Drought is a natural hazard with potentially significant societal, economic, and environmental consequences. Public policy issues related to drought range from how to identify and measure drought to how best to prepare for, respond to, and mitigate drought impacts, and who should bear such costs. This report provides information relevant to drought policy discussions by describing the physical causes of drought, drought history in the United States, examples of regional drought conditions, and policy challenges related to drought. What is drought? Drought is commonly defined as a lack of precipitation over an extended period of time, usually a season or more, relative to some long-term average condition. While the technology and science to predict droughts have improved, regional predictions remain limited to a few months in advance. History suggests that severe and extended droughts are inevitable and part of natural climate cycles. What causes drought? The physical conditions causing drought in the United States are increasingly understood to be linked to sea surface temperatures (SSTs) in the tropical Pacific Ocean. Studies indicate that cooler-than-average SSTs have been connected to the severe western drought in the first decade of the 21st century, severe droughts of the late 19th century, and precolonial North American "megadroughts." The 2011 severe drought in Texas is thought to be linked to La Nina conditions in the Pacific Ocean. What is the future of drought in the United States? The prospect of extended droughts and more arid baseline conditions in parts of the United States could suggest new challenges to federal water projects, which were constructed largely on the basis of 20th century climate conditions. Some studies suggest that the American West may be transitioning to a more arid climate, possibly resulting from the buildup of greenhouse gases in the atmosphere, raising concerns that the region may become more prone to extreme drought it was in the 20th century. Some models of future climate conditions also predict greater fluctuations in wet and dry years. California's 2007-2009 drought exacerbated ongoing tensions among competing water uses. While drought is most common in California and the Southwest, drought also can exacerbate water tensions in other regions. For example, the 2007-2008 drought in the Southeast heightened a long-standing dispute in the Apalachicola-Chattahoochee-Flint River (ACF) basin. Both California and the ACF are again experiencing drought conditions, as are the Rio Grande and Upper Colorado River basins. What are some drought policy challenges? Although the impacts of drought can be significant nationally as well as regionally, comprehensive national drought policy does not exist. Developing such a policy would represent a significant challenge because of split federal and non-federal responsibilities, the existing patchwork of federal drought programs, and differences in regional conditions and risks. While a comprehensive national policy has not been enacted, Congress has considered and acted upon some of the recommendations issued by the National Drought Policy Commission in 2000. In coming years, Congress may review how federal agencies such as the U.S. Army Corps of Engineers and the Bureau of Reclamation respond to droughts. Congress may also assess other federal programs or choose to reassess the National Drought Policy Commission's recommendations.

In the past, the oil and gas industry considered gas locked in tight, impermeable shale uneconomical to produce. However, advances in directional well drilling and reservoir stimulation have dramatically increased gas production from unconventional shales. The United States Geological Survey estimates that 200 trillion cubic feet of natural gas may be technically recoverable from these shales. Recent high natural gas prices have also stimulated interest in developing gas shales. Although natural gas prices fell dramatically in 2009, there is an expectation that the demand for natural gas will increase. Developing these shales comes with some controversy, though. The hydraulic fracturing treatments used to stimulate gas production from shale have stirred environmental concerns over excessive water consumption, drinking water well contamination, and surface water contamination from both drilling activities and fracturing fluid disposal. The saline "flowback" water pumped back to the surface after the fracturing process poses a significant environmental management challenge in the Marcellus region. The flowback's high content of total dissolved solids (TDS) and other contaminants must be disposed of or adequately treated before discharged to surface waters. The federal Clean Water Act and state laws regulate the discharge of this flowback water and other drilling wastewater to surface waters, while the Safe Drinking Water Act (SDWA) regulates deep well injection of such wastewater. Hydraulically fractured wells are also subject to various state regulations. Historically, the EPA has not regulated hydraulic fracturing, and the 2005 Energy Policy Act exempted hydraulic fracturing from SDWA regulation. Recently introduced bills would make hydraulic fracturing subject to regulation under SDWA, while another bill would affirm the current regulatory exemption. Gas shale development takes place on both private and state-owned lands. Royalty rates paid to state and private landowners for shale gas leases range from 121/2% to 20%. The four states (New York, Pennsylvania, Texas, and West Virginia) discussed in this report have shown significant increases in the amounts paid as signing bonuses and increases in royalty rates. Although federal lands also overlie gas shale resources, the leasing restrictions and the low resource-potential may diminish development prospects on some federal lands. The practice of severing mineral rights from surface ownership is not unique to the gas shale development. Mineral owners retain the right to access surface property to develop their holdings. Some landowners, however, may not have realized the intrusion that could result from mineral development on their property. Although a gas-transmission pipeline-network is in place to supply the northeast United States, gas producers would need to construct an extensive network of gathering pipelines and supporting infrastructure to move the gas from the well fields to the transmission pipelines, as is the case for developing any new well fiel

Congress is examining potential approaches to reducing manmade contributions to global warming from U.S. sources. One approach is carbon capture and sequestration (CCS) - capturing CO2 at its source (e.g., a power plant) and storing it indefinitely (e.g., underground) to avoid its release to the atmosphere. A common requirement among the various techniques for CCS is a dedicated pipeline network for transporting CO2 from capture sites to storage sites.

On March 27, 2012, the U.S. Environmental Protection Agency (EPA) proposed a new rule that would limit emissions to no more than 1,000 pounds of carbon dioxide (CO2) per megawatt-hour of production from new fossil-fuel power plants with a capacity of 25 megawatts or larger. EPA proposed the rule under Section 111 of the Clean Air Act. According to EPA, new natural gas fired combined-cycle power plants should be able to meet the proposed standards without additional cost. However, new coal-fired plants would only be able to meet the standards by installing carbon capture and sequestration (CCS) technology. The proposed rule has sparked increased scrutiny of the future of CCS as a viable technology for reducing CO2 emissions from coal-fired power plants. The proposed rule also places a new focus on whether the U.S. Department of Energy's (DOE's) CCS research, development, and demonstration (RD&D) program will achieve its vision of developing an advanced CCS technology portfolio ready by 2020 for large-scale CCS deployment. Congress has appropriated nearly $6 billion since FY2008 for CCS RD&D at DOE's Office of Fossil Energy: approximately $2.3 billion from annual appropriations and $3.4 billion from the American Recovery and Reinvestment Act (or Recovery Act). The large and rapid influx of funding for industrial-scale CCS projects from the Recovery Act may accelerate development and deployment of CCS in the United States. However, the future deployment of CCS may take a different course if the major components of the DOE program follow a path similar to DOE's flagship CCS demonstration project, FutureGen, which has experienced delays and multiple changes of scope and design since its inception in 2003. A question for Congress is whether FutureGen represents a unique case of a first mover in a complex, expensive, and technically challenging endeavor, or whether it indicates the likely path for all large CCS demonstration projects once they move past the planning stage. Since enactment of the Recovery Act, DOE has shifted its RD&D emphasis to the demonstration phase of carbon capture technology. The shift appears to heed recommendations from many experts who called for large, industrial-scale carbon capture demonstration projects (e.g., 1 million tons of CO2 captured per year). Funding from the Recovery Act for large-scale demonstration projects was 40% of the total amount of DOE funding for all CCS RD&D from FY2008 through FY2012. To date, there are no commercial ventures in the United States that capture, transport, and inject industrial-scale quantities of CO2 solely for the purposes of carbon sequestration. However, CCS RD&D in 2012 is just now embarking on commercial-scale demonstration projects for CO2 capture, injection, and storage. The success of these projects will likely bear heavily on the future outlook for widespread deployment of CCS technologies as a strategy for preventing large quantities of CO2 from reaching the atmosphere while U.S. power plants continue to burn fossil fuels, mainly coal. Given the pending EPA rule, congressional interest in the future of coal as a domestic energy source appears directly linked to the future of CCS. In the short term, congressional support for building new coal-fired power plants could be expressed through legislative action to modify or block the proposed EPA rule. Alternatively, congressional oversight of the CCS RD&D program could help inform decisions about the level of support for the program and help Congress gauge whether it is on track to meet its goals.

The 1994 Northridge (CA) earthquake caused as much as $26 billion (in 2005 dollars) in damage and was one of the costliest natural disasters to strike the United States. The Federal Emergency Management Agency has estimated that earthquakes cost the United States over $5 billion per year. A hypothetical scenario for a magnitude 7.8 earthquake in southern California estimated a possibility of 1,800 fatalities and over $200 billion in economic losses. The May 12, 2008, magnitude 7.9 earthquake in Sichuan, China, resulted in nearly 70,000 fatalities. The January 12, 2010, magnitude 7.0 earthquake that struck Haiti only 15 miles from Port-au-Prince, the capital city, is also expected to result in a high number of fatalities and injuries. Compared to the loss of life in some other countries, relatively few Americans have died as a result of earthquakes over the past 100 years. The United States, however, faces the possibility of large economic losses from earthquake-damaged buildings and infrastructure. California alone accounts for most of the estimated annualized earthquake losses for the nation, and with Oregon and Washington the three states account for nearly $4.1 billion (77%) of the U.S. total estimated annualized loss. A single large earthquake, however, can cause ...

For most of the twentieth century, the primary use of coal in the United States was for electric power generation, and for most of the history of power generation in the United States, coal has been the dominant fuel used to produce electricity. Even as recently as 2011, coal was the fuel used for almost 42% of power generation in the United States accounting for 93% of coal use. Industrial uses represented the remaining 7%. However, in April 2012, coal's share of the power generation market dropped to about 32% (according to Energy Information Administration statistics), equal to that of natural gas. Coal was the fuel of choice because of its availability and the relatively low cost of producing electricity in large, coal-burning power plants which took advantage of coal's low-priced, high energy content to employ economies of scale in steamelectric production. However, coal use for power generation seems to be on the decline, and the magnitude of coal's role for power generation is in question. Two major reasons are generally seen as being responsible: the expectation of a dramatic rise in natural gas supplies, and the impact of environmental regulations on an aging base of coal-fired power plants. A recent drop in natural gas prices has been enabled by increasing supplies of natural gas largely due to horizontal drilling and hydraulic fracturing (i.e., fracking) of shale gas formations. If the production can be sustained in an environmentally acceptable manner, then a long-term, relatively inexpensive supply of natural gas could result. Decreased natural gas prices are lowering wholesale electricity prices, stimulating a major switch from coal to gas-burning facilities. The electric utility industry values diversity in fuel choice options since reliance on one fuel or technology can leave electricity producers vulnerable to price and supply volatility. However, an "inverse relationship" may be developing for coal vs. natural gas as a power generation choice based on market economics alone, and policies which allow one fuel source to dominate may come at the detriment of the other. Coal-fired power plants are among the largest sources of air pollution in the United States. More than half a dozen separate Clean Air Act programs could possibly be used to control emissions, which makes compliance strategy potentially complicated for utilities and difficult for regulators. Because the cost of the most stringent available controls, for the entire industry, could range into the tens of billions of dollars, some power companies have fought hard and rather successfully to limit or delay regulations affecting them, particularly with respect to plants constructed before the Clean Air Act Amendments of 1970 were passed. The expected retirement of approximately 27 GW of coal-fired capacity by 2016 has been reported to the Energy Information Administration (EIA) by coal plant owners and operators, accounting for approximately 8.5% of U.S. coal-fired capacity. While the costs of compliance with new Environmental Protection Agency regulations are a factor, several other issues are cited by coal plant owners and operators as contributing to these retirement decisions including the age of coal-fired power plants, flat to modest electricity demand growth, the availability of previously underutilized natural gas combined-cycle power plants, and the lower price of natural gas due to shale gas development. Even coal plants which have made significant modifications to meet existing EPA regulations are being closed or mothballed due to a combination of low natural gas prices, and the inability to sell power into other markets. EIA expects coal to be a significant part of the U.S. power generation industry's future to well past 2030. But given price competition from natural gas, and emerging environmental regulations, that role will likely be smaller than in recent decades. Coal-fired generation is likely to face a challenging future.

Carbon capture and sequestration (or storage)-known as CCS-has attracted interest as a measure for mitigating global climate change because large amounts of carbon dioxide (CO2) emitted from fossil fuel use in the United States are potentially available to be captured and stored underground or prevented from reaching the atmosphere. Large, industrial sources of CO2, such as electricity-generating plants, are likely initial candidates for CCS because they are predominantly stationary, single-point sources. Electricity generation contributes over 40% of U.S. CO2 emissions from fossil fuels.

The earthquake and subsequent tsunami that devastated Japan's Fukushima Daiichi nuclear power station and the earthquake that forced the North Anna, VA, nuclear power plant's temporary shutdown have focused attention on the seismic criteria applied to siting and designing commercial nuclear power plants. Some Members of Congress have questioned whether U.S nuclear plants are more vulnerable to seismic threats than previously assessed, particularly given the Nuclear Regulatory Commission's (NRC's) ongoing reassessment of seismic risks at certain plant sites. The design and operation of commercial nuclear power plants operating in the United States vary considerably because most were custom-designed and custom-built. Boiling water reactors (BWRs) directly generate steam inside the reactor vessel. Pressurized water reactors (PWRs) use heat exchangers to convert the heat generated by the reactor core into steam outside of the reactor vessel. U.S. utilities currently operate 104 nuclear power reactors at 65 sites in 31 states; 69 are PWR designs and the 35 are BWR designs. One of the most severe operating conditions a reactor may face is a loss of coolant accident (LOCA), which can lead to a reactor core meltdown. The emergency core cooling system (ECCS) provides core cooling to minimize fuel damage by injecting large amounts of cool water containing boron (borated water slows the fission process) into the reactor coolant system following a pipe rupture or other water loss. The ECCS must be sized to provide adequate makeup water to compensate for a break of the largest diameter pipe in the primary system (i.e., the socalled "double-ended guillotine break" (DEGB)). The NRC considers the DEGB to be an extremely unlikely event; however, even unlikely events can occur, as the magnitude 9.0 earthquake and resulting tsunami that struck Fukushima Daiichi proves. U.S. nuclear power plants designed in the 1960s and 1970s used a deterministic statistical approach to addressing the risk of damage from shaking caused by a large earthquake (termed Deterministic Seismic Hazard Analysis, or DSHA). Since then, engineers have adopted a more comprehensive approach to design known as Probabilistic Seismic Hazard Analysis (PSHA). PSHA estimates the likelihood that various levels of ground motion will be exceeded at a given location in a given future time period. New nuclear plant designs will apply PSHA. In 2008, the U.S Geological Survey (USGS) updated the National Seismic Hazard Maps (NSHM) that were last revised in 2002. USGS notes that the 2008 hazard maps differ significantly from the 2002 maps in many parts of the United States, and generally show 10%-15% reductions in spectral and peak ground acceleration across much of the Central and Eastern United States (CEUS), and about 10% reductions for spectral and peak horizontal ground acceleration in the Western United States (WUS). Spectral acceleration refers to ground motion over a range, or spectra, of frequencies. Seismic hazards are greatest in the WUS, particularly in California, Oregon, and Washington, as well as Alaska and Hawaii. In 2010, the NRC examined the implications of the updated NSHM for nuclear power plants operating in the CEUS, and concluded that NSHM data suggest that the probability for earthquake ground motions may be above the seismic design basis for some nuclear plants in the CEUS. In late March 2011, NRC announced that it had identified 27 nuclear reactors operating in the CEUS that would receive priority earthquake safety reviews.

The United States faces the possibility of large economic losses from earthquake-damaged buildings and infrastructure. The Federal Emergency Management Agency has estimated that earthquakes cost the United States, on average, over $5 billion per year. California, Oregon, and Washington account for nearly $4.1 billion (77%) of the U.S. total estimated average annualized loss. California alone accounts for most of the estimated annualized earthquake losses for the nation. A single large earthquake, however, can cause far more damage than the average annual estimate. The 1994 Northridge (CA) earthquake caused as much as $26 billion (in 2005 dollars) in damage and was one of the costliest natural disasters to strike the United States. One study of the damage caused by a hypothetical magnitude 7.8 earthquake along the San Andreas Fault in southern California projected as many as 1,800 fatalities and more than $200 billion in economic losses. An issue for the 112th Congress is whether existing federally supported programs aimed at reducing U.S. vulnerability to earthquakes are an adequate response to the earthquake hazard. Under the National Earthquake Hazards Reduction Program (NEHRP), four federal agencies have responsibility for long-term earthquake risk reduction: the U.S. Geological Survey (USGS), the National Science Foundation (NSF), the Federal Emergency Management Agency (FEMA), and the National Institute of Standards and Technology (NIST). They variously assess U.S. earthquake hazards, deliver notifications of seismic events, develop measures to reduce earthquake hazards, and conduct research to help reduce overall U.S. vulnerability to earthquakes. Congressional oversight of the NEHRP program might revisit how well the four agencies coordinate their activities to address the earthquake hazard. Better coordination was a concern that led to changes to the program in legislation enacted in 2004 (P.L. 108-360). P.L. 108-360 authorized appropriations for NEHRP through FY2009. Total funding enacted from reauthorization through FY2009 was $613.2 million, approximately 68% of the total amount of $902.4 million authorized by P.L. 108-360. Congress appropriated $131.2 million for NEHRP in FY2010, similar to FY2009 funding levels. Also, the American Recovery and Reinvestment Act (ARRA; P.L. 111-5) provided some additional funding for earthquake activities under NEHRP. What effect funding at the levels enacted through FY2010 under NEHRP has had on the U.S. capability to detect earthquakes and minimize losses after an earthquake occurs is difficult to assess. The effectiveness of the NEHRP program is a perennial issue for Congress: it is inherently difficult to capture precisely, in terms of dollars saved or fatalities prevented, the effectiveness of mitigation measures taken before an earthquake occurs. A major earthquake in a populated urban area within the United States would cause damage, and a question becomes how much damage would be prevented by mitigation strategies underpinned by the NEHRP program. Legislation was introduced during the 111th Congress (H.R. 3820) that would have made changes to the program and would have authorized appropriations totaling $906 million over five years for NEHRP. Ninety percent of the funding would have been designated for the USGS and NSF, and the remainder for FEMA and NIST. The bill passed the House but not the Senate. Similar legislation will likely be introduced in the 112th Congress.

This report covers Carbon Capture and Sequestration. Carbon capture and sequestration (or storage)-known as CCS-has attracted interest as a measure for mitigating global climate change because large amounts of carbon dioxide (CO2) emitted from fossil fuel use in the United States are potentially available to be captured and stored underground or prevented from reaching the atmosphere. Large, industrial sources of CO2, such as electricity-generating plants, are likely initial candidates for CCS because they are predominantly stationary, single-point sources. Electricity generation contributes over 40% of U.S. CO2 emissions from fossil fuels.