and Gas Journal. 103:33 (2005).
 McKenna et al., 2005.
 Delaquil, P., Goldstein, G., and Wright, E. 2008. “US Technology Choices, Costs and opportunities under the Lieberman-Warner Climate Security Act: Assessing Compliance Pathways.” International Resources Group. http://docs.nrdc.org/globalwarming/files/glo_08051401A.pdf
 The levelized cost of electricity is an economic assessment of the cost of electricity generation from a representative generating unit of a particular technology type (e.g. wind, coal, EGS) that includes costs over the lifetime of the plant: initial investment, operations and maintenance, cost of fuel, and cost of capital. The levelized cost generally does not include costs associated with transmission and distribution of electricity. Levelized cost estimates can vary based on uncertainty regarding and differences in underlying assumptions, such as the size and application of the system, what taxes and subsidies are included, location of the system, and other factors.
 Tester et al., 2006.
 DOE, 2008b.
 Western Governors’ Association. 2006. Geothermal Task Force Report. Clear and Diversified Energy Initiative.
 Tester et al., 2006.
 Deloitte. 2008. Geothermal Risk Mitigation Strategies Report. Prepared for Department of Energy, Office of Energy Efficiency and Renewable Energy Geothermal Program. http://www1.eere.energy.gov/geothermal/pdfs/geothermal_risk_mitigation.pdf
 International Energy Agency (IEA). 2011. Geothermal Heat and Power Roadmap. http://www.iea.org/papers/2011/Geothermal_Foldout.pdf
 DOE. 2009. “Recovery Act Announcement: President Obama Announces Over $467 Million in Recovery Act Funding for Geothermal and Solar Energy Projects.” http://apps1.eere.energy.gov/news/progress_alerts.cfm/pa_id=173
 DOE. 2012. “Geothermal Technologies Program - EGS Component R&D.” http://www4.eere.energy.gov/geothermal/projects?filter[field_project_area]=%2248%22
 DOE 2012. “Geothermal Technologies Program - EGS Systems Demonstration.” http://www4.eere.energy.gov/geothermal/projects?filter[field_project_area]=%2249%22
 Bureau of Land Management (BLM). 2011. “Renewable Energy and the BLM: GEOTHERMAL.” http://www.blm.gov/pgdata/etc/medialib/blm/wo/MINERALS__REALTY__AND_RESOURCE_PROTECTION_/energy.Par.74240.File.dat/Fact_Sheet_Geothermal_Oct_2011.pdf
 Ledru, P. et al. 2007. “ENhanced Geothermal Innovative Network for Europe: the state-of-the-art.” Geothermal Resources Council Bulletin. http://engine.brgm.fr/Documents/GRC_ENGINE_Presentation_06092006.pdf
 GEA, 2012.
 IGPT, 2012.
 DOE, 2008b.
 Deloitte, 2008.
For an example of this work, see Blankenship, D., et al. 2009. Development of a High-Temperature Diagnostics-While-Drilling Tool. Sandia Report 2009-0248. http://www1.eere.energy.gov/geothermal/pdfs/ht_dwd_tools.pdf
 See footnote 9 in Tester et al., 2006.
 Center for Climate and Energy Solutions (C2ES). 2012a. “C2ES State Policy Map - Renewable & Alternative Energy Portfolio Standards.” Accessed 22 August 2012. http://www.c2es.org/what_s_being_done/in_the_states/rps.cfm
 C2ES. 2012b. Summary of the Clean Energy Standard Act. http://www.c2es.org/docUploads/bingaman-clean-energy-standard-act-summary.pdf.
Carbon capture and storage (CCS) technologies can capture up to 90 percent of carbon dioxide (CO2) emissions from a power plant or industrial facility and store them in underground geologic formations.
Carbon capture has been established for some industrial processes, but it is still a relatively expensive technology that is just reaching maturity for power generation and other industrial processes.
- There are twelve active commercial-scale CCS projects at industrial facilities around the world (eight of those projects are in the U.S.), and approximately 50 additional projects are in various stages of development around the world (Global Carbon Capture and Storage Institute project list).
The world’s first commercial-scale CCS power plant, SaskPower's Boundary Dam Power Station in Saskatchewan, Canada, will become operational in October 2014. Two additional CCS power plants are under construction - Southern Company’s Kemper County Energy Facility in Mississippi and NRG's Petra Nova project in Texas.
- There is a growing market for utilizing captured CO2, primarily in enhanced oil recovery (CO2-EOR). Selling captured CO2 provides a valuable revenue source to help overcome the high costs and financial risks of initial CCS projects.
The International Energy Agency (IEA) estimates that CCS can achieve 14 percent of the global greenhouse gas emissions reductions needed by 2050 to limit global warming to 2 degrees Celsius (IEA CCS Roadmap).
CCS can allow fossil fuels, such as coal and natural gas, to remain part of our energy mix, by limiting the emissions from their use.
Electricity generation and industrial processes release large amounts of carbon dioxide (CO2), the primary greenhouse gas (GHG). In 2011, coal- and natural gas-fueled electricity generation accounted for approximately 80 percent and 19 percent, respectively, of CO2 emissions from the U.S. electricity sector; together, they accounted for almost 32 percent of all U.S. GHG emissions. Not including its electricity use, the industrial sector’s CO2 emissions accounted for an additional 15 percent of total U.S. GHG emissions. The combustion of fossil fuels accounted for approximately 79 percent of the industrial sector’s CO2 emissions, while industrial processes accounted for approximately 21 percent.
Going forward, coal and natural gas will remain major sources of energy for the U.S. and global power and industrial sectors. In the United States, both coal and natural gas are in relatively abundant supply and are relatively inexpensive electricity generation sources., In 2011, the United States generated approximately 42 percent of its electricity from coal and 25 percent from natural gas. Globally, coal and natural gas will continue to meet growing energy demand, particularly in emerging market counties, such as China and India. From 2008 to 2012, China’s total coal consumption increased by nearly 35 percent, while India’s increased by 25 percent. During that same time period, China’s total natural gas consumption increased by more than 89 percent, while India’s increased by nearly 37 percent.
CCS technology has the potential to yield dramatic reductions in CO2 emissions from the power and industrial sectors by capturing and storing anthropogenic CO2 in underground geological formations. Given the magnitude of CO2 emissions from coal and natural gas-fired electricity generation, the greatest potential for CCS is in the power sector. The U.S. Energy Information Administration (EIA) estimates that natural gas, when used in an efficient combined cycle plant, emits less than half as much CO2 as coal. The deployment of CCS with coal generation is necessary to reduce coal’s release of global CO2 emissions relative to natural gas, but CCS also can be combined with natural gas generation to limit the impact of natural gas electricity generation on global CO2 emissions.
In the industrial sector, CO2 can be captured from a number of industrial processes, including natural gas processing; ethanol fermentation; fertilizer, industrial gas, and chemicals production; the gasification of various feedstocks; and the manufacture of cement and steel.
CCS uses a combination of technologies to capture the CO2 released by fossil fuel combustion or an industrial process, transport it to a suitable storage location, and finally store it (typically deep underground) where it cannot enter the atmosphere and thus contribute to climate change. CO2 geologic storage options include saline formations and depleted oil reservoirs, where captured CO2 can be utilized in enhanced oil recovery (CO2-EOR).
Currently, CCS has been deployed at commercial-scale natural gas processing, fertilizer production, synfuel production, and hydrogren production facilities. The first commercial-scale coal-fired power plant with CCS (Boundary Dam in Saskatchewan) will become operational in October 2014. Two additional commercial power plants are alose under construction.
The various technologies used for CCS are described below.
Good candidates for early commercial CCS adoption are certain industrial processes, where it is relatively easy to capture CO2. As a part of normal operations, these processes remove CO2 in high-purity, concentrated streams. Equipment can be used to capture CO2 from these streams, instead of otherwise being emitted.
Figure 1: How CCS Works
Source: Global Carbon Capture and Storage Institute. 2012. “How CCS Works.” http://www.globalccsinstitute.com/ccs/how-ccs-works
For other industrial processes and electricity generation, carbon capture is more difficult. Current processes must be reengineered or redesigned to process CO2 and concentrate it for capture and transportation. There are three primary methods for CO2 capture from these other industrial processes and electricity generation:
Pre-Combustion Carbon Capture
Fuel is gasified (rather than combusted) to produce a synthesis gas, or syngas, consisting mainly of carbon monoxide (CO) and hydrogen (H2). A subsequent shift reaction converts the CO to CO2, and then a physical solvent typically separates the CO2 from H2.
For power generation, pre-combustion carbon capture can be combined with an integrated gasification combined cycle (IGCC) power plant that burns the H2 in a combustion turbine and uses the exhaust heat to power a steam turbine.
Post-Combustion Carbon Capture
Post-combustion capture typically uses chemical solvents to separate CO2 out of the flue gas from fossil fuel combustion. Retrofitting existing power plants for carbon capture is likely to use this method.
Oxyfuel Carbon Capture
Oxyfuel capture requires fossil fuel combustion in pure oxygen (rather than air) so that the exhaust gas is CO2-rich, which facilitates capture.
Once captured, CO2 must be transported from its source to a storage site. Pipelines like those used for natural gas present the best option for terrestrial CO2 transport. As of 2009, there were approximately 3,900 miles of pipelines for transporting CO2 in the United States for use in enhanced oil recovery.
The primary option for storing captured CO2 is injecting it into geological formations deep underground. The United States has geological formations with sufficient capacity to store CO2 emissions from centuries of continued fossil fuel use based on 2011 emissions.
A combination of regulations and technology can provide a high level of confidence that CO2 will be safely and permanently stored underground. In the United States, federal and state regulations cover CO2 storage site selection and injection. In addition, CO2 storage technologies for measurement, monitoring, verification, accounting, and risk assessment can minimize or mitigate the potential of stored CO2 to pose risks to humans and the environment. Options for CO2 geologic storage options include:
Deep Saline Formations
The largest potential for geologic storage in the United States is in deep saline formations, which are underground porous rock formations infused with brine. Deep saline formations are found in many locations across the country, but less is known about their storage potential because they have not been examined as extensively as oil and gas reservoirs.
Oil and Gas Reservoirs (Enhanced Oil Recovery with Carbon Dioxide, CO2-EOR)
Oil and gas reservoirs offer geologic storage potential as well as economic opportunity through CO2-EOR. CO2-EOR is a tertiary oil production process which injects CO2 into oil wells to extract the oil remaining after primary production methods. Oil and gas reservoirs are thought to be suitable candidates for the geologic storage of CO2 given that they have held oil and gas resources in place for millions of years, and previous fossil fuel exploration has yielded valuable data on subsurface areas that could help to ensure permanent CO2 geologic storage. CO2-EOR operations have been operating in West Texas for over 30 years. Moreover, revenue from selling captured CO2 to EOR operators could help defray the cost of CCS at power plants and industrial facilities that adopt the technology.
Unminable Coal Beds
Coal beds that are too deep or too thin to be economically mined could offer CO2 storage potential. Captured CO2 can also be used in enhanced coalbed methane recovery (ECBM) to extract methane gas.
Basalt formations and shale basins are also considered potential future geologic storage locations.
Figure 2: Map of North American Sedimentary Basins for CO2 Storage
Source: National Energy Technology Laboratory. “NATCARB CO2 Storage Formations.” http://www.netl.doe.gov/technologies/carbon_seq/natcarb/storage.html.
Environmental Benefit / Emission Reduction Potential
CCS technology has the potential to reduce CO2 emissions from a coal or natural gas-fueled power plant by as much as 90 percent. CCS could provide significant economy-wide CO2 emission reductions:
- The U.S. Energy Information Administration’s (EIA) modeling analysis of the Waxman-Markey American Clean Energy and Security Act of 2009 projected that, under the proposed cap-and-trade program, coal power plants with CCS could provide 11 percent of U.S. electricity by 2030, and that new coal power plants with CCS could account for 28 percent of new generating capacity. In contrast, under a business-as-usual scenario and without legislation, new coal power plants would account only for 11 percent of new generating capacity.
- Due to rising global demand for energy, the consumption of fossil fuels is expected to rise through 2035, leading to greater CO2 emissions. CCS technology offers the opportunity to reduce emissions while maintaining a role for fossil fuels in national energy portfolios.
- Under its 2 °C Scenario (2DS), the International Energy Agency (IEA) estimates that CCS will provide 14 percent of cumulative emissions reductions between 2015 and 2050 compared to a business as usual scenario. Under the same scenario, CCS provides one-sixth of required emissions reductions in 2050.
- Oil produced by CO2-EOR projects can be considered relatively lower-carbon than oil produced by other techniques. For example, the carbon stored by the Weyburn EOR project can offset approximately 40 percent of the combustion emissions resulting from the oil it produces, not including emissions from electricity use due to compression, lifting, and refining.
The implementation of CCS technology raises the investment costs for power and industrial projects. New power plants and industrial facilities can be designed to incorporate CCS from their inception, or the technology can be retrofitted to existing sources of CO2 emissions. Overall, the cost of each project can vary considerably. The incremental cost of CCS varies depending on parameters such as the choice of capture technology, the percentage of CO2 captured, the type of fossil fuel used, and the distance to and type of geologic storage location. Overall, as with other new technologies, the cost of CCS is expected to be higher for the first CCS projects and decline thereafter as the technology moves along its “learning curve.”,
Selling captured CO2 as a commodity is one option for mitigating the higher upfront costs and risks of investing in CCS. Enhanced oil recovery is an emerging opportunity for utilizing captured CO2. In the United States, CO2-EOR already accounts for 6 percent of domestic oil production, and the industry could take advantage of enormous oil reserves if more CO2 is captured and utilized. 26.9 to 61.5 billion barrels could be extracted with “state of the art” CO2-EOR technology, while 67.2 to 136.6 billion barrels could be extracted with “next generation” CO2-EOR technology. 
Power Plant Capture Costs
Carbon capture raises power plant costs by requiring capital investment in carbon capture equipment and by reducing the quantity of useful electricity. Additional generation capacity is needed at a power plant to power capture equipment, and incorporating CCS at a power plant could decrease its net power output by as much 30 percent. Overall, in 2010, the U.S. Department of Energy and the National Energy Technology Laboratory estimated that “CCS technologies would add around 80 percent to the cost of electricity for a new pulverized coal plant, and around 35 percent to the cost of electricity for a new advanced gasification-based plant.”
In 2010, the National Energy Technology Laboratory (NETL) released a report on CCS costs for new integrated combined cycle (IGCC), pulverized coal (PC), and natural gas combined cycle (NGCC) power plants. The study compared the levelized costs of electricity for individual power plant configurations with and without CO2 capture. For each power plant type, the average levelized cost of electricity with and without CCS was estimated to be:
Table 1: Levelized Cost of Electricity for New-Build Power Plants with and without CCS
Power Plant Type
Average LCOE without CCS
Average LCOE with CCS
Retrofitting existing plants for CCS is expected to be more expensive and reduce a plant’s overall efficiency when compared to building a new plant that incorporates CCS from the start. In addition, retrofitting CCS on existing power plants faces additional constraints: insufficient land and space for capture equipment; a shorter expected plant life than a new plant, which limits the window in which to repay the investment in CCS equipment; and the tendency of existing plants to have lower efficiency, which consequently means that CCS will have a proportionally greater impact on net output than it would have in new plants. New power plants without CCS can be designed to be “CCS-ready” so that the cost of later retrofitting the plant for CCS will be lower.
Industrial Facility Capture Costs
The cost of capturing carbon from different industrial processes varies considerably. This variation results from the relative ease of capturing CO2 from certain industrial processes and the level of maturation for capture technologies. Carbon capture is easier when CO2 is produced in high purity and high concentration streams as the byproduct of certain industrial processes, such as natural gas processing, hydrogen production, and synthetic fuel production. In contrast, it is relatively more difficult to capture CO2 from flue gas emissions, which may require “the reengineering of certain established and reliable production techniques.” Similar to power plants, industrial processes that produce carbon via flue gas are cement production, iron and steel manufacturing, and refining. The U.S. Energy Information Administration estimated industrial carbon capture and CO2 transportation costs for the following industrial processes:
Table 2: Cost of CO2 Capture and Transportation for Various Industrial CO2 Sources
Industrial CO2 Source
Cost of CO2 Capture and Transp. ($/Metric ton)
Coal and biomass-to-liquids
Natural gas processing
36.67 to 46.12
36.67 to 46.12
CO2 Transportation and Storage Costs
Transportation and storage costs will vary by CO2 capture project and the proximity and availability of pipeline networks and injection sites. The Environmental Protection Agency estimates that the long-term average cost for CO2 transportation and storage is approximately $15 per metric ton of CO2.
Current Status of CCS
Currently, CCS has been deployed at commercial-scale industrial facilities, and the first commercial-scale power plants with CCS are under construction. As of late 2013, the Global Carbon Capture and Storage Institute (GCCSI) listed twelve commercial-scale CCS projects in operation and around 50 additional projects in various stages of development around the world. Around 20 of these projects are located in the United States (see the Global Carbon Capture Institute’s large-scale integrated CCS project database). The International Energy Agency (IEA) labels CCS as a critical technology for limiting the rise in global temperature to 2° Celsius (3.6° F) by 2050 and calls for 38 power and 82 industrial large-scale integrated CCS projects to be in place by 2020 to meet this objective. Given that only around 20 large-scale integrated CCS projects are estimated to be in operation by the mid-2010s, the IEA has labeled the status of CCS as “not on track.”
The status of the component technologies of CCS is reviewed below.
Carbon capture technologies have long been used for industrial processes like natural gas processing and CO2 generation for the food and beverage industry. Currently, in the United States, commercial-scale CCS projects include four natural gas processing facilities, two fertilizer plants, a synfuel plant, and a hydrogen plant that capture CO2 and transport it for use in enhanced oil recovery. In the power sector, the first commercial-scale power plant, SaskPower's Boundary Dam project in Saskatchewan, will be world's first commercial-scale project with CCS. Additional power plants and industrial facilities with CCS are under construction or in design stages. Few or no commercial-scale projects have been proposed for other high-emitting CO2 sources, such as iron and steel, cement, and pulp and paper production.
The United States already has approximately 3,900 miles of CO2 pipelines used to transport CO2 for EOR. CO2 pipeline transport is commercially proven.
Globally, there is much research and policy activity regarding CO2 storage. Many countries are setting up legal and regulatory frameworks for CO2 injection and long-term monitoring and verification, while mapping geologic formations for CO2 storage potential. Technologies are available to minimize or mitigate the risks of geologically stored CO2 to humans and the environment, but policies are needed to ensure that these technologies are deployed effectively. CO2 can be monitored and accounted for once injected underground, while risk assessment tools can determine the suitability of sites for CO2 storage. CO2 injection in EOR wells is commercially proven and has a history of safely storing CO2 underground. Research by the University of Texas Bureau of Economic Geology found no evidence of leakage from the SACROC oil field where CO2-EOR has been performed since the 1970s.
A well-developed regulatory framework for CO2 injection and geologic storage is also essential to protect human health and the environment. In the United States, the Safe Drinking Water Act and the EPA’s Underground Injection Control Program impose safety requirements on CO2 injection. In addition, the Clean Air Act and the EPA’s GHG Emissions Program require project operators to report data on CO2 injections and to submit monitoring, reporting, and verification (MRV) plans if CO2 is injected for geologic storage. U.S. state regulations can include additional requirements. In addition, the Underground Injection Control Program requires previous seismic history to be considered when selecting geologic CO2 sequestration sites. Large faults should be avoided entirely. In addition, the risk of small earthquakes causing CO2 leakage to the surface is mitigated by multiple layers of rock that prevent CO2 from reaching the surface even if they migrate from an injection zone.
Finally, there is on-going work to determine the size of CO2 sequestration resources and the suitability of individual sites for CO2 injection. In 2012, the U.S. Department of Energy (DOE) and NETL released The North American Carbon Storage Atlas, in conjunction with partner agencies from Canada and Mexico. Also, since 2003, DOE has supported Regional Partnerships focused on geologic CO2 storage. The partnerships are initiating large-scale tests to determine how storage reservoirs and their surroundings respond to large amounts of injected CO2 in a variety of geologic formations and regions across the United States. Through the American Recovery and Reinvestment Act of 2009, DOE and the Archer Daniels Midland Company (ADM) are sharing the investment costs of capturing one million tons of CO2 per year from ADM’s ethanol plant in Decatur, Illinois and injecting it in a nearby reservoir. The Midwest Geologic Sequestration Consortium (MGSC) has begun to inject and store CO2 from the facility.
Obstacles to Further Development or Deployment of CCS
- Deploying CCS requires large incremental investments in capital equipment and higher operating costs.
Lack of a Price on Carbon, GHG Emissions Performance Standards, or CCS incentives
- Policies that place a financial cost on or otherwise limit GHG emissions, or subsidize CCS, are crucial for incentivizing investments in CCS.
Need for Faster Commercial-Scale CCS Project Development
- The first commercial-scale CCS projects integrated with power plants and certain industrial facilities will generate valuable information on the actual cost and performance of CCS as well as the optimal configuration of the technologies. These projects also will provide much-needed data to guide firms’ investments and will lead to cost reductions via technology improvements.
Uncertainty in CO2 Storage Regulations
- CO2 injection in geologic formations is regulated at the federal level by the Environmental Protection Agency’s Underground Injection Control (UIC) program, and the quantity of injected CO2 must be reported under the Mandatory Greenhouse Gas Reporting Rule. Additional regulations at federal, state, and local levels are being developed to specify site selection criteria; well, injection, and closure operational requirements; long-term monitoring and verification requirements; and long-term liability. Without a clear regulatory or legal framework in place, investment in CCS may be hindered.
Policy Options to Help Promote CCS
Price on Carbon
- Policies that place a price on GHG emissions, such as cap and trade, would discourage investments in traditional fossil-fuel use and spur investments in a range of clean energy technologies, including CCS.
Including CCS in Clean Energy Standards
- A clean energy standard is a policy that requires electric utilities to provide a certain percentage of electricity from designated low carbon dioxide-emitting sources. CCS has been included in state-level clean energy standards and under a proposed federal clean energy standard.
Funding for Continued CCS Research, Development, and Demonstration
- Globally, approximately $23.5 billion in public support has been made available for CCS demonstration, with much of this amount coming through recent economic stimulus packages. By the end of 2010, public institutions had distributed only 55 percent of the available public support for CCS to actual CCS projects. The United States has spent approximately $6.1 billion of the available $7.4 billion in public funding designated for CCS. Under the American Recovery and Reinvestment Act of 2009, the U.S. Department of Energy’s Office of Fossil Energy received $3.4 billion to support clean coal and other aspects of CCS development.
Incentivizing CCS and CO2-EOR
- Federal and state-level incentives can foster the initial, large-scale CCS projects that are needed to fully demonstrate the technology. At the federal level, Section 45Q tax credits provide $10 per metric ton of CO2 stored through enhanced oil recovery and $20 per metric ton of CO2 stored through deep saline formations. The National Enhanced Oil Recovery Initiative recommends an expansion of the existing 45Q tax credit for capturing carbon dioxide for use in EOR, as well as modifications to improve the functionality and financial certainty of 45Q tax credits. The Initiative also recommends U.S. states to consider incentives such as allowing cost recovery through the electricity rate base for CCS power projects; including CCS under electricity portfolio standards; offering long-term off-take agreements for the products of a CCS project; and providing supportive tax policy for CCS or CO2-EOR projects.
Setting GHG Emissions Rates
- Policymakers can enact regulations that require CCS via a new source performance standard for power plants or a low-carbon performance standard (similar to the renewable portfolio standards that many states already have). In 2013, the EPA proposed new greenhouse gas emissions standards for new power plants, which would likely require new coal-fired power plants to meet emissions standards by including CCS technology.
Defining a CO2 Storage Regulatory Framework
- Uncertainty regarding the regulatory or legal framework governing CO2 storage may hinder investment in CCS. Determining regulatory authorities and legal requirements for CO2 storage will provide additional certainty for project developers and operators.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading / Additional Resources
U.S. Department of Energy/National Energy Technology Laboratory
- DOE Office of Fossil Energy - Clean Coal Technologies, Carbon Sequestration
- NETL - Carbon Storage Program
- DOE/NETL Carbon Dioxide Capture and Storage R&D Roadmap (2010)
- The North American Carbon Storage Atlas (2012)
- Major Demonstrations - Clean Coal Power Initiative
- Major Demonstrations - Industrial Carbon Capture and Storage
National Enhanced Oil Recovery Initiative (NEORI)
Congressional Research Service
- Folger, Carbon Capture and Sequestration: Research, Development, and Demonstration at the U.S. Department of Energy (2014)
- Folger, Carbon Capture: A Technology Assessment (2013)
Global CCS Institute
International Energy Agency
- Technology Roadmap - Carbon Capture and Storage (2013)
- A Policy Strategy for Carbon Capture and Storage (2012)
- Tracking Progress in Carbon Capture and Storage (2012)
Congressional Budget Office
Massachusetts Institute of Technology (MIT)
 U.S. Environmental Protection Agency (EPA). 2013. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011. http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Main-Text.pdf.
 U.S. Energy Information Agency (EIA). 2011a. “What is the role of coal in the United States.” http://126.96.36.199/energy_in_brief/role_coal_us.cfm.
 EIA. 2012a. “What is shale gas and why is it important.” http://188.8.131.52/energy_in_brief/about_shale_gas.cfm.
 EIA. 2011b. Annual Energy Review 2010. Table 8.2a Electricity Net Generation: Total (All Sectors), Selected Years, 1949-2010. http://www.eia.gov/totalenergy/data/annual/pdf/sec8_8.pdf
 EIA. “International Energy Statistics.” Accessed 6 July 2012. http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=1&pid=1&aid=2
 EIA, 2012.
 National Enhanced Oil Recovery Initiative (NEORI). 2012a. Carbon Dioxide Enhanced Oil Recovery: A Critical Domestic Energy, Economic, and Environmental Opportunity. http://www.neori.org/NEORI_Report.pdf
 Global Carbon Capture and Storage Institute (GCCSI). "Status of CCS Project Database" Accessed 1 October 2014.
 United Nations Industrial Development Organization (UNIDO). 2010. Carbon Capture and Storage in Industrial Applications: Technology Synthesis Report Working Paper – November 2010. http://cdn.globalccsinstitute.com/sites/default/files/publications/15661/carbon-capture-and-storage-industrial-applications-technology-synthesis-report.pdf
 Dooley, J., Davidson, C., and Dahowski, R. 2009. “Comparing Existing Pipeline Networks with the Potential Scale of Future U.S. CO2 Pipeline Networks.” Energy Procedia. Volume 1, Issue 1, February 2009.
 U.S. National Technology Energy Laboratory (NETL), et al. 2012. The North America Carbon Storage Atlas 2012. http://www.netl.doe.gov/File%20Library/Research/Coal/carbon-storage/atlasiv/Atlas-IV-2012.pdf
 NETL, et al. 2012.
 NETL, et al. 2012.
 Tertiary oil production follows primary and secondary production. Primary and secondary oil production only recovers 30 to 50 percent of the original amount of oil found in a given oil reservoir. Tertiary production can recover an additional 15 percent of the original oil. The tertiary phase require(s) the use of some injectant that reacts with the oil to change its properties and allow it to flow more freely within the reservoir. Heat, hot water or chemicals can do that. These techniques are commonly lumped into a category called enhanced oil recovery or EOR. One of the most utilized of these methods is carbon dioxide (CO2) flooding. Almost pure CO2 (>95% of the overall composition) has the property of mixing with the oil to swell it, make it lighter, detach it from the rock surfaces, and cause the oil to flow more freely within the reservoir so that it can be swept up in the flow from injector to producer well. (Melzer NEORI paper).
 NETL. 2010a. Carbon Dioxide Enhanced Oil Recovery. Untapped Domestic Energy Supply and Long Term Carbon Storage Solution. http://www.netl.doe.gov/technologies/oil-gas/publications/EP/small_CO2_eor_primer.pdf
 NETL, et al. 2012.
 Finkenrath, M. 2011. Cost and Performance of Carbon Dioxide Capture from Power Generation. International Energy Agency. http://www.iea.org/publications/freepublications/publication/costperf_ccs_powergen-1.pdf
 Center for Climate and Energy Solutions (C2ES). 2009. “In Brief: What the Waxman-Markey Bill Does for Coal.” http://www.c2es.org/federal/what-waxman-markey-does-for-coal
 International Energy Agency. 2011. “World Energy Outlook Factsheet – How will global energy markets evolve to 2035?” http://www.worldenergyoutlook.org/media/weowebsite/factsheets/factsheets.pdf
 International Energy Agency. 2013. Technology Roadmap - Carbon Capture and Storage. http://www.iea.org/publications/freepublications/publication/name,39359,en.html
 Taglia, P. 2010. Enhanced Oil Recovery (EOR) – Petroleum Resources and Low Carbon Fuel Policy in the Midwest. http://cleanwisconsin.org/proxy.php?filename=files/EnhancedOilRecovery.pdf
 McKinsey & Company. 2008. Carbon Capture and Storage: Assessing the Economics. http://www.mckinsey.com/clientservice/ccsi/pdf/CCS_Assessing_the_Economics.pdf
 Kuuskraa, Vello. 2007. A Program to Accelerate the Deployment of CO2 Capture and Storage
(CCS): Rationale, Objectives, and Costs. Prepared for the Pew Center on Global Climate Change. http://www.c2es.org/white_papers/coal_initiative/ccs_demo
 Kuuskra, V., Van Leeuwen, T., and Wallace M. 2011. Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR). Prepared by Advanced Resources International (ARI) for the U.S. Department of Energy and the U.S. National Energy Technology Laboratory.
 The use of power plant electricity for CCS equipment is sometimes referred to as parasitic load.
 U.S. Department of Energy (DOE) and U.S. National Energy Technology Laboratory (NETL). 2010. DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap. http://www.netl.doe.gov/File%20Library/Research/Carbon%20Seq/Reference%20Shelf/CCSRoadmap.pdf
 NETL. 2010b. Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity. http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/OE/BitBase_FinRep_Rev2a-3_20130919_1.pdf
 Finkenrath, 2012.
 UNIDO, 2010.
 Dooley, J., Dahowski, R., and Davidson, C. 2008. On the Long-Term Average Cost of CO2
Transport and Storage. Pacific Northwest National Laboratory. http://www.pnl.gov/main/publications/external/technical_reports/pnnl-17389.pdf
 IEA. 2012. Tracking Clean Energy Progress – Energy Technology Perspectives 2012 excerpt as IEA input to the Clean Energy Ministerial. http://www.iea.org/media/etp/Tracking_Clean_Energy_Progress.pdf
 GCCSI, 2013.
 Dooley, J., Davidson, C., and Dahowski, R. 2008. Comparing Existing Pipeline Networks with the
Potential Scale of Future U.S. CO2 Pipeline Networks. http://www.pnnl.gov/main/publications/external/technical_reports/PNNL-17381.pdf
 GCCSI, 2011.
 NETL, et al. 2012.
 EPA. 2012b. “Geologic Sequestration of Carbon Dioxide.” Accessed 6 July 2012. http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm
 Peridas, G. 2012. “CCS and Earthquakes – Anything to Worry About?.” Accessed 6 July 2012. ENGO Network on CCS. http://www.engonetwork.org/Blog.html?entry=ccs-and-earthquakes-anything-to
 DOE. 2012. “Carbon Sequestration Regional Partnerships.” Accessed 5 May 2014. http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships
 NETL. 2012. “Archer Daniels Midland Company: CO2 Capture from Biofuels Production and Sequestration into the Mt. Simon Sandstone.” Accessed 6 July 2012. http://www.netl.doe.gov/publications/factsheets/project/FE0001547.pdf
 Midwest Geological Sequestration Consortium (MGSC). 2012. “ISGS-led consortium begins injection of CO2 for storage at the Illinois Basin - Decatur Project.” http://sequestration.org/resources/topStories.html
 EPA. 2012b.
 EPA. 2011. “Fact Sheet for Geologic Sequestration and Injection of Carbon Dioxide: Subparts RR and UU.” http://www.epa.gov/ghgreporting/documents/pdf/2011/documents/Subpart-RR-UU-factsheet.pdf
 C2ES. 2012a. “Renewable & Alternative Energy Portfolio Standards.” Accessed 6 July 2012. http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=5907
 C2ES. 2012b. Summary of the Clean Energy Standard Act. http://www.c2es.org/docUploads/bingaman-clean-energy-standard-act-summary.pdf
 Global Carbon Capture and Storage Institute (GCCSI). 2011. The Global Status of CCS: 2011. http://cdn.globalccsinstitute.com/sites/default/files/publications/22562/global-status-ccs-2011.pdf
 DOE. “FE Implementation of the Recovery Act.” http://energy.gov/fe/fe-implementation-recovery-act
 NEORI, 2012a.
 C2ES. 2013. “EPA Regulation of Greenhouse Gas Emissions from New Power Plants.” http://www.c2es.org/federal/executive/epa/ghg-standards-for-new-power-plants
I recently responded to a question on the National Journal blog, "What role should natural gas play in the United States?"
You can read more on the original blog post and other responses at the National Journal.
Here is my response:
Leading by Example: Using Information and Communication Technologies to Achieve Federal Sustainability Goals
Eileen Claussen's Statement on the Bipartisan Bill to Reduce Carbon Emissions and Develop Domestic Energy Resources
Statement of Eileen Claussen
President, Center for Climate and Energy Solutions
Sept. 20, 2012
The bipartisan bill introduced today by Sens. Kent Conrad, D-N.D.; Michael Enzi, R-Wyo.; and Jay Rockefeller, D-W.Va., is an important step toward expanding the use of captured carbon dioxide for enhanced oil recovery, a proven strategy that will boost domestic oil production, create jobs, spur economic growth, and reduce carbon emissions.
We applaud Senators Conrad, Enzi, and Rockefeller for introducing legislation to modify the existing Section 45Q Tax Credit for Carbon Dioxide Sequestration to enable its effective commercial use.
The bill reflects recommendations from the National Enhanced Oil Recovery Initiative (NEORI), a diverse coalition of stakeholders from industry, labor, state government, and environmental groups that was convened by C2ES and the Great Plains Institute. The proposed modifications to the 45Q tax credit are needed to advance important commercial CO2 capture projects now under development and to promote broader deployment of carbon capture utilization and storage technologies that will reduce the carbon footprint of fossil fuels.
We look forward to working with the Senators and others to see this bill enacted.
For more information, see NEORI’s 45Q recommendations and the NEORI participant list.
Contact Laura Rehrmann, 703-516-0621, firstname.lastname@example.org
I recently responded to a question on the National Journal blog, "How close is the United States to reaching the elusive goal of energy independence?"
You can read more on the original blog post and other responses here.
Here is my response:
- In the United States, petroleum is the largest energy source, accounting for 36 percent of all energy consumed in 2011 with the transportation sector accounting for over two-thirds of U.S. petroleum consumption.
- Correspondingly, petroleum is one of the largest sources of U.S. greenhouse gas emissions, accounting for around 32.3 percent of total U.S. greenhouse gas emissions in 2011.
- Globally, petroleum supplies 32.5 percent of global energy use and was responsible for 35.3 percent of global carbon dioxide emissions in 2011.
- The crude oil market is a global market. The United States has 1.9 percent of the world’s proved oil reserves, produces 13.7 percent of the world’s oil supply, and constitutes 20.7 percent of the world’s oil demand.
U.S. demand peaked in 2005 at 20.8 million barrels per day (b/d) and declined to 18.9 million b/d in 2013. Assuming current policites, consumption is expected to remain below the 2005 level until 2040.
Crude oil is an organic compound composed of hydrogen and carbon (i.e., a hydrocarbon). The hydrogen provides us with energy and the carbon is generally a waste product that is emitted into the air upon combustion. In order to be useful, crude oil must be refined through distillation and chemical processes. The refining process separates the hydrocarbon chains into different petroleum products. In addition to gasoline, some of the most common products are:
• Petroleum gas – like methane, butane and propane used for heating and cooking
• Kerosene – fuel for jet engines, tractors and some heaters
• Naphtha or Ligroin – an intermediate product used to make gasoline
• Gas oil or diesel distillate – diesel fuel and heating oil
• Lubricants – motor oil, and grease
• Residuals Products – coke, asphalt/tar, waxes
A typical 42 gallon barrel of crude oil (Figure 1) yields around 45 gallons of petroleum products; the 3-gallon refinery gain is due to the fact that the refined products have a lower density than crude oil.
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Figure 1. Products Made from a Barrel of Crude Oil
Source: U.S. Energy Information Administration, “Oil: Crude and Petroleum Products Explained.” 2012
Globally, transportation accounts for 62.3 percent of petroleum consumption. The remaining uses are non-energy related, including lubricants and asphalt production and use (16.8 percent); agriculture, commercial and public services, residential, and non-specified other (12 percent); and industry (8.9 percent). In the United States, transportation accounts for over two-thirds of U.S. petroleum consumption, with the remainder used by the industrial (25.1 percent), residential and commercial (4.5 percent), and electric power sector (0.6 percent).
Figure 2. U.S. Petroleum Consumption by Sector (2013)
As shown in Figure 3, light-duty vehicles – cars and pickup trucks – account for 58.6 percent of transportation petroleum consumption with the rest used by medium- and heavy-duty trucks (22 percent), airplanes (8 percent), and water transport, such as ships (4.5 percent).
Figure 3. U.S. Consumption of Transportation Energy, Petroleum (2012)
Petroleum, or crude oil, is formed from organic matter deposited millions of years ago. As the organic material decomposed, it mixed with other material like sand and silt and eventually formed sedimentary layers. Over time, heat and pressure from overlying rock layers in certain places forced the this organic material to move until it was trapped beneath less porous rock where it accumulated in what is known as oil reservoirs.
Generally, conventional oil resources refer to those that are most accessible and easiest to produce. Unconventional resources are less accessible and more difficult to produce. Examples of unconventional resources include shale oil, oil sands, and deep underwater resources. As known conventional supplies diminish and the price of oil rises, we are increasingly shifting to unconventional resources, and what was once unconventional is today becoming conventional. Note that the term “proven reserves” implies that the estimated quantities are deemed recoverable with reasonable certainty under existing economic and operating conditions.
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The combustion of petroleum emits a variety of pollutants – such as carbon dioxide, carbon monoxide, sulfur dioxide, nitrogen oxides, volatile organic compounds, and particulate matter. These pollutants are directly and indirectly linked to climate change, acid rain, and public health issues. As one of three fossil fuels, oil has less carbon content than coal, but more than natural gas. According to the U.S. Environmental Protection Agency’s 2014 U.S. Greenhouse Gas Inventory Report, CO2 emissions from petroleum accounted for 32.7 percent of total U.S. greenhouse gas emissions in 2012, ahead of coal (24.5 percent) and natural gas (20.8 percent). The transportation sector accounted for 79.8 percent of these CO2 emissions and the industrial sector (including refining) accounted for 12.5 percent. Within the transportation sector, gasoline and diesel contributed 88.1 percent of the CO2 emissions, 63.1 percent and 25 percent respectively. Petroleum refineries are one of the largest energy consumers in the industrial sector, accounting for about 2.7 percent of total U.S. GHG emission in 2012.
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Historically, the world oil market has been dominated by national oil companies, particularly through the exercise of market power by the Organization of Petroleum Exporting Countries. OPEC has 12 member countries: six in the Middle East, four in Africa and two in South America. OPEC accounts for around 73 percent of the world’s proven oil reserves.
Table 1. Top 20 Countries’ Crude Oil Reserves (Billion Barrels)
|7||United Arab Emirates*||5.9%||97.8|
Source: U.S. Energy Information Administration, International Energy Statistics, 2013
In recent years, global oil production and reserve estimates have become more geographically diversified with unconventional oil such as Canadian oil sands playing an increasingly important role. A shift is also taking place in global demand patterns, with consumption in Asia now exceeding consumption in North America. Over the last 30 years, global petroleum consumption has increased by 26 percent, and reserves have increased by 109 percent. Asian demand has surged by nearly 15 million barrels per day (Figure 4). The U.S. share of world oil demand, and consequently its market leverage, is declining as the rest of the world increases its demand.
Figure 4. World Petroleum Consumption by Region, 1980 – 2010
Source: U.S. Energy Information Administration, International Energy Statistics
U.S. domestic crude production is up because of tight oil – extraction of conventional light crude using the unconventional drilling technique known as hydraulic fracturing – and other unconventional supplies. In hydraulic fracturing, or “fracking” wells are drilled vertically and then turned horizontally to run within shale formations. A slurry of sand, water, and chemicals, together referred to as hydraulic fluid, is then injected into the well to increase pressure and break apart the shale so that the oil is released. Additionally, carbon dioxide injected into oil wells, known as carbon dioxide enhanced oil recovery, is helping to sustain oil production in otherwise declining oil fields and currently accounts for 6 percent of U.S. oil production; this practice is constrained by limited supplies of carbon dioxide.
At the same time, U.S. petroleum demand has fallen steadily since it peaked in 2005. Demand is not expected to exceed 2005 levels until after 2040, if at all, largely because of two key domestic policies: (1) renewable fuel standards requiring the displacement of petroleum-based gasoline with biofuels, and (2) new fuel economy standards for light-, medium-, and heavy-duty vehicles.
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Oil prices have historically been volatile and this is likely to continue due to supply disruptions motivated by world politics and shifts in global supply and demand. Because the oil market is global, any significant conventional oil find anywhere in the world or any technological breakthrough with regard to the recovery of unconventional oil sources that has the ability to meaningfully augment global supply, has the potential to push oil prices down. The prospects of finding a large conventional oil field within the United States are low, but off-shore (non-conventional) deep-water drilling in the Gulf of Mexico as well as on-land and off-shore regions in Northern Alaska hold the greatest potential. With a small amount of proven reserves relative to the global quantity, the United States is a price-taker. However, dramatic changes in U.S. consumption, as evidenced by the economic downturn in 2009 can affect world oil prices.
Figure 5. Crude Oil Spot Prices 1995 - 2014
By reducing its demand for oil, the United States can make itself more resilient to oil price shocks, and by increasing domestic production, the United States can reduce its trade deficit. The United States has numerous options for further reducing its oil demand, including additional tightening of fuel economy standards and shifting to alternative fuels (see our 2011 report: Reducing Greenhouse Gases from U.S. Transportation). Also, an estimated 35-50 billion barrels of economically recoverable oil could be produced in the United States using currently available enhanced oil recovery technologies and practices, or potentially more than twice the country’s proven reserves; enhanced oil recovery using carbon capture is the only domestic oil supply option that also decreases GHG emissions.
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Center Resources (Publications, blogs, BELC companies, Techbook entries)
- The Enhanced Oil Recovery (EOR) Initiative
- Greene & Plotkin (2011), Reducing Greenhouse Gas Emissions from U.S. Transportation
- Burbank & Nigro (2011), Saving Oil and Reducing Greenhouse Gas Emissions through U.S. Federal Transportation Policy
- Joel Bluestein (2010), Coverage of Greenhouse Gas Emissions from Petroleum Use under Climate Policy
External Resources (datasets, publications, websites); should be as recent as possible
- Environmental Protection Agency, “GHG Inventory Report, 1990-2010”
- International Energy Agency, "Oil Market Report"
- BP’s Statistical Review of World Energy 2011
- Shell’s Enhanced Oil Recovery webpage
- Congressional Research Service, “The U.S. Trade Deficit, the Dollar, and the Price of Oil,” J. Jackson, March 14, 2011
- EIA, “Oil: Crude and Petroleum Products Explained”
- Resources for the Future, “The Role of Oil in the U.S. Economy: Insights from a Veteran Observer,” Winter/Spring 2011
- In the United States, coal is the third largest primary energy source, accounting for 18 percent of all energy consumed in 2012 with the electric power sector accounting for 91 percent of U.S. coal consumption.
- Coal is still a major source of energy for U.S. electricity generation, but its role is declining in favor of natural gas and other energy sources due to low natural gas prices, state renewable energy standards and environmental regulations.
- With the highest carbon content of all the fossil fuels, carbon dioxide emissions from coal combustion represented 24.5 percent of total U.S. greenhouse gas emissions in 2012.
- Globally, coal is one of the most widely distributed energy resources with recoverable reserves in nearly 70 countries. The U.S., China, and India are the top producers and consumers of coal. Worldwide, coal supplies 29.7 percent of energy use and is responsible for 44 percent of global CO2 emissions.
- Most of the coal produced is consumed in the country in which it was mined. International trade accounts for only 16 percent of coal consumption worldwide; this share is expected to increase to 17 percent over the next 25 years.
- Compared to natural gas, the price of coal for electric power plants in the United States has remained relatively stable since the 1980s and expected to remain so over the next 25 years.
- Under potential climate policies, the development and success of low-emission technologies such as carbon capture and storage or other pollution control devices will be key in order to reduce the impact of continued to coal use.
In 2012, 91 percent of coal consumed in the U.S. was used for 37 percent of total U.S. electric power generation. The remaining 8 percent was consumed for industrial purposes, including steel and cement manufacturing. Worldwide, electric power generation was also the largest consumer of coal. In 2011, the electricity sector consumed 62 percent, while global industrial coal consumption was approximately 33 percent. The remaining 5 percent was used in the commercial and residential sectors.
Coal is a brownish to black sedimentary rock; it is formed under high temperature and pressure from plants and other organic matter that lived millions of years ago through a geologic process known as coalification. There are four main types of coal, classified according to the amount of available heat energy. The amount of carbon, hydrogen, and oxygen in the coal are the main factors that determine the amount of heat released during combustion. The carbon content determines the amount of CO2 emissions from each type of coal.
Table 1: Types of Coal and its Uses
Location of Deposits
% US Production (2010)
Black and brittle with a glassy appearance; usually the oldest type; sometimes called “hard coal”
Electric power, some space heating, industrial uses
Nearly 15,000 BTUs per pound
Softer than anthracite and sometimes called “soft coal”; low moisture content; 100 to 300 million years old
Most common type used for electric power, production of coke for steel industry
10,500- 14,500 BTUs per pound
East of the Mississippi; WV, KY and PA are top producers
Harder and darker than lignite; dates back at least 100 million years; lower sulfur content than bituminous coal
Electric power, industrial uses
8,300-13,000 BTUs per pound
West of the Mississippi; Wyoming is the top producer
Soft, crumbly and light-colored; relatively young; high moisture and ash content
Electric power, production of synthetic gas and liquids
4,000- 8,300 BTUs per pound
Mainly in Texas and North Dakota
Source: U.S. Energy Information Agency, “Coal Explained,” 2012
Bituminous coal is the most abundant type of coal in the United States and it is divided into two sub-types, according to end use. The first, steam or thermal coal, is used mainly for electricity generation, while the second, coking or metallurgical coal, is used in steel production. As a general rule, bituminous coal with its higher heat content coal is more desirable for electric power generation. Sub-bituminous coal from Wyoming’s Powder River Basin has a much lower sulfur content, which makes it an attractive fuel option because of regulatory limits on sulfur dioxide emissions.
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Depending on the geology of the coal formation, there are two main methods of extracting coal, surface and underground. Surface mining is used when coal is deposited less than 200 feet below the surface, while underground mines are suitable for coal formations several hundred feet below the earth. The recovery ratio of a coal deposit can be more than 90 percent for surface mines, while less than 40 percent for underground mines.
After the coal is mined, it is sent to a preparation plant for minimal processing and then transported to end-users through rail, barge, and/or truck. In the United States, rail is the primary mode of transportation for long-haul shipments of coal. Nearly all the coal mined in Wyoming, for instance, is sent via rail directly to power plants in the eastern United States. Trucks are used mainly for short hauls from mines to nearby electricity and industrial plants.
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A large number of environmental problems are associated with the production and combustion of coal. One significant impact is acid mine drainage, where acidic run-off is formed through a chemical reaction between water and sulfur-bearing rocks. This run-off contaminates creeks and rivers, and, because it diffuses easily, can be difficult to contain. Another significant impact is the practice of mountaintop mining. As the tops of mountains are removed to reveal coal seams, the sediment and waste becomes valley fill, impacting water quality and resulting in the loss of headwater ecosystems, or the species and environmental processes that are native to river sources. The U.S. Environmental Protection Agency uses the best-available science and incorporates feedback from the public and key stakeholders to provide guidance to protect water quality and people’s health regarding abandoned mines and mountaintop removal mining, among other things.
In terms of greenhouse gases, mining can result in the direct release of methane (which has a global warming potential 23 times higher than CO2, but only persists in the atmosphere for 12 – 17 years), particularly from underground mines. In 2012, methane emissions from U.S. coal mining were 0.9 percent of overall U.S. greenhouse gas emissions. The EPA estimates that coal mine methane contributes 8 – 10 percent of human-made methane emissions worldwide.
Table 2: Global Methane Emissions from Coal Mining
Surface mining %
Underground mining %
20 (NSW 59)
Source: U.S. Environmental Protection Agency, 2005
Carbon dioxide emissions from coal combustion for electric power and industry were responsible for 24.5 percent of total U.S. greenhouse gas emissions in 2012. Moreover, combustion emits common air pollutants, such as sulfur dioxide, nitrogen oxides, particulate matter, and mercury as well as other heavy metals. These air pollutants have adverse effects on both public health and the environment. Consequently, many but not all coal plants use a variety of technologies, such as scrubbers, to reduce most of the pollutants from combustion emissions. Some governments and companies are developing carbon capture and storage technologies that will capture, transport and store CO2 emissions underground. For more information, see Climate Techbook: Carbon Capture and Storage.
Additionally, coal combustion residuals, commonly referred to as coal ash, contain a broad range of metals, including arsenic, selenium and cadmium; however, the EPA considers the amounts of chemicals leached from these residuals to be non-hazardous. Coal combustion residuals are one of the largest waste streams generated in the United States, and must be managed to prevent environmental impacts such as the Kingston, Tennessee spill in 2008. Finally, considerable water usage for coal-fired power generation can stress aquifers and watersheds, and in many instances, water must be cooled to near ambient levels before being returned to the surroundings to protect ecosystems.
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The U.S. Energy Information Administration estimated global coal reserves at 980 billion short tons in 2011. At current consumption rates, these reserves are expected to last 113 years. The BP Statistical Review of World Energy gives similar numbers for global reserves.
Figure 1: McKelvy Diagram for Coal or Gas Resources
Source: McKelvy, V.E. 1972. “Mineral Resource Estimates and Public Policy.” American Scientist 60 (1): 32-40
Although coal deposits are distributed throughout the world, they are concentrated in the United States, Russia, China, and Australia.
Figure 2: Recoverable Coal Reserves by Country
For the United States, estimated recoverable reserves were 257 billion short tons as of January 1, 2013. Of this, recoverable reserves at producing mines were 18.7 billion tons; this reflects the working inventory at producing (active) mines.
Figure 3: Coal-Bearing Areas in the United States
Source: National Energy Technology Laboratory, 1983.
Domestic coal reserves are concentrated in several regions of the country. The majority of the estimated reserves are bituminous (53.1 percent), mainly found east of the Mississippi River. The next most common, sub-bituminous (36.6 percent) is found primary west of the Mississippi. Lignite deposits, which account for 8.8 percent of estimated reserves, are found in Montana, Texas, and North Dakota. Anthracite reserves are only about 1.5 percent and are concentrated in northeastern Pennsylvania.
In 2012, world coal production was 8,695 million short tons. China, the United States, and India are the top three coal producers. Since 1985, China has surpassed the United States in annual coal production. In 2012, China produced 4,025 million short tons of coal, nearly 4 times the amount of coal produced in the United States.
Since 1990, domestic coal production has ranged from a low of 945 million short tons in 1993 to a high of 1,171 million short tons in 2008. Coal production in 2012 has fallen around 13 percent from its 2008 peak. The recent lower trend obscures the fact that in some areas of the country, production has gone down even as it has gone up in other regions. In the Interior and Western regions, production increased, while production in the Appalachian Region continued to decrease, remaining at a near 50-year low. The top five coal producing states are:
- Wyoming (39 percent of U.S. total) is part of the Western region, producing 89 percent of the total amount of sub-bituminous coal in the United States.
- West Virginia (12 percent of U.S. total) is in the Appalachian region and produces only bituminous coal.
- Kentucky (9 percent) is split into two regions, both of which produce only bituminous coal.
- Pennsylvania (5 percent) is in the Appalachian region and the country's only producer of anthracite.
- Montana (5 percent) is in the Western region and produces only sub-bituminous coal.
There were approximately 1,229 mines in operation in the United States in 2012. The majority of these mines (60 percent) were surface mines and responsible for 66 percent of domestic coal production in 2012. Surface mining is much more prevalent in the western United States, where about 90 percent of the coal is extracted from surface mines.
Approximately 8,449 million short tons of coal were used worldwide in 2012. Three quarters of the world's coal is consumed by the top five users – China, United States, India, Germany, and Russia. As a region, Asia uses almost two thirds of global coal supplies. Coal usage accounts for approximately 29 percent of world energy consumption. Industrial consumers are responsible for about 33 percent of coal consumption worldwide, while the electricity sector uses about 62 percent.
In 2012, total coal consumption in the United States was 889.2 million short tons, which represented a decrease of approximately 21 percent from 2007. The electric power sector is the main driver of domestic coal consumption. Coal use (figure 5) has been declining due to a number of factors. First, the recession, which began in late 2007, reduced overall economic activity and the demand for coal in the electricity and industrial sector fell. In 2009, the economy began to grow again, albeit slowly. During this period, very low natural gas prices (which are expected to continue until at least the end of this decade), coupled with under-utilized generating capacity at efficient combined cycle power plants, made natural gas an economic fuel choice for baseload power in the U.S. electric power sector. That further eroded demand for coal. At the same time, EPA rules affecting coal plant emissions are coming into force, contributing to coal plant retirements. Finally, state energy portfolio standards have increased the quantity of available renewable power sources; wind now makes up approximately 4 percent of the annual electric generation mix in the U.S.
Figure 4. Recent Trend in U.S. Coal Consumption, 1990 – 2012
Figure 5. U.S. Coal Consumption, 1949 – 2013
Over the next 25 years, the EIA predicts that China will make up more than half of the world coal consumption. Increased use of coal in develpoping economies, including China, accounts for all of the projected growth in coal use until 2040, continuing a trend that began in the early 2000s (figure 6). Total coal production in developing economies of 176.8 quadrillion Btu in 2040 is expected to be more than four times higher than total coal production in developed nations.
Figure 6: Global Coal Consumption and Forecast, 1980-2040
Over the next 25 years, the EIA forecasts that coal use in the United States will increase 0.3 percent annually, from 2012 to 2040. Projected growth is due to increases in domestic coal consumption for use in power plants and for the production of synthetic fuels. However, the portion of electricity from coal-fired generation is predicted drop from 37 to 32 percent, due to increases in electricity generation from natural gas and renewables. Note that total electricity generation is forecast to increase 0.8 percent annually, from 2012 to 2040.
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Most coal is consumed in the country in which it was mined, with only about 15 percent of total overall coal consumption traded internationally in 2011. Coal trade is differentiated by the type of coal, either steam coal (used in power plants) or coking coal (used in industrial production). Historically, trade in steam coal has increased at an average rate of 7 percent per year over the past 20 years, and for coking coal, about 2 percent annually. U.S. coal exports, chiefly Central Appalachian coal, made up 9 percent of the global export market in 2012, up from 6.9 percent in 2010.
Table 3. Top Six Exporting and Importing Countries in 2012 (Million Short Tons)
Because transportation costs are a large share of the total coal price, international trade in coal is split into two main regions: the Atlantic, made up of Western Europe, and the Pacific, composed of importing countries in Asia, which accounts for the majority of world coal trade. These markets overlap when prices are high, with South Africa as a point of convergence between the two.
Figure 7: Inter-regional Coal Trade Flows (Metric Tons)
Indonesia is the world's largest exporter of steam coal, while Australia is the largest exporter of coking coal; most of their coal goes to Asia. Under forecast consumption rates, international coal trade is predicted to grow at an average annual rate of 1.4 percent over the next 25 years. Because the largest increases in consumption are forecast to occur in India and China, which meet most of the increase in their coal demand with domestic supply rather than imports, the share of coal trade as a percentage of global coal consumption grows modestly to 17 percent in 2035. Australia and Indonesia are expected to continue as the leading suppliers of coal over the next 25 years, while Asia is forecast to remain the largest importer of coal.
In its International Energy Outlook 2013, the EIA projects that total annual U.S. coal exports will rise from about 83 million short tons in 2010 to 169 million short tons in 2040 (from around 8 percent to 14 percent of U.S. annual production levels), buoyed by the increase in Asian and European coal demand. Because U.S. coal export facilities are located primarily in the east, the United States is currently at a distinct geographic disadvantage relative to Australia and Indonesia. Higher transportation costs associated with shipping coal from the eastern United States to Asian markets historically has meant that U.S. coal exports cannot compete economically in that region.
With strong growth in world coal trade, favorable international prices, and declining demand for coal in the U.S. electric power sector, there has been renewed activity and investment in port capacity expansion projects to facilitate the growth of U.S. coal exports.Some projects, particularly along the coastlines of Washington and Oregon face considerable local and environmental challenges. However, a number of projects on the U.S. Gulf coast are moving ahead and will add approximately 50 million tons of additional export capacity between 2012 and 2015.
The domestic price of coal is a function of supply and demand, coal type, and mining method used. Generally, lignite is the least expensive, and anthracite the most expensive. Surface-mined coal is usually lower in price than underground-mined.
Figure 8: U.S. Regional Coal Spot Prices
Transportation can be a significant portion of the delivered coal price. In 2010, transportation costs on average accounted for approximately 38 percent of the total delivered price to power plants in the United States. Compared to natural gas, the price of coal for electric power plants in the United States has remained relatively stable since the 1980s (with the notable exception of 2008, when many commodities spiked simultaneously).
Over the next 25 years, the average real minemouth price of domestic coal is expected to increase by 1.4 percent per year, from $1.98/MMBtu in 2012 to $2.96/MMBtu in 2040. In comparison, natural gas prices are expected to increase by approximately 3.7 percent per year.
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Because of its high-energy content, low cost per unit of energy, and abundant worldwide reserves, coal is the least-cost energy source for both developed and developing countries. Estimated worldwide reserves, if consumed at forecast consumption levels, are expected to last 120 years. Although supplies of coal are substantial, other factors may limit its use as an energy source.
In the United States, proposed and upcoming regulations by the EPA, as well as any future action on greenhouse gas emissions, will impact coal power plants and future coal markets. For example, in July 2011, the U.S. EPA issued guidance on water quality standards from surface coal mining in the Appalachian Region. Additionally, in February 2012 the agency published the mercury and air toxic standard rule, which is designed to reduce the emissions of harmful heavy metals as well as sulfur dioxide and fine particle pollution from power plants. Many electric generating units are already compliant with these rules; however, existing sources will have up to four years if they need it to comply. Also, the EPA in July 2011 issued the Cross-State Air Pollution Rule, which sets new standards for controls on power plants that cause much of the oxides from nitrogen and sulfur dioxide (which react and become ozone and fine particulate matter) that travel downwind and across state lines. Utilities have already announced the retirement of older, inefficient and infrequently used coal power plants in response to these rules. Additionally, in March 2012 the EPA released new performance standards for new electric power plants under the Clean Air Act. Under the proposed standard, all new power plants would need to match the greenhouse gas emissions performance currently achieved by highly efficient natural gas combined cycle power plants, that is, emit less than 1,100 pounds of CO2 per megawatt/hour. If implemented, this rule would effectively bar any new coal power plant from being built in the U.S. unless it implemented carbon capture and storage technology; even emissions from a state-of-the-art, integrated gasification combined cycle coal power plant are in excess of 1,600 pounds of CO2 per megawatt/hour.
Worldwide, coal use accounted for 44.3 percent of energy-related CO2 emissions in 2011. Reducing these emissions, in the context of increasing use in growing economies, will be a challenge. Development of low-carbon technologies and complementary government policies to drive the deployment of these technologies will be key factors enabling the use of coal in the future.
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- Climate Techbook: Carbon Capture and Storage
- Mercury and Air Toxic Standard (MATS) rule
- Cross-State Air Pollution Rule (CSAPR)
- New Source Performance Standards (NSPS) for emissions of CO2
External Resources (datasets, publications, websites);
- Environmental Protection Agency, “GHG Inventory Report, 1990-2010”
- IEA, “Key World Energy Statistics”
- EIA, “Coal Explained”
- EIA Annual Coal Report
- World Coal Association
- In the United States, renewable energy for electric power, transportation, industrial, residential and commercial purposes is the fastest-growing energy source, increasing 52 percent from 2000 to 2013 from 6.1 to 9.3 quadrillion British Thermal Units (Btus).
- In 2013, renewable energy was responsible for nearly 10 percent of total U.S. energy consumption (all sectors), up from a little more than 6 percent in 2005, due to strong growth in biomass (including biofuels) and wind power.
- In 2013, renewable energy was responsible for 12.9 percent of net U.S. electricity generation with hydroelectric generation contributing 6.6 percent and wind generation responsible for 4.1 percent of this total.
- Globally, renewable energy was responsible for approximately 22.1 percent of electricity generation with hydro generation accounting for 16.4 percent of the total in 2013.
- The U.S. Energy Information Agency projects that solar power will be the fastest-growing source of renewable energy in the United States with annual growth averaging 7.5 percent in the period from 2012 to 2040. In 2013, solar generation accounted for 1.8 percent of total renewable generation. In 2040, this is projected to climb to 10 percent.
- In 2013, renewable ethanol and biodiesel transportation fuels made up 21.5 percent of total U.S. renewable energy consumption, up from just 12 percent in 2006.
Renewable energy comes from sources that can be regenerated or naturally replenished. The main sources of renewable energy are:
Renewable energy is used for electric power generation, space heating and cooling, and transportation fuels. All sources of renewable energy are used to generate electric power. In addition to generating electricity, geothermal steam is used directly for heating and cooking. Biomass and solar sources are also used for space and water heating. Ethanol and biodiesel are the renewable transportation fuels with gaseous biomethane also fueling transport to a much lesser extent.
Renewable energy sources are considered to be zero (wind, solar, and water), low (geothermal) or neutral (biomass) with regard to greenhouse gas emissions during their operation. A neutral source has emissions that are balanced by the amount of carbon dioxide absorbed during the growing process. However, each source’s overall environmental impact depends on its overall lifecycle emissions, including manufacturing of equipment and materials, installation as well as land-use impacts.
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Water power captures the energy of flowing water in rivers, streams and waves to generate electricity. Conventional hydropower plants can be built in rivers with no water storage (known as “run-of-the-river” units) or in conjunction with reservoirs that store water, which can be used on an as-needed basis. As water travels downstream, it is channeled down through a pipe or other intake structure in a dam (penstock). The flowing water turns the blades of a turbine, generating electricity in the powerhouse, located at the base of the dam.
Figure 1. Hydroelectric Power Generation
Source: Environment Canada, 2012
Large conventional hydropower projects currently provide the majority of renewable electric power generation. With 1,000 gigawatts (GW) of global capacity, hydropower produced an estimated 3,750 terawatt hours (TWh) of total global electricity in 2013. Note that in 2013, total global electricity generation was 22,865 TWh. Hydropower operational costs are relatively low, and it generate little to no greenhouse gas emissions. The main environmental impact is to local ecosystems and habitats; a dam to create a reservoir or divert water to a hydropower plant changes the ecosystem and physical characteristic of the river.
The United States is the fourth-largest producer of hydropower after China, Canada and Brazil. In 2011, a much wetter than average year in the U.S. Northwest, the United States generated 7.9 percent of its total electricity from hydropower. The quantity of electricity generated each year depends on the amount of precipitation that falls over a particular area.
Small hydropower, generally less than 10 megawatts (MW), and micro-hydropower (less than 1 MW) are less costly to develop and have a lower environmental impact than large conventional hydropower projects. In 2011, the total amount of small hydro installed worldwide was 106 GW – China had the largest share at 55.3 percent, followed by India at 9 percent and the United States at 6.9 percent. Many countries have renewable energy targets that include the development of small hydro projects. In the United States, the Federal Energy Regulatory Commission (FERC) approved more than 50 project permits in 2009.
Hydrokinetic electric power, including wave and tidal power, is a form of unconventional hydropower that captures energy from waves or currents and does not require dam construction. These technologies are in various stages of research, development and deployment. In 2011, a 254 MW tidal power plant in South Korea began operation, doubling the global capacity to 527 MW.
Low-head hydro is a commercially available source of hydrokinetic electric power that has been used in farming areas for more than 100 years. Generally, the capacity of these devices is small, ranging from 1kW to 250kW.
Pumped storage hydropower plants use inexpensive electricity (typically overnight during periods of low demand) to pump water from a lower-lying storage reservoir to a storage reservoir located above the power house for later use during periods of peak electricity demand. Since this technology uses more electricity than it generates, it is not considered to be renewable energy. Note that it is economical to do this since the revenues that a generator receives during times of peak electricity generation far exceed the costs that they pay to pump the water during times of low electricity demand.
Figure 2. Pumped Storage Power Generation
Source: U.S. Geological Survey, 2012
Wind power harnesses the energy generated by the movement of air in the earth’s atmosphere to drive electricity-generating turbines. Although people have used wind power for hundreds of years, modern turbines reflect significant technological advances over early windmills and even over turbines from just 10 or 20 years ago. Generating electric power using wind turbines creates no greenhouse gases, but since a wind farm includes dozens or more turbines, widely-spaced, it requires thousands of acres of land. For example, Lone Star is a 200 MW wind farm located in Texas on approximately 36,000 acres.
After hydropower, wind was the next largest renewable energy source used for power generator with 318 GW of global capacity at the end of 2013, producing 2.9 percent of global electricity. Capacity is indicative of the maximum amount of electicity that can be generated when the wind is blowing at sufficient levels for a turbine. Because the wind is not always blowing, wind farms do not always produce as much as their capacity. With more than 91 MW, China had the largest installed capacity of wind generation in 2013, and the United States with 62 GW had the second-largest capacity; Texas, Iowa, California, Oklahoma and Illinois were the top five wind power producing states.
Average turbine size has been steadily increasing over the past 30 years. Today, new onshore turbines are typically in the range of 1.5 – 3.5 MW. The largest production models, designed for off-shore use, are capable of generating more than 7.5 MW; some innovative turbine models under development are expected to generate more than 15 MW in offshore projects in the coming years. Due to higher costs and technology constraints, off-shore capacity, approximately 3 GW in 2010, is only a small share of total installed wind generation capacity. For more information on wind power, see Climate TechBook: Wind.
Figure 3. Size and Power Evolution of Wind Turbines Over Time
Solar power harnesses the sun’s energy to produce electricity as well as solar heating and cooling. Solar energy resources are massive and widespread, and they can be harnessed anywhere that receives sunlight. The amount of solar radiation, also known as insolation, reaching the earth’s surface every hour is more than all the energy currently consumed by all human activities each year. A number of factors, including geographic location, time of day, and current weather conditions, all affect the amount of energy that can be harnessed for electricity production or heating purposes.
Solar energy can be captured for electricity production using solar photovoltaics and concentrating solar power. A solar or photovoltaic cell converts sunlight into electricity using the photoelectric effect. Typically, photovoltaic is found on the roofs of residential and commercial buildings. Concentrating solar power uses lenses or mirrors to concentrate sunlight into a narrow beam that heats a fluid, producing steam to drive a turbine which generates electricity. Concentrating solar power projects are larger-scale than residential or commercial PV and are often owned and operated by electric utilities.
Figure 4. Concentrating Solar Power
Source: NextEra Energy, 2012
Solar hot water heaters, typically found on the roofs of homes and apartments, provide residential hot water by using a solar collector, which absorbs solar energy, that in turn heats a conductive fluid, and transfers the heat to a water tank. Modern collectors are designed to be functional even in cold climates and on overcast days.
Electricity generated from solar energy emits no greenhouse gases. The main environmental impacts of solar energy come from the use of some hazardous materials (arsenic and cadmium) in the manufacturing of PV and the large amount of land required, hundreds of acres, for a utility-scale solar project. For more information on solar energy, see Climate TechBook: Solar.
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Biomass energy sources are used to generate electricity, provide direct heating and can be converted into biofuels as a direct substitute for fossil fuels used in transportation. Unlike intermittent wind and solar energy, biomass can be used continuously or according to a schedule. Biomass is derived from wood, waste, landfill gas, crops and alcohol fuels. Traditional biomass, including waste wood, charcoal and manure has been a source of energy for domestic cooking and heating throughout human history. In rural areas of the developing world, it remains the dominant fuel source. Globally in 2010, traditional biomass accounted for about 8.5 percent of total energy consumption. The growing use of biomass has resulted in increasing international trade in biomass fuels in recent years; wood pellets, biodiesel, and ethanol are the main fuels traded internationally.
In 2013, global biomass electric power capacity stood at 88 GW. In 2011, the United States had 11.5 GW of installed biomass-fueled electric generation capacity. In the United States, most of the electricity from wood biomass is generated at lumber and paper mills using their own wood waste; in addition, wood waste is used to generate the heat for drying wood products and other manufacturing processes. Biomass waste is mostly municipal solid waste, i.e., garbage, which is burned as a fuel to run power plants. On average, a ton of garbage generates 550 to 750 kWh of electricity. Landfill gas contains methane that can be captured, processed and used to fuel power plants, manufacturing facilities, vehicles and homes. In the United States, there is currently nearly 2 GW of installed landfill gas-fired generation capacity at more than 600 projects.
In addition to landfill gas, biofuels can be synthesized from dedicated crops, trees and grasses, agricultural waste and algae feedstock; these include renewable forms of diesel, ethanol, butanol, methane and other hydrocarbons. Corn ethanol is the most widely used biofuel in the United States. Roughly 40 percent of the U.S. corn crop was diverted to the production of ethanol for gasoline in 2010, up from 20 percent in 2006. Gasoline with up to 10 percent ethanol (E10) can be used in most vehicles without further modification, while special flexible fuel vehicles can use a gasoline-ethanol blend that has up to 85 percent ethanol (E85).
Closed-loop biomass ,where power is generated using feedstocks grown specifically for the purpose of energy production, is generally considered to be carbon dioxide neutral because the carbon dioxide emitted during combustion of the fuel was previously captured during the growth of the feedstock. While biomass can avoid the use of fossil fuels, the net effect of biopower and biofuels on greenhouse gas emissions will depend on full lifecycle emissions for the biomass source, how it is used, and indirect land-use effects. For more information, see Climate Techbook: Biofuels and Biopower. Overall, however, biomass energy can have varying impacts on the environment. Wood biomass, for example, contains sulfur and nitrogen, which yield air pollutants sulfur dioxide and nitrogen oxides, though in much lower quantities than coal combustion.
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Traditional geothermal energy exploits naturally occurring high temperatures, located relatively close to the surface of the earth in some areas, to generate electric power and for direct uses such as heating and cooking. Geothermal areas are generally located near tectonic plate boundaries, where there are earthquakes and volcanoes. In some places, hot springs and geysers naturally rise to the surface. These have been used for bathing, cooking and heating for centuries. At least 78 countries used direct geothermal power in 2011.
Generating geothermal electric power typically involves the drilling of well, perhaps a mile or two in depth, in search of rock temperatures in the range of 300 to 700°F. Water is pumped down this well, where it is reheated by hot rocks. It travels through natural fissures and rises up a second well as steam, which can be used to spin a turbine and generate electricity or it can be used for heating or other purposes. Note that drilling a suitable injection well is by no means a certain task; several wells may have to be drilled before a suitable one is in place and the size of the resource cannot be confirmed until after the drilling takes place. Additionally, some water is lost to evaporation in this process, so new water is added to maintain the continuous flow of steam. Like biopower and unlike intermittent wind and solar power, geothermal electricity can be used continuously. Note that very small quantities of carbon dioxide trapped below the earth’s surface are released during this process.
Figure 5. Geothermal Power Station
Source: BBC Science
Globally, geothermal provided an estimated 205 TWh in 2011, one third in the form of electricity (with an estimated 11.2 GW of capacity) and the remaining two-thirds in the form of heat. Note that in 2009, total global electricity generation was 18,979 TWh. In 2011, the 16.7 billion kWh of geothermal electricity generated in the United States constituted 8.6 percent of the non-hydroelectric, renewable electricity generation, but only 0.4 percent of total electricity generation. The same year, five states generated electricity from geothermal energy , California, Hawaii, Idaho, Nevada and Utah. Of these, California accounted for 80 percent of this generation. For more information, see Climate TechBook: Geothermal.
Enhanced geothermal systems use advanced, often experimental drilling and fluid injection techniques to augment and expand the availability of geothermal resources. They are being studied by the U.S. Department of Energy. For more on this topic (see Climate TechBook: Enhanced Geothermal Systems).
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Figure 6. Renewable Energy Indicators 2013
There are several factors that determine which renewable technologies are adopted. These include market drivers (cost, diversity, proximity to demand or transmission, resource availability, and others), policy decisions (tax credits and renewable portfolio standards) as well as specific regulations. At least 144 countries, more than half of which are developing, had renewable energy policy targets in place by the end of 2013.
U.S. Electricity Sector
All renewable energy sources are used to generate electric power. When selecting new electricity capacity additions utility planners often look at levelized costs as a convenient summary measure of the overall competitiveness of different technologies. Total system levelized costs here (Figure 7) do not include policy-related factors like tax credits, and assumptions about future fuel prices and financing costs in particular can significantly affect these cost projections. Also, dispatchable technologies, i.e., those that can be controlled by an operator, are more desirable than non-dispatchable or intermittent technologies.
Table 1. U.S. Average Levelized Costs (2012 $/MWh) for Plants Entering Service in 2019
Capacity Factor (%)
Levelized Capital Cost
Variable O&M (Including fuel)
Total System Levelized Cost
Integrated Coal-Gasification Combined Cycle (IGCC)
IGCC with Carbon Capture & Storage (CCS)
Conventional Combined Cycle (CC)
Advanced CC with CCS
Conventional Combustion Turbine (CT)
Source: U.S. Energy Information Agency Annual Energy Outlook. April 2014
In the absence of policy mandates and incentives, a utility planner would be inclined to select the least-cost, dispatchable generation technology, which today is a natural gas-fired combined cycle. Additionally, planners often consider the mix or diversity of the generation under their control, so as to minimize exposure to any one particular technology. Also, planners must consider the environmental impacts and regulatory rules, e.g. land and water use, ecosystems, wild-life impacts and pollution mitigation.
An renewable portfollio standard is a state mandate, which specifies that electric utilities deliver a certain amount of electricity from renewable or alternative energy sources by a given date. State standards range from modest to ambitious, and qualifying energy sources vary. Some states also include "carve-outs" (requirements that a certain percentage of the portfolio be generated from a specific energy source, such as solar power) or other incentives to encourage the development of particular resources. Although climate change may not be the prime motivation behind these standards, the use of renewable or alternative energy can deliver significant greenhouse gas reductions. Increasing a state’s use of renewable energy brings other benefits as well, including job creation, energy security, and cleaner air. Most states allow utilities to comply with the renewable portfolio standard through tradeable credits. These credits can be sold in addition to the electricity generated to gain additional revenues for the utilities.
In states where a renewable portfolio standard exists, utilities must consider renewable technologies that satisfy this requirement. Cost is typically a key driver of the selected technology, but intermittency and resource availability have to be taken into account. In the case of wind, it is a lower-cost renewable technology, but it is intermittent, i.e., the wind is not always blowing hard enough to generate electricity. Moreover, many onshore locations in the United States (Figure 8), particularly in the east and south are not well-suited for wind generation. In these areas, many counties have biomass resources (Figure 10) greater than 55,000 tons/year. Since biomass is not an intermittent resource (Figure 7), it might be an attractive option to meet a renewable portfolio standard requirement. Note that roughly 25,000 to 45,000 tons of biomass is needed to support 5 MW of generation for one year at 70 percent utilization rate (~30,000 MWh/year), depending on the condition and type of biomass. Note also that wind’s intermittency issue can be lessened to an extent by grid connecting individual wind farms from many geographically diverse areas, so if the wind is not blowing in one area, it is likely blowing in others.
At the federal level, there are two tax credits that have served to encourage the adoption of renewable energy sources: the production tax credit and the investment tax credit. First enacted in 1992 and subsequently amended, the production tax credit is a corporate tax credit available to a wide range of renewable technologies including wind, landfill gas, geothermal and small hydroelectric. For wind, geothermal and closed-loop biomass, the utility receives a 2.2 ¢/kWh ($22/MWh) credit for all electricity generated during the first 10 years of operation. For wind, with an average total system levelized cost of $96/MWh (Figure 7), the production tax credit represents a 23 percent cost reduction. The investment tax credit is earned when qualifying equipment, including solar hot water, photovoltaics, small wind turbines, is placed into service. The credit functions to reduce installation costs and shorten the payback time of these technologies. In addition to these federal incentives, states offer added incentives, making renewables even easier to implement from a cost perspective.
U.S. Transportation Sector
Biofuels have been gaining attention as a way to lessen dependence on petroleum-based fuels and reduce greenhouse gas emissions. To that end, the United States has adopted a renewable fuel standard.
The Energy Policy Act of 2005 created a Renewable Fuel Standard in the United States that required 2.78 percent of gasoline consumed in the U.S. in 2006 to be renewable fuel. With the Energy Independence and Security Act of 2007, Congress created a new Renewable Fuel Standard, which increased the required volumes of renewable fuel to 36 billion gallons by 2022 or about 7 percent of expected annual gasoline and diesel consumption above a business-as-usual scenario. For more information, see the C2ES overview: Renewable Fuel Standard.
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Renewable resource availability and location are key considerations in the adoption of renewable energy sources.
Idaho National Laboratory recently estimated that there is approximately 83 GW of mostly small hydropower available in the U.S. Pacific Northwest. While the DOE found that the untapped generation potential at existing dams in the United States that were designed for purposes other than power production, i.e., water supply and inland navigation represents 12 GW, roughly 15 percent of the current hydropower capacity.
The following maps from the DOE National Renewable Energy Laboratory depict the relative availability of renewable energy resources throughout the United States.
- Wind resources (Figure 7) are abundant in the Great Plains, Iowa, Minnesota, along the spine of Apalachian Mountains, in the Western Mountains and many off-shore locations.
- Solar photovoltaic (Figure 8) and concentrating solar power resources are the highest in the desert Southwest and diminish in intensity in a northward direction.
- The best biomass resources (Figure 9) are in the upper central plains (corn) and forests of the Pacific Northwest.
- Traditional geothermal resources (Figure 10) are concentrated in the Western United States.
Figure 7. U.S. Wind Resource Map
Source: U.S. National Renewable Energy Laboratories, 2009.
Figure 8. U.S. Photovoltaic Solar Resources
Source: U.S. National Renewable Energy Laboratories, 2008.
Figure 9. U.S. Biomass Resource
Source: U.S. National Renewable Energy Laboratories, 2008
Figure 10. U.S. Geothermal Resource
Globally, 19 percent of world energy came from renewable sources in 2012. A little less than one half of this was from traditional biomass sources used in residential heating and cooking in developing countries. In 2013, renewable energy accounted for 10 percent of total U.S. energy use (9.3 quadrillion Btu out of a total of 97.5 quadrillion Btu). In the United States, renewable energy is used across economic sectors (Figure 11).
Figure 11. U.S. Sector Demand for Renewable Energy
Renewable energy sources made up 12.9 percent of total electricity generation in 2013; hydro, wind and biomass made up the majority of U.S. renewable electricity generation (Figure 12). In the industrial sector, biomass makes up 98 percent of the renewable energy use with nearly 60 percent derived from biomass wood, 33 percent from biofuels, and nearly 8 percent from biomass waste.
Figure 12. U.S. Renewable Electricity Generation (2013)
Source: U.S. Energy Information Administration, 2014.
World energy consumption is expected to grow 56 percent to 820 quadrillion Btus from 2010 to 2040 with most of this growth coming from developing countries (Figure 13). Renewables are projected to be the fastest-growing source of energy with consumption of hydroelectricity and other renewables set to increase from 11 percent of total energy consumption in 2010 to 15 percent in 2040.
Figure 13. Projected Total Global Energy Consumption
Renewable energy’s share of global electricity generation is forecast to increase from 21 percent to 25 percent; hydroelectric power is expected to contribute 52 percent of added renewable generation and wind is expected to contribute 28 percent. Large hydro projects are being constructed and planned in China, Canada and Brazil among others. According to the International Energy Agency, the development and market deployment of renewable energy technologies will depend heavily on government policies to make renewable energy cost-competitive.
In the United States over the next 25 years, non-hydro renewable energy consumption, excluding ethanol and biomass, is expected to grow at an average annual rate of 2.5 percent, higher than the overall growth rate in energy consumption (0.4 percent per year), under a business-as-usual scenario. E85 (ethanol transportation fuel) is expected to be the fastest growing renewable energy type, growing at an average annual rate of 11.9 percent over the same period, but it starts from a very low base. For renewable electricity sources, solar is expected to grow the most rapidly, followed by wood and other biomass. Uncertainty about federal tax credits, fuel prices and economic growth will influence the pace of renewable energy source development.
- Renewable & Alternative Energy Portfolio Standards
- Climate Techbook:
- Renewable Fuel Standard
- Renewable Energy Policy Network for the 21st Century REN21
- EIA’s Renewable & Alternative Fuels
- INL’s Assessment of Natural Stream Sites for Hydroelectric Dams in the Pacific Northwest Region
- DOE’s An Assessment of Energy Potential at Non-Powered Dams in the United States
- IRS’s Production Tax Credit, Investment Tax Credit
- WRI’s Renewable Energy Credits Factsheet
- Hydro Green Energy
- Natural gas plays an important role in nearly every sector of the U.S. economy, constituting 27 percent of primary energy consumption (second only to oil) and slightly more than 27 percent of electricity generation in 2013.
- Combustion of natural gas emits about half as much carbon dioxide as coal and 30 percent less than oil, and far fewer pollutants, per unit of energy delivered.
- Natural gas combustion is responsible for approximately 21 percent of U.S. greenhouse gas emissions annually; venting and other fugitive methane releases from natural gas systems produced around 2 percent of total emissions.
- Globally, natural gas combustion accounted for 20.2 percent of the world’s CO2 emissions from fossil fuels in 2011.
- The United States has enough natural gas to last nearly 85 years at current consumption rates (about 26.0 trillion cubic feet (Tcf) per year); the U.S. Energy Information Administration estimates technically recoverable reserves in excess of 2,200 Tcf.
Figure 1. Geological Formations Bearing Natural Gas
Natural gas is a naturally occurring fossil fuel consisting primarily of methane and small amounts of impurities such as carbon dioxide. It may also contain heavier liquids (also known as natural gas liquids) that can be processed into valuable byproducts including ethane, propane, butane and pentane. As illustrated in the above graphic, natural gas is found in several different types of geologic formations. Historically, natural gas has been conventionally extracted from large reservoirs and often produced in conjunction with oil. Technological advances in the areas of horizontal drilling and hydraulic fracturing have made it easier and cheaper to obtain gas from smaller unconventional sources including non-porous sand (tight sands), coal seams (coal bed methane) and most recently from very fine grained sedimentary rock called shale (shale gas), known in the industry as shale plays.
Shale gas extraction differs significantly from the conventional extraction methods. Wells are drilled vertically and then turned horizontally to run within shale formations. A slurry of sand, water, and chemicals, together referred to as hydraulic fluid, is then injected into the well to increase pressure and break apart the shale so that the gas is released. This technique is known as hydraulic fracturing or “fracking.”
An assessment of 137 shale gas basins in 41 countries suggest that shale gas resources, which have recently provided a major boost to U.S. natural gas production, are also available in other world regions. The 2013 study reported 6.634 Tcf of technically recoverable shale gas resources in 41 foreign countries, compared with 665 Tcf in the United States.
Figure 2. Global Natural Gas Basins
Natural gas is used extensively in the United States, for generating electricity, for space and water heating in residential and commercial buildings, and as industrial feedstock, providing the base ingredient for such varied products as plastic, fertilizer, anti-freeze and fabrics.
Figure 3. U.S. Natural Gas Consumption by Sector
In the residential buildings sector, almost 95 percent of natural gas is used for space and water heating, with cooking and clothes drying making up the remainder. In the commercial buildings sector, space and water heating comprise the majority of natural gas use (63 percent), but other uses – including cogeneration (the use of natural gas to generate electricity and useful heat), also known as combined heat and power – compose one-third of natural gas usage. Chemicals and petroleum products, which includes refining, account for the largest shares of natural gas consumption in energy industries.
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Compared to other fossil fuels, natural gas is considered relatively “clean” because when it is burned it releases fewer harmful pollutants. Compared to coal or oil, natural gas combustion releases smaller quantities of particulate matter, nitrogen oxides, and sulfur dioxide. The combustion of natural gas also emits about half as much carbon dioxide as coal. However, methane itself is a potent GHG, more than 20 times more powerful in terms of its heat-trapping ability than CO2, though it is shorter lived in the atmosphere. Sources of methane emissions include landfills and coal mines as well as digestion by cows and other ruminant animals. Emissions from equipment leaks, process venting and disposal of waste gas streams are known as fugitive emissions.
Table 1: Fossil Fuel Emissions Levels (Pounds per Billion Btu of Energy Input)
Source: U.S. Energy Information Administration, Natural Gas Issues and Trends (1998)
Currently, natural gas combustion-related emissions account for about 21 percent of total U.S. greenhouse gas emissions, while fugitive methane releases from natural gas systems (production, processing, transmission, storage, and distribution) represent 2 percent of the total. Globally, natural gas combustion accounted for 20.2 percent of the world’s CO2 emissions in 2011.
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Since 2000, U.S. proved reserves of natural gas have increased more than 80 percent, driven mostly by shale gas advancements. As a result, in 2013 the United States had the fourth largest proved reserves of natural gas in the world, at 308 Tcf. Russia had the largest reserves at 1,688 Tcf, followed by Iran at 1,187 Tcf, and Qatar at 890 Tcf.
As at the end of 2012, the Potential Gas Committee estimated that the total assessed U.S. shale gas resource was 1,073 Tcf. This represented approximately 48 percent of the United States' total traditional gas resource of 2,225 Tcf. Total technically recoverable resources, which also include coalbed gas resource of 158 Tcf, were 2,384 Tcf. This represents an increase of around 25 percent from the previous assessment in 2010.
Natural Gas Production
Total domestic dry natural gas production in 2013 was 24.3 Tcf. This figure represents the remainder from a total gross withdrawal of 30.2 Tcf of product, after venting and flaring, removal of non-hydrocarbon gases such as CO2, removal of natural gas liquids and other losses. From 2007 to 2012, shale gas production grew at an annual rate of nearly 52 percent. Natural gas is produced in 33 states and in the Gulf of Mexico. According to the EIA, Texas, the Gulf of Mexico, Pennsylvania, Wyoming, Louisiana, Oklahoma, Colorado and New Mexico account for 83.3 percent of U.S. production in 2012. The geography of U.S. natural gas production is changing with an increasing percentage of production coming from other states like Pennsylvania and Arkansas. From 2010 to 2012, natural gas production increased fourfold in Pennsylvania; the state was responsible for more than 9 percent of U.S. production in 2012.
Development of fracking technology has created the present boom in natural gas production. This technology was initially funded in the 1970s through the U.S. Department of Energy and with more than 20 years of federal tax credits (1980 – 2002).
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Figure 4. U.S. Shale Plays
The U.S. natural gas pipeline network is a highly integrated transmission and distribution grid that can transport natural gas to and from nearly any location in the contiguous 48 states. Interstate and intrastate pipelines deliver natural gas to local distribution companies, directly to some large industrial end users and electricity generators, and to interconnections with other pipelines. The network consists of more than 210 pipeline systems with nearly 306,000 miles of pipe, and 1,400 compressor stations that maintain network pressure and assure continuous forward movement of supplies. To support the seasonal peaking demand of natural gas, there are 414 underground natural gas storage facilities in the pipeline network for additional winter heating demand. There are three types of underground storage facilities: depleted natural gas or oil fields, aquifers and salt caverns. Additionally, there are 49 locations where natural gas can be imported or exported at the Canadian and Mexican borders. In response to earlier expectations of natural gas import needs, there are eight liquefied natural gas (LNG) import facilities in the United States, which are now underused. With the recent increase in domestic natural gas production, the U.S. Federal Energy Regulatory Commission (FERC) has authorized three export terminals. One terminal in Sabine, LA is under construction and is expected to begin operations before 2017, while the others in Hackberry, LA and Freeport, TX are not yet under construction. There are dozens of other proposed and potential terminals that are in various stages of the permitting process.
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Natural gas consumption made up a little more than 24 percent of total global energy use in 2013. The EIA estimated that world natural gas demand climbed to 120 Tcf in 2012, up 3.1 percent from 2011. According to the International Energy Agency, electric power generation remains the main driver behind global natural gas demand growth.
Natural gas use constituted about 27 percent of total U.S. primary energy consumption in 2013. Total U.S. natural gas consumption grew from 23.3 Tcf in 2000 to 26.0 Tcf in 2013. A decline in annual consumption in the industrial sector during this earlier portion of this period has almost been erased, while growth in the electric power sector continues - this sector grew at an annual average rate of 3.5 percent.
Figure 5. U.S. Natural Gas Consumption by Sector, 2000 – 2013 (Tcf)
In 2013, natural gas fueled 27.4 percent of total U.S. electricity generation. From 2000 to 2013, natural gas electricity generation grew at a faster rate than total electricity generation (4.9 percent per year versus 0.5 percent per year). This growth can be attributed to a number of factors, including low natural gas prices in the early part of the decade. Additionally, gas-fired plants are relatively easy to construct, have lower emissions compared to other fossil fuels, and have lower capital costs and shorter construction times compared to coal power plants. More information about natural gas fired electricity generation can be found on the Center’s Natural Gas Techbook page.
The market for natural gas is similar to other commodities. Generally, when demand goes up, producers respond with increased exploration, drilling and production. However, significant supply increases do not happen overnight. It takes time to study the geology, acquire leases, drill wells and connect to pipelines (or build new pipelines). This expansion can take many months or years. As a result, there is often a lag in bringing new supply to market, which can cause price volatility and spikes. Conversely, oversupply (or expectations of low price), result in less exploration. Even with a lower price, many producers are reluctant to halt extraction due to the geologic characteristics of wells that make it difficult to stop and restart production. In addition, since gas is often produced along with oil or natural gas liquids, stopping the flow of natural gas means stopping the flow of oil and natural gas liquids, which may not make financial sense. Another market driver is that gas is often sold on a contractual basis, and a producer may be legally bound to produce a specific quantity of natural gas.
Natural gas markets across the world are segmented, that is, natural gas pipeline systems connect distinct regions of the world, for example, the United States is connected to Canada and Mexico while the United Kingdom is connected to the North Sea and Europe. Natural gas prices are determined within these regional markets based on the available regional supply and demand patterns. A general upward trend in world natural gas prices began in the early 2000s as demand for the product began to exceed supply. Following the global recession of 2008 – 2009 a fairly wide spread in world natural gas prices developed (Figure 6).
Figure 6: World Natural Gas Prices (USD/MMBtu)
Prices in the U.S. and Canadian markets have plummeted due to the abundant supply of North American shale gas. Asian markets have seen higher gas prices due to increasing demand in China, South Korea and Japan. Europe has also seen higher prices as a result of increased demand as well as periodic Russian supply disruptions from 2005 – 2009.
Supply and demand responses, the seasonal nature of demand (residential winter heating or summer cooling through increased electric power generation requirements), or cold weather and hurricane-driven supply disruptions, have all contributed to natural gas price volatility in the United States in the last decade (Figure 7). In 2001, several years of declining productive capacity and increasing demand resulted in a sharp winter price spike. Prices spiked again in 2005 in the wake of hurricanes Rita and Katrina, which temporarily curtailed supplies from the Gulf of Mexico. Prices remained high relative to historic norms, peaking along with other energy commodities in 2008. Since then, average annual wellhead prices in the U.S. have gone down. Two factors – an abundance of shale gas and the slow pace of economic recovery following the recession – have contributed to sustained low prices.
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Figure 7: U.S. Natural Gas Monthly Average Wellhead Prices (USD/MMBtu)
While most of the world’s gas supply is transported regionally via pipeline, global gas trade has accelerated with the growing use of liquefied natural gas. To maximize the quantity of natural gas that can be transported, the gas is liquefied at an export facility. First, the liquefaction process involves the removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons. Then, the natural gas is condensed into a liquid by cooling it to approximately -162°C (-260 °F). Liquefied natural gas (LNG) takes up 1/600th the volume of natural gas in the gaseous state. Once liquefied, the LNG can be transported by tanker and regasified for use in other markets at an LNG import terminal. Between 2005 and 2011, the liquefied natural gas market grew by more than 70 percent, but the volume of LNG trade has been relatively flat for the past 3 years (2011 to 2013) at around 240 million metric tons (MT) (approximately 11 Tcf). In 2013, Japan was responsible for 37 percent of global LNG imports; its nuclear fleet has been temporarily shutdown as a result of the Fukushima disaster, and it is relying much more heavily on natural gas for its energy consumption. Global gas liquefaction capacity was 290.7 MT in 2013, and is expected to increase more than 100 MT by 2018 with Australia adding 62 MT and poised to become the world's largest exporter.
With surplus domestic supply and substantially higher prices in other regional markets, several U.S. companies have applied to the relevant agencies for permission to export liquefied natural gas with Houston-based Cheniere Energy being the first company to win approval for its Sabine Pass facility in 2012, followed by Freeport LNG and Cameron LNG.
Prospects for U.S. liquefied natural gas exports depend significantly on the cost-competitiveness of U.S. liquefaction projects relative to those at other locations. Over much of the last decade, lower supply expectations and higher, volatile prices prompted new investments in U.S. natural gas import and storage infrastructure. Since 2000, North America’s import capacity has expanded from approximately 2.3 Bcf/day to 22.7 Bcf/day, around 35 percent of the United States’ average daily requirement. Yet as of 2009, U.S. consumption of imported liquefied natural gas was less than 0.3 Bcf/day, leaving most of this capacity unused. The ability to use and repurpose existing U.S. import infrastructure—pipelines, processing plants, storage and loading facilities—will help reduce total costs relative to new facilities. While liquefied natural gas makes up a small portion of U.S. imports, it is important in other parts of the world. The majority of the gas trade in the Asia Pacific region is in the form of LNG imports to Japan, South Korea, China, India and Taiwan from Qatar, Malaysia, Australia, and Indonesia (Figure 8).
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Figure 8: Major International Natural Gas Trade Flows (Billion Cubic Meters)
According to the EIA’s International Energy Outlook, natural gas is expected to be the world’s fastest growing fossil fuel, with consumption increasing at an average rate of 1.5 percent per year to 2040. Growth in natural gas is expected to occur in every region and is most concentrated in developing countries, where demand increases more than twice as fast as in developed countries.
In the United States, shale gas production is expected to more than double over the next 25 years (Figure 9), and production of natural gas is expected to exceed consumption before 2020. As a consequence, the EIA in its 2014 Annual Energy Outlook Reference Scenario expects U.S. natural gas prices to remain below $5/MMBtu through at least the early 2020s.
Figure 9. U.S. Natural Gas Production, 1990 – 2040 (Tcf)
The forecast of an abundance of domestic natural gas, coupled with recent regulatory actions taken by the U.S. Environmental Protection Agency (EPA) with regard to the electric power sector (Mercury rule, Cross-State Air Pollution Rule, and New Source Performance Standard for CO2 from new power plants) have led to natural gas becoming the dominant choice for planned electricity generating capacity. Moreover, the abundance of natural gas has somewhat mitigated industrial concerns about using the fuel as a feedstock to manufacture products such as plastics and fertilizers.
The rapid growth of shale gas has also increased scrutiny of the potential environmental and health effects of hydraulic fracturing. As a result, several states have taken action either to regulate hydraulic fracturing or to issue a temporary moratorium while they explore the issue further. In addition to state action, the U.S. Department of Interior proposed new rules for regulating natural gas drilling on federal lands in 2012, and the EPA has undertaken a Hydraulic Fracturing Study Plan to study the relationship between hydraulic fracturing and drinking water.
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- Natural Gas Initiative:
- Climate Techbook: Natural Gas.
- Bluestein, Joel (2008). Coverage of Natural Gas Emissions & Flows Under a GHG Cap-and-Trade Program, Pew Center on Global Climate Change.
- Claussen, Eileen. Climate Policy and Natural Gas: A Bridge to a Lower GHG Future. 2008 October 6. American Gas Association Executive Conference.
- BP’s Statistical Review of World Energy 2011
- Shell’s Natural Gas
- BPC’s Task Force on Ensuring Stable Natural Gas Markets. 2011 March 22.
- Ratner, Michael. Global Natural Gas: A Growing Resource. Congressional Research Service (CRS). R41543. 2010 December 22.
- EIA’s Natural Gas Overview
- FracFocus Chemical Disclosure Registry
- RFF’s Abundant Shale Gas Resources: Long-Term Implications for U.S. Natural Gas Markets. RFF Discussion Paper 10-41. 2010 August.
- IEA’s Natural Gas Overview
- MIT’s The Future of Natural Gas. 2011 July.
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