Hydraulic fracturing is a technique used to recover oil and natural gas from underground low permeability rock formations. Hydraulic fracturing involves pumping fluids (primarily water and a small portion of chemicals, along with sand or other proppant) under high pressure into rock formations to crack them and allow the resources inside to flow to a production well. The technique has been the subject of controversy because of the potential effects that hydraulic fracturing and related oil and gas production activities may have on the environment and health. This report focuses on selected legal issues related to the use of hydraulic fracturing. It examines some of the requirements for hydraulic fracturing contained in major federal environmental laws. It also provides an overview of issues involving state preemption of local zoning authority, as well as state tort law. The Safe Drinking Water Act (SDWA), among other things, directs EPA to regulate the underground injection of fluids (including solids, liquids, and gases) to protect underground sources of drinking water. Part C of the SDWA establishes the national regulatory program for the protection of underground sources of drinking water, including the oversight and limitation of underground injections that could affect aquifers, through the establishment of underground injection control regulations. Section 1421 of the SDWA directs the EPA Administrator to promulgate regulations for state underground injection control (UIC) programs, and mandates that the EPA regulations "contain minimum requirements for programs to prevent underground injection that endangers drinking water sources." Section 1421(b)(2) specifies that EPA may not prescribe requirements for state UIC programs which interfere with or impede—(A) the underground injection of brine or other fluids which are brought to the surface in connection with oil or natural gas production or natural gas storage operations, or (B) any underground injection for the secondary or tertiary recovery of oil or natural gas, unless such requirements are essential to assure that underground sources of drinking water will not be endangered by such injection . As noted, Section 1421 of the SDWA states that UIC regulations must "contain minimum requirements for effective programs to prevent underground injection which endangers drinking water sources." Known as the "endangerment standard," this statutory standard is a major driving force in EPA regulation of underground injection. This endangerment language focuses on protecting groundwater that is used or may be used to supply public water systems. This focus parallels the general scope of the statute, which addresses the quality of water provided by public water systems and does not address private, residential wells. The endangerment language has raised questions as to whether EPA regulations can reach underground injection activities to protect groundwater that is not used by public water systems. The SDWA directs EPA to protect against endangerment of an "underground source of drinking water" (USDW). The regulations define a USDW to mean an aquifer or part of an aquifer that either: supplies a public water system; or contains a sufficient quantity of groundwater to supply a public water system; and currently supplies drinking water for human consumption; or contains fewer than 10,000 milligrams per liter (mg/L) total dissolved solids; and is not an "exempted aquifer." To implement the UIC program as mandated by the provisions of the SDWA described above, EPA has established six classes of underground injection wells based on categories of materials that are injected into the ground by each class. In addition to the similarity of fluids injected in each class of wells, each class shares similar construction, injection depth, design, and operating techniques. The wells within a class are required to meet a set of appropriate performance criteria for protecting undergro und sources of drinking water. Class II wells feature the injection of brines and other fluids associated with oil and gas production, and hydrocarbons for storage. The wells inject fluids beneath the lowermost USDW. If hydraulic fracturing were to be regulated under the SDWA, it is likely that most hydraulic fracturing operations would be characterized as Class II wells. Under the SDWA, states may take on primary responsibility for administration and enforcement. Section 1422 of the SDWA authorizes EPA to delegate primary enforcement authority for UIC programs to the states, provided that the state program meets EPA requirements promulgated under Section 1421 and prohibits any underground injection that is not authorized by a state permit or rule. If a state's UIC program plan is not approved, or the state has chosen not to assume program responsibility, then EPA must implement the UIC program in that state. Alternatively, Section 1425 authorizes EPA to approve the portion of a state's UIC program that relates to "any underground injection for the secondary or tertiary recovery of oil or natural gas" if the state program meets certain requirements of Section 1421 and represents an effective program to prevent underground injection which endangers drinking water sources. Under this provision, states may demonstrate to EPA that their existing programs for oil and gas injection wells are effective in preventing endangerment of underground sources of drinking water. This provides states with an alternative to meeting the specific requirements contained in EPA regulations promulgated under Section 1421. From the date of the SDWA's enactment in 1974 until the late 1990s, hydraulic fracturing was not regulated under the act by either EPA or any of the states who had chosen to take on responsibility for administration of the SDWA. However, in the last 15 years a number of developments called into question the extent to which hydraulic fracturing would be considered an "underground injection" to be regulated under the SDWA. One trigger for this debate was a challenge to the Alabama UIC program brought by the Legal Environmental Assistance Foundation (LEAF). In 1994, LEAF petitioned EPA to initiate proceedings to have the agency withdraw its approval of the Alabama UIC program because the program did not regulate hydraulic fracturing operations in the state associated with production of methane gas from coalbed formations. The State of Alabama had previously been authorized by EPA to administer a UIC program pursuant to the terms of the SDWA. EPA denied the LEAF petition in 1995 based on a finding that hydraulic fracturing did not fall within the definition of "underground injection" as the term was used in the SDWA and the EPA regulations promulgated under that act. According to EPA, that term applied only to wells whose "principal function" was the placement of fluids underground. LEAF challenged EPA's denial of its petition in the U.S. Court of Appeals for the Eleventh Circuit, arguing that EPA's interpretation of the terms in question was inconsistent with the language of the SDWA. The court rejected EPA's claim that the language of the SDWA allowed it to regulate only those wells whose "principal function" was the injection of fluids into the ground. EPA based this claim on what it perceived as "ambiguity" in the SDWA regarding the definition of "underground injection" as well as a perceived congressional intent to exclude wells with primarily non-injection functions. The court held that there was no ambiguity in the SDWA's definition of "underground injection" as "the subsurface emplacement of fluids by well injection," noting that the words have a clear meaning and that: The process of hydraulic fracturing obviously falls within this definition, as it involves the subsurface emplacement of fluids by forcing them into cracks in the ground through a well. Nothing in the statutory definition suggests that EPA has the authority to exclude from the reach of the regulations an activity (i.e. hydraulic fracturing) which unquestionably falls within the plain meaning of the definition, on the basis that the well that is used to achieve that activity is also used—even primarily used—for another activity (i.e. methane gas production) that does not constitute underground injection. The court therefore remanded the decision to EPA for reconsideration of LEAF's petition for withdrawal of Alabama's UIC program approval. Following the LEAF I decision, in 1999 Alabama submitted a revised UIC program to EPA. Alabama sought approval for the revised UIC program under Section 1425 of the SDWA rather than Section 1422(b). As mentioned above, Section 1425 differs from Section 1422(b) in that approval under Section 1425 is based on a showing by the state that the program meets the generic requirements found in Section 1421(b)(1)(A)-(D) of the SDWA and that the program "represents an effective program (including adequate recordkeeping and reporting) to prevent underground injection which endangers drinking water sources." In contrast, approval of a state program under Section 1422(b) requires a showing that the state's program satisfies the requirements of the UIC regulations promulgated by EPA. EPA approved Alabama's revised UIC program in 2000, and LEAF appealed EPA's decision to approve to the U.S. Court of Appeals for the Eleventh Circuit. In its challenge, LEAF made three arguments. First, LEAF claimed that EPA should not have approved state regulation of hydraulic fracturing under Section 1425 of the SDWA because it does not "relate to ... underground injection for the secondary or tertiary recovery of oil or natural gas," one of the requirements for approval under Section 1425. The court rejected this argument, finding that the phrase "relates to" was broad and ambiguous enough to include regulation of hydraulic fracturing as being related to secondary or tertiary recovery of oil or natural gas. Second, LEAF challenged the Alabama program's regulation of hydraulic fracturing as "Class II-like" wells not subject to the same regulatory requirements as Class II wells. The court agreed with LEAF on this point, noting that in its decision in LEAF I , it had held that methane gas production wells used for hydraulic fracturing are "wells" within the meaning of the statute. As a result, the court found that wells used for hydraulic fracturing must fall under one of the five classes set forth in the EPA regulations at 40 C.F.R. Section 144.6. Specifically, the court found that the injection of hydraulic fracturing fluids for recovery of coalbed methane "fit squarely within the definition of Class II wells," and as a result the court remanded the matter to EPA for a determination of whether Alabama's updated UIC program complied with the requirements for Class II wells. Finally, LEAF alleged that even if Alabama's revised UIC program was eligible for approval under Section 1425 of the SDWA, EPA's decision to approve it was "arbitrary and capricious" and therefore a violation of the Administrative Procedure Act. The court rejected this argument. The decision by the U.S. Court of Appeals for the Eleventh Circuit in LEAF I highlighted a debate over whether the SDWA, as it read at the time, required EPA to regulate hydraulic fracturing. Although the Eleventh Circuit's decision applied only to hydraulic fracturing for coalbed methane production in Alabama, the court's reasoning—in particular, its finding that hydraulic fracturing "unquestionably falls within the plain meaning of the definition [of underground injection]" —raised the issue of whether EPA could be required to regulate hydraulic fracturing generally under the SDWA. Before this question was resolved through agency action or litigation, Congress passed an amendment to the SDWA as a part of the Energy Policy Act of 2005 (EPAct 2005; P.L. 109-58 ) that addressed this issue. Section 322 of EPAct 2005 amended the definition of "underground injection" in the SDWA as follows: The term "underground injection"—(A) means the subsurface emplacement of fluids by well injection; and (B) excludes—(i) the underground injection of natural gas for purposes of storage; and (ii) the underground injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities. This amendment clarified that the UIC requirements found in the SDWA do not apply to hydraulic fracturing, although the exclusion does not extend to the use of diesel fuel in hydraulic fracturing operations. This amended language is the definition of "underground injection" found in the SDWA as of the date of this report. As noted above, the 2005 amendment to the definition of "underground injection" in the SDWA excluded injections as part of hydraulic fracturing operations, but such injections involving the use of diesel fuels were not made part of the exclusion, meaning that injections for purposes of hydraulic fracturing involving the use of diesel fuel might still be made subject to regulation under the SDWA. It was not clear to states or the regulated community how EPA would address the EPAct 2005 amendment, and for several years EPA took no official position regarding the regulation of hydraulic fracturing using diesel fuel under the SDWA. In February 2014, EPA issued final diesel permitting guidance, which states that "under the 2005 amendments to the SDWA, a UIC Class II permit must be obtained prior to conducting the underground injection of diesel fuels for hydraulic fracturing." As described earlier in this report, injections subject to UIC Class II requirements must comply with a number of regulatory requirements. These include permitting requirements, and testing and monitoring obligations with respect to the well. The guidance is intended for EPA permit writers and is relevant where EPA directly implements the UIC Class II program. EPA notes that "[t]o the extent that states may choose to follow some aspects of EPA guidance in implementing their own programs, it may also be relevant in areas where EPA is not the permitting authority." There had been considerable debate regarding how EPA would define "diesel fuels" in the final guidance. The draft guidance recommends using six Chemical Abstracts Service Registry Numbers (CASRNs) for determining whether diesel fuels are used in hydraulic fracturing operations. These six CASRNs collectively include various types of diesel fuels, home heating oils, kerosene, crude oil, and a range of other petroleum compounds. Also at issue was whether the final guidance would specify a de minimis amount of diesel fuel content for hydraulic fracturing fluids; the draft guidance did not do so. The final document covers five of the six proposed CASRNs (no longer including crude oil), and does not establish a de minimis concentration of "diesel" in fracturing fluid that would be exempt from permitting requirements. Hydraulic fracturing is a water-intensive practice. After a well is hydraulically fractured, a substantial portion of the injected fluid returns to the surface as "flowback." This flowback typically contains proppant (sand) and chemical residues from the frac fluid, as well as salts, metals, and potentially significant amounts of naturally occurring radioactive materials (NORM) that may be present in the water produced from the geologic formations. Additionally, oil and gas wells generally continue to produce formation water throughout their production lives. Flowback water and production brine that are not reused will require proper disposal, either through underground injection or treatment and surface discharge. Often this flowback is injected into wells for disposal. However, if underground injection is not feasible or not employed for other reasons, drilling companies may opt to transfer the wastewater to publicly owned treatment works (POTW) that discharge into navigable waters in compliance with the Clean Water Act (CWA). Section 301(a) of the CWA prohibits "the discharge of any pollutant" into "navigable waters" except as permitted pursuant to other sections of the CWA. Under Section 304(m), EPA sets national standards for discharges of industrial wastewater based on best available technologies that are economically achievable. States incorporate these limits into discharge permits. Current effluent limitation guidelines (ELGs) and standards for the Oil and Gas Extraction Point Source Category prohibit direct discharges of onshore oil and gas wastewater into surface waters. However, current ELGs do not include standards for "indirect discharges" of these wastewaters to POTWs. On June 28, 2016, EPA promulgated final regulations establishing a "zero discharge" pretreatment standard to prohibit discharges to POTWs of wastewater resulting from unconventional oil and gas production. In the proposed regulations, EPA had noted that, while states are not approving requests for such discharges to POTWs, the proposed zero discharge standard would "provide regulatory certainty and would eliminate the burden on POTWs to analyze such requests." As this report has explained, the definition of "underground injection" found in the SDWA prevents regulation of hydraulic fracturing pursuant to that statute unless the fracking fluid contains diesel fuel. However, other federal environmental statutes do not contain similar reservations of jurisdiction, and EPA has sought to regulate certain environmental impacts of hydraulic fracturing pursuant to these statutes. One such avenue is regulation of emissions associated with the hydraulic fracturing process via the Clean Air Act (CAA). On August 16, 2012, EPA issued new regulations covering, among other things, emissions of volatile organic compounds (VOCs) from onshore natural gas hydraulic fracturing operations. The impetus for the new regulations was a legal challenge filed by environmental organizations. In 2009, WildEarth Guardians and the San Juan Citizens Alliance filed a petition in the U.S. District Court for the District of Columbia alleging that EPA had failed to review and revise its New Source Performance Standards (NSPSs) for oil and gas operations every eight years as required by Section 111(b)(1)(B) of the CAA. Specifically, the environmental groups alleged that EPA had failed to update existing standards and adopt new standards for emissions from oil and natural gas production as well as natural gas transmission and storage. The challenge and subsequent settlement triggered a new rulemaking by EPA in which it not only updated existing standards for certain natural gas processing plants, but also established new standards for emissions from certain types of natural gas operations not covered at all in the existing standards. Among the new standards were requirements applicable to new onshore natural gas hydraulic fracturing operations as well as refracturing operations. The new regulations direct the industry to adopt a process known as "green completions" or "reduced emissions completions" for hydraulically fractured gas wells. (Hydraulically fractured oil wells are exempt from the 2012 NSPS requirements.) In a "green completion," the natural gas that would otherwise be vented or flared during the completion process is captured and cleaned for reuse in another process that does not involve direct release into the atmosphere. In order to allow the industry time to make the needed changes, the rulemaking established two phases for compliance. During Phase 1, which lasted from the effective date of the rulemaking (October 15, 2012) until January 1, 2015, industry had to reduce VOC emissions at new hydraulic fracturing sites either by using a "completion combustion device" in a technique commonly referred to as "flaring," or by employing the green completion process. As of January 1, 2015, all hydraulically fractured wells had to employ a green completion. These requirements apply both to new hydraulic fracturing operations and to refracturing of existing wells. The regulations also establish reporting requirements for owners and operators of hydraulically fractured and refractured wells prior to the start of well completion. There are some exceptions in these regulations for certain types of wells. Exploratory or "wildcat" drilling operations and "delineation wells" used to determine the borders of a reservoir, and low-pressure wells do not need to employ green completions. The 2012 NSPS requires operators of these types of wells to use completion combustion devices unless hazardous or prohibited under state or local law or regulations. On June 3, 2016, EPA promulgated several CAA rules affecting the oil and natural gas production industry, including amendments to the NSPS standards for the oil and natural gas source category to establish new emissions standards for methane (a short-lived greenhouse gas) and VOCs. Briefly, the rules do the following: 1. Build on the 2012 NSPS "to set first-ever controls for methane emissions and extend controls for VOC emissions beyond the existing requirements to include new or modified hydraulically fractured oil wells, pneumatic pumps, compressor stations, and leak detection and repair at well sites, gathering and boosting stations, and processing plants." The final rule also includes the issuance for public comment of an Information Collection Request (ICR) that would require companies to provide extensive information that is instrumental for developing comprehensive regulations to reduce methane emissions from existing oil and gas sources. EPA notes the new NSPS does not add requirements for operations covered by the 2012 rule but it expands coverage to include other sources. 2. Revise permitting requirements applicable to stationary sources in the oil and natural gas sector. The rule establishes in regulation a specific meaning of the term "adjacent" for this sector, which was previously defined in guidance documents. 3. Limit emissions from oil and gas production in Indian country. Further, EPA has issued rules or guidelines to strengthen the Greenhouse Gas Reporting Program to require reporting in all segments of the industry (promulgated on October 22, 2015) and extend VOC reduction requirements to existing oil and gas sources in ozone nonattainment areas and states in the Ozone Transport Region (released on August 18, 2015). Federal and state authorities to regulate wastes are established under the Solid Waste Disposal Act of 1965, as amended by the Resource Conservation and Recovery Act of 1976 (RCRA). Subtitle C of RCRA established a framework for EPA, or authorized states, to regulate waste identified as "hazardous." Specifically, EPA was required to develop criteria necessary to identify hazardous wastes and to promulgate regulations applicable to hazardous waste generators and transporters and to facilities that treat, store, and dispose of such wastes. EPA has primary authority to implement the federal hazardous waste program, but was required to develop procedures for states to become authorized to implement that program. Most states have chosen to do so. Under RCRA Subtitle D, state and local governments were established as the primary planning, regulating, and implementing entities responsible for managing non-hazardous solid waste, including waste explicitly exempt from regulation under Subtitle C. EPA's primary role under Subtitle D is to provide state and local agencies with information, guidance, and policy. The Solid Waste Disposal Act Amendments of 1980 ( P.L. 96-482 ) included amendments to Subtitle C requirements regarding the identification of hazardous waste. Provisions commonly referred to as the "Bentsen" amendment temporarily excluded "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy" (E&P wastes) from regulation as hazardous wastes under Subtitle C of RCRA. The exemption was motivated in part by a concern about the economic impact that comprehensive regulation of E&P wastes under Subtitle C would have on the oil and gas industry. The Bentsen amendment required EPA to conduct a study of E&P waste and submit its findings to Congress. If EPA determined that E&P wastes warranted regulation under Subtitle C, the agency was required to submit proposed regulations to both houses of Congress. Those regulations could "take effect only when authorized by Act of Congress." In its 1987 report to Congress, EPA found, in part, that existing state and federal regulations were generally adequate to regulate E&P wastes, although there were regulatory gaps in certain states. EPA further found that regulating E&P wastes under RCRA Subtitle C would have a substantial impact on the U.S. economy and would be unnecessary and impracticable. In its 1988 regulatory determination, EPA determined that the management of E&P wastes under Subtitle C was not warranted, but that the agency would pursue the following three-pronged approach to addressing adverse effects of the waste: improve existing federal regulatory programs under RCRA Subtitle D and augment the Safe Drinking Water Act and/or Clean Water Act requirements; work with states to improve their waste management programs; and work with Congress on any additional legislation that might be needed. In the 25 years since EPA made its regulatory determination, the agency has chosen not to develop regulations under RCRA Subtitle D or pursue additional RCRA legislation. However, EPA has previously sought to clarify the Subtitle C exemption. In 2002, EPA issued guidance regarding the scope of the exemption, including examples of exempt and non-exempt E&P wastes. EPA listed produced water and drilling fluids as exempt wastes; and unused fracturing fluids or acids as non-exempt waste. That is, unused fracturing fluids may be subject to Subtitle C requirements if the fluid exhibits characteristics that make a waste "hazardous" (e.g., exceed regulatory levels for toxicity). Depending on the chemicals in the drilling fluid and the geologic formations in which it is injected, produced hydraulic fracturing fluids may contain hazardous constituents (e.g., heavy metals). Regardless of whether those fluids exhibit the regulatory characteristics of hazardous waste (e.g., exceed regulatory levels of toxicity), such fluids are exempt from federal Subtitle C regulation. E&P waste disposal is, however, subject to state waste management requirements, as well as requirements applicable to the disposal of liquid waste implemented under federal laws other than RCRA (e.g., UIC Program requirements applicable to the injection of oil and gas-related wastes into Class II wells). In September 2010, the Natural Resources Defense Council (NRDC), an environmental advocacy group, petitioned EPA to initiate a rulemaking under RCRA to regulate E&P wastes as hazardous wastes under Subtitle C. In support of their petition, NRDC identified reports and data prepared since 1988 that they assert "quantify the waste's toxicity, threats to human health and the environment, inadequate state regulatory programs, and readily available solutions." In addition, NRDC asserted that "both the oil and gas industry and the risks associated with E&P wastes have expanded dramatically, making EPA's 1988 Regulatory Determination unjustified." The NRDC sought to have EPA promulgate regulations that subject E&P wastes to Subtitle C to "ensure safe management of these wastes throughout their life cycle from cradle to grave, including generation, transportation, treatment, storage and disposal." EPA has not yet formally responded to the NRDC petition. However, in 2011, EPA indicated that in response to the petition, the Office of Solid Waste and Emergency Response was reviewing incidents alleged by the petitioner; regulations in states with natural gas activities; and best management practices for E&P wastes developed by industry, federal, and state associations. Based on its finding, EPA could possibly review and revise its 1988 regulatory determination. However, as discussed above, the Bentsen amendment specifies that, if EPA determined that Subtitle C regulation was warranted, proposed regulations could not take effect until authorized by act of Congress. Thus, if EPA were to review its 1988 regulatory determination and find that regulation under Subtitle C is necessary, the agency could arguably promulgate such regulations, but could not implement them unless explicitly authorized by Congress to do so. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), often referred to as Superfund, provides broad authority for the federal government to respond to releases or threatened releases of hazardous substances into the environment, in order to protect public health or welfare, or the environment. Federal resources to carry out response actions under CERCLA are subject to the availability of appropriations. To minimize the burden of the costs on the taxpayer, CERCLA established a liability scheme to hold persons responsible for a release or threatened release liable for response costs (i.e., cleanup costs), natural resource damages, and the costs of federal public health studies that may be carried out at a site to assess potential hazards. The categories of "potentially responsible parties" who may be held liable under CERCLA include past and current owners and operators of facilities from which there is a release or threatened release of a hazardous substance, persons who arranged for disposal or treatment of hazardous substances (often referred to as generators of wastes), and persons who transported hazardous substances and selected the site for disposal or treatment. The President's response and enforcement authorities under CERCLA are delegated by Executive Order to the EPA and certain other federal departments and agencies to fulfill various functions under the statute. Although the sites at which hydraulic fracturing is conducted may not fit the typical mold of Superfund sites, it is possible that hydraulic fracturing operations could result in the release of hazardous substances into the environment at or under the surface in a manner that may endanger public health or the environment. If a release were to occur as a result of hydraulic fracturing, the facility owner and operator and other potentially responsible parties could face liability under CERCLA. However, certain exclusions or exemptions from the statute potentially could limit liability in such instances, including the petroleum and natural gas exclusion and the exemption from liability for federally permitted releases, discussed below. Although releases of petroleum and natural gas generally are excluded from the authorities of CERCLA, this exclusion does not constitute a broader facility or industry exclusion, but is a substance exclusion alone. Therefore, CERCLA may apply to hazardous substances released into the environment from a petroleum or natural gas facility. Similarly, CERCLA also potentially could apply to releases of hazardous substances resulting from oil or natural gas production, but not releases of petroleum or natural gas itself. The petroleum and natural gas exclusion is found in the CERCLA definition of a "hazardous substance," where the statute provides that the term "does not include petroleum, including crude oil or any fraction thereof which is not specifically listed or designated as a hazardous substance ... and the term does not include natural gas, natural gas liquids, liquefied natural gas or synthetic gas usable for fuel." Therefore, while CERCLA would not apply to leaked petroleum products at a fracking site, contamination of a site by any substance that does satisfy the definition of a "hazardous substance" could result in liability under the statute. For example, if fracking fluid contained components (i.e., constituents) that are considered hazardous substances under CERCLA, and such fluids were released into the environment at a site in a way that could endanger public health or the environment, the release could warrant cleanup actions, the costs of which the potentially responsible parties would be liable for under CERCLA. Liability similarly could arise from releases of hazardous substances that may be present in produced wastewaters from hydraulic fracturing. Whether a release of hazardous substances that may result from hydraulic fracturing operations would be in compliance with a federal permit (including permits issued by states under delegated federal authorities) or a state-authorized permit would be a critical factor in determining liability. CERCLA exempts persons from liability for response costs or damages under the statute resulting from a "federally permitted release." This exemption provides relief from liability under CERCLA, but does not preclude liability under other federal or state law, including common law. CERCLA defines a federally permitted release to include any underground injection of fluids authorized under the Safe Drinking Water Act, any discharges of wastewater authorized under the Clean Water Act, and other discharges or emissions authorized under certain other federal statutes. This definition also includes any underground injection of fluids or other materials authorized under applicable state law for the production or enhanced recovery of crude oil or natural gas, or the reinjection of produced waters. The exemption from liability under CERCLA for a federally permitted release therefore may include a state permitted release in such instances. EPA has used the response authorities of CERCLA to investigate potential contamination in groundwater in at least two instances that have received prominent attention at locations where natural gas extraction using hydraulic fracturing has been conducted. One such instance occurred in Dimock, PA, and another has occurred in Pavillion, WY. EPA initiated the Pavillion groundwater investigation in response to a public petition submitted under CERCLA in 2008 that cited concerns of residents about groundwater quality. EPA issued a draft investigation report for the Pavillion site on December 8, 2011. On June 20, 2013, EPA announced that it does not plan to finalize its groundwater investigation report for the Pavillion site. EPA indicated that it would defer to the state of Wyoming to assume the lead in investigating drinking water quality in the area, and that its continuing role would focus on providing technical support to the state. The state intended to conclude its investigation and release a final report by September 30, 2014. However, the EPA's website states that, as of March 2016, the agency continues to provide technical assistance to the State of Wyoming during the state's ongoing investigation of Pavillion groundwater issues. The EPA has submitted comments on the state's draft final report examining these issues. On January 19, 2012, EPA issued an Action Memorandum for the Dimock site to "request and document approval of an emergency removal action to prevent, limit, or mitigate the threats posed by the presence of hazardous substances at the Dimock Residential Groundwater Site ... pursuant to Section 104(a) of the Comprehensive Environmental Response, Compensation and Liability Act." The Action Memorandum noted that "[h]istoric drilling activities in the Dimock area have used materials containing hazardous substances" and that there was "reason to believe that a release of hazardous substances has occurred" that may have contaminated groundwater used by residents in the area. EPA announced on July 25, 2012, that it had completed its groundwater investigation at the Dimock site and determined that contaminant levels did not warrant further action by the agency. Although the Dimock and Pavillion sites differ in terms of their geophysical characteristics and other site-specific conditions, they offer examples of the use of the authorities of CERCLA to investigate potential contamination at locations where hydraulic fracturing has been conducted. In both cases, EPA has not confirmed a definitive link between a release of hazardous substances and hydraulic fracturing, and no potentially responsible parties have been identified at either site who would be liable under CERCLA. The National Environmental Policy Act (NEPA) requires federal agencies to consider the potential environmental consequences of proposed federal actions and to involve the public in the federal decisionmaking process, but does not compel agencies to choose a particular course of action. If the action is anticipated to affect significantly the quality of the human environment, the agency must document its consideration of those effects in an environmental impact statement (EIS). If the degree of impacts is uncertain, an agency may prepare an environmental assessment (EA) to determine whether a finding of no significant impact (FONSI) could be made or whether an EIS is necessary. There are certain categories of action that do not individually or cumulatively have a significant effect on the human environment and, thus, do not require the preparation of an EIS or EA. In contrast to the other environmental statutes discussed in this report, NEPA is a procedural statute. It requires that agencies assess the environmental consequences of an action. If the adverse environmental effects of the proposed action are adequately identified and evaluated, an agency is not constrained by NEPA from deciding that other benefits outweigh the environmental costs and moving forward with the action. Because the requirements of NEPA apply only to federal actions, NEPA applies to hydraulic fracturing activities only when such activities take place on federal lands or when there is otherwise a sufficient federal nexus to hydraulic fracturing. The following sections discuss two case studies involving a potential federal role in the production of oil or natural gas resources that may potentially require the preparation of a NEPA document. Oil and gas companies have shown interest in drilling in the Monterey Shale in Central California. The shale formation was at one time estimated to contain billions of barrels of oil, most of which may be economically recovered only through the use of hydraulic fracturing and horizontal drilling. In 2011, the Bureau of Land Management (BLM) sold leases in four parcels, which accounted for about 2,700 acres of public land, to private parties. Environmental groups sued BLM, claiming that the agency had violated the Administrative Procedure Act (APA) and NEPA when it prepared an EA, resulting in a FONSI, instead of an EIS for the proposed lease sale. During the public comment period for the EA, several parties expressed concerns about the potential environmental effects of hydraulic fracturing. However, BLM declined to analyze these impacts because, in its view, they were "not under the authority or within the jurisdiction of the BLM." After issuing a FONSI, BLM proceeded with the auction. The Council on Environmental Quality (CEQ) promulgated regulations implementing NEPA that are broadly applicable to all federal agencies. Those regulations specify what agencies must do to determine whether a proposed action will significantly affect the environment and, therefore, require preparation of an EIS. To determine what constitutes "significant" effects, CEQ regulations require agencies to consider the context of the action and intensity or severity of its impacts. Environmental impacts that must be considered include those identified by CEQ as direct, indirect (reasonably foreseeable future impacts), or cumulative. The district court examined the 10 factors CEQ regulations identify as requiring consideration when determining the severity of an action's impacts. Consistent with those factors, the court identified three factors that it believed required BLM to prepare an EIS. According to the court, these were: (1) hydraulic fracturing is highly controversial because of its potential effects on health and the environment; (2) the proposed lease sale would affect public health and safety because of the risk of water pollution; and (3) the environmental impacts of hydraulic fracturing are uncertain. The court also found that BLM did not properly investigate possible direct or indirect impacts of its decision. In March 2013, the district court held that the BLM NEPA review was "erroneous as a matter of law." The court held that BLM unreasonably relied on an environmental analysis that (1) assumed only one exploratory well would be drilled on the leased acres when it was reasonably foreseeable that more wells would be drilled; and (2) did not contain a detailed assessment of the environmental impacts of hydraulic fracturing and horizontal drilling. The Delaware River Basin Compact is an agreement among the federal government, Delaware, New Jersey, New York, and Pennsylvania. The compact creates the Delaware River Basin Commission (DRBC) and grants it certain powers to manage the water resources of the basin. In December 2010, the commission published draft regulations "to protect the water resources of the Delaware River Basin during the construction and operation of natural gas development projects." In May 2011, the New York Attorney General brought a federal lawsuit on behalf of the State of New York alleging that five federal agencies and their officers were in violation of NEPA. In November 2011, the complaint was amended to add the DRBC and its executive director as defendants. The plaintiffs asked the court to compel the defendants to prepare an EIS "before proceeding to adopt federal regulations to be administered by DRBC that would authorize natural gas development within the Delaware River Basin." New York alleged that the approval of the DRBC regulations was a major federal action requiring at least one of the defendants to prepare an EIS. New York alleged that the refusal of the five federal agencies that are represented by the DRBC's federal member to prepare an EIS was not in accordance with law and was arbitrary, capricious, and an abuse of discretion under the APA. Because it appears that the Delaware River Basin Compact exempts the DRBC from compliance with the APA, New York argued that the DRBC's refusal to prepare an EIS was subject to judicial review under the compact itself. The federal defendants moved to dismiss the lawsuit on the grounds that the court lacked subject matter jurisdiction over the plaintiff's claims. In addition to procedural arguments, the federal defendants maintained that NEPA did not apply because the DRBC's development of proposed regulations was not a "major federal action." The federal defendants argued that no federal action existed because, in their view, the DRBC was not a federal agency. In addition, the federal defendants argued that they did not exercise enough decisionmaking power, authority, or control over the DRBC's development of the proposed regulations to render it a federal action. In September 2012, the U.S. District Court for the Eastern District of New York granted the defendants' motions to dismiss New York's complaint for lack of subject matter jurisdiction. The court held that it lacked subject matter jurisdiction for two reasons. First, the court held that New York lacked standing because it could not show an immediate threat of injury to its interests from the proposed regulations. Alternatively, the court held that it lacked subject matter jurisdiction because New York's complaint was not ripe for review. Because the court dismissed the plaintiffs' complaint on procedural grounds, it did not reach the merits of the plaintiffs' claims. However, because the court dismissed the suit without prejudice, the plaintiffs may file it again in the future if final regulations are adopted. The composition of the fluid used in hydraulic fracturing varies with the nature of the formation but typically contains mostly water; a proppant to keep the fractures open, such as sand; and a small percentage of chemicals. A primary function of these chemicals is to assist the movement of the proppant into the fractures made in the formation. Although some of these chemicals may be harmless, others may be hazardous to health and the environment. A report by the minority staff of the House Committee on Energy and Commerce found that between 2005 and 2009, the 14 leading oil and gas service companies used 780 million gallons of chemical products in fracturing fluids. Calls for public disclosure of information about chemicals used in hydraulic fracturing have increased as homeowners and others express concerns about the potential presence of unknown chemicals in tainted well water near oil and gas operations. Proponents of chemical disclosure laws maintain that public disclosure of the chemicals used in each well would allow for health professionals to better respond to medical emergencies involving human exposure to the chemicals; assist researchers in conducting health studies on shale gas production; and permit regulators and others to perform baseline testing of water sources to track potential groundwater contamination if it occurs. However, some manufacturers of the additives, as well as others in the industry, remain reluctant to disclose information about the chemicals they use. These parties have expressed concerns that disclosure would reveal proprietary chemical formulas to their competitors, destroying the parties' valuable trade secrets. In 2011, President Barack Obama directed Secretary of Energy Steven Chu to convene a panel to study the effects of shale gas production on health and the environment. The Shale Gas Production Subcommittee of the Secretary of Energy Advisory Board made several recommendations intended to address these effects. One recommendation calls for the public disclosure, on a "well-by-well basis," of all of the chemicals added to fracturing fluids, with some protection for trade secrets. No federal law currently requires parties to submit detailed information about the chemical composition of a hydraulic fracturing fluid. Under the Emergency Planning and Community Right-to-Know Act (EPCRA), owners or operators of facilities where certain hazardous hydraulic fracturing chemicals are present above certain thresholds may have to comply with emergency planning requirements; emergency release notification obligations; and hazardous chemical storage reporting requirements. In addition, environmental advocacy groups have petitioned EPA to collect and share health and environmental effect information for hydraulic fracturing chemicals under the Toxic Substances Control Act and to require the oil and gas extraction industry to report the toxic chemicals it releases under EPCRA Section 313, which established EPA's Toxics Release Inventory. Several states have adopted chemical disclosure requirements in the form of laws, regulations, or administrative interpretations. The Interstate Oil and Gas Compact Commission (IOGCC), an organization with members that include state regulators and industry representatives, has argued that current regulation of hydraulic fracturing by the states is sufficient. A main goal of the Toxic Substances Control Act (TSCA) is to protect human health and the environment from unreasonable risks associated with toxic chemicals in U.S. commerce. Under the act, EPA may require manufacturers and processors of chemicals to develop, maintain, and report data on the chemicals' effects on health and the environment. EPA may also place certain restrictions on chemicals when the agency has determined that they warrant regulation based on unreasonable risk of injury to health or the environment or other criteria delineated in the statute. , On August 4, 2011, Earthjustice and more than 100 other environmental advocacy organizations petitioned EPA to promulgate rules under Section 4 and Section 8 of TSCA for chemical substances and mixtures used in oil and gas exploration or production (E&P Chemicals). Section 4 of TSCA authorizes EPA to issue rules requiring manufacturers or processors of chemicals to test the chemicals in order to obtain data on their health and environmental effects. Section 8 of TSCA generally authorizes EPA to require manufacturers, processors, and distributors of chemicals in U.S. commerce to maintain and report certain data on the health and environmental effects of the chemicals. The petition stated that EPA and the public "lack adequate information about the health and environmental effects of E&P Chemicals, which are used in increasing amounts to facilitate the rapid expansion of oil and gas development throughout the United States." Earthjustice and the other petitioners further argued that E&P Chemicals may present an unreasonable risk of injury to health and the environment for several reasons. Petitioners maintained that, for example, leaks and spills of the chemicals may cause harm to people and animals, as well as the quality of air, water, and soil. The petitioners also argued that the large volume of chemicals used in hydraulic fracturing of wells in the United States could result in substantial human exposure to the chemicals, as well as a substantial release of the chemicals into the environment. In the petitioners' view, testing was needed to obtain sufficient data on the chemicals' effects because existing federal and state disclosure requirements were inadequate. EPA's response to the petitioners was mixed. In a November 2, 2011, letter, EPA denied the petitioners' request for promulgation of a TSCA Section 4 test rule. In a short paragraph, the agency wrote that the petitioners had failed to present sufficient facts for EPA to find that such a rule was necessary. However, in a November 23, 2011, letter, EPA partially granted petitioners' Section 8(a) and Section 8(d) requests. The agency wrote that it would initiate a rulemaking to gather available data on the chemicals used in hydraulic fracturing. However, the agency declined to issue rules for other chemicals in the oil and gas exploration and production sector. EPA intends to discuss potential Section 8 reporting requirements with the states, industry, and public interest groups to "minimize reporting burdens and costs, take advantage of existing information, and avoid duplication of efforts." On July 11, 2013, EPA published an explanation of the reasons for the agency's response to the petition. In May 2014, EPA issued an advance notice of proposed rulemaking "to develop an approach to obtain information on chemical substances and mixtures used in hydraulic fracturing." EPA indicated that it had not yet determined whether to mandate disclosure of the chemical information under TSCA, provide incentives for voluntary reporting, or use an approach combining aspects of both mandatory and voluntary disclosure. The Occupational Safety and Health Administration has promulgated a set of regulations under the Occupational Safety and Health Act (OSHAct) referred to as the Hazard Communication Standard (HCS). A primary purpose of the HCS is to ensure that employees who may be exposed to hazardous chemicals in the workplace are aware of the chemicals' potential dangers. Manufacturers and importers must obtain or develop Material Safety Data Sheets (MSDS) for hydraulic fracturing chemicals that are hazardous according to OSHA standards. MSDS must list basic information about the identity of the chemicals; the chemicals' potential hazards; and safety precautions for their handling and use, among other things. The HCS requires operators to maintain MSDS for hazardous chemicals at the job site. MSDS may provide limited information about hydraulic fracturing chemicals. Currently, the most specific details about chemical identities that must be listed on the data sheets are the common or chemical names of substances that are considered to be hazardous under OSHA regulations. Chemical Abstract Service Registry Numbers (CASRNs) for substances or mixtures do not have to be listed. In addition, parties that prepare MSDS may withhold chemical identity information from the data sheets at their discretion in some circumstances. However, the regulations do not prevent parties from voluntarily submitting data sheets with more detailed information. The Emergency Planning and Community Right-to-Know Act (EPCRA) establishes programs to provide members of the public with information about hazardous chemicals located in their communities. It also requires that representatives from different levels of government coordinate their efforts with communities and industry to prepare response plans for emergencies involving the accidental release of hazardous chemicals. The act seeks to induce each state to establish a State Emergency Response Commission (SERC). Each SERC appoints and coordinates the activities of a Local Emergency Planning Committee (LEPC) for each emergency planning district created within a state or across multiple states. A LEPC is responsible for developing an emergency response plan for an accidental chemical release with input from stakeholders and submitting it to the SERC. Generally, a facility is subject to EPCRA's emergency planning requirements if there is a substance on EPA's list of extremely hazardous substances (EHS) present at the facility in excess of its EPA-determined threshold planning quantity. Whether a well site where hydraulic fracturing occurs would be subject to EPCRA's planning requirements would depend on the identities and quantities of the chemicals present, among other things. Under Section 304 of EPCRA, an owner or operator of a facility must immediately notify the SERC and the community emergency coordinator for the LEPC in the affected area if an accidental release of a chemical that is an EHS occurs in an amount in excess of its reportable quantity from a facility where an EHS is produced, used, or stored. This information must be made available to the public. Section 311 of EPCRA generally requires that facility owners or operators submit an MSDS for each hazardous chemical present that exceeds an EPA-determined threshold level, or a list of such chemicals, to the LEPC, SERC, and the local fire department. For non-proprietary information, the act generally requires a LEPC to provide an MSDS to a member of the public on request. Again, whether a well site where hydraulic fracturing occurs would be subject to EPCRA's requirements would depend on the identities and quantities of the chemicals present, among other things. Under Section 312 of EPCRA, facility owners or operators must submit annual chemical inventory information for hazardous chemicals present at the facility in excess of an EPA-determined threshold level to the LEPC, SERC, and the local fire department. There are two types of information that may have to be submitted. If the facility owner or operator is required to report "Tier I information," then the inventory form must contain information about the maximum and average daily aggregate amounts of chemicals in each hazard category present at the facility during the prior year, as well as the general location of chemicals in each category. However, most states require the submission of "Tier II information." This information includes "Tier I information," as well as the chemical or common name of each hazardous chemical as listed on its MSDS and the location and manner of storage of the chemical at the facility. Tier II information for the prior calendar year for a particular facility must be made available to members of the public upon written request. A SERC or LEPC must disclose to the requester any non-proprietary information it possesses. If the SERC or LEPC lacks the information for a hazardous chemical, then it must request the information from the facility owner or operator and disclose the non-proprietary portions of it to the requester. Section 313 of EPCRA requires owners or operators of certain facilities to report information about the release into the environment of certain "toxic" chemicals from the facilities. This information must be disclosed to federal and state officials, who in turn disclose the non-proprietary details to the public via the Toxics Release Inventory (TRI) website. Generally, the reporting requirements apply to owners or operators of facilities with 10 or more full-time employees when the facilities fall under certain Standard Industrial Classification or North American Industry Classification System codes and manufactured, processed, or otherwise used a listed toxic chemical in excess of its threshold reporting amount during the applicable calendar year. Facilities used by the oil and gas extraction industry are generally not included in the industry codes required to report under the TRI. Section 313(b) allows EPA to add or delete industry codes as needed. In October 2012, Earthworks and several other environmental advocacy organizations asked EPA to require the oil and gas extraction industry to report the toxic chemicals it releases under the TRI program. When determining whether to add new industry groups, EPA has previously considered three factors: (1) Whether one or more listed toxic chemicals are reasonably anticipated to be present at facilities in that industry (chemical factor); (2) whether facilities within the candidate industry group 'manufacture,' 'process,' or 'otherwise use' EPCRA section 313 listed toxic chemicals (activity factor); and (3) whether addition of facilities within the candidate industry group reasonably can be anticipated to increase the information made available pursuant to EPCRA section 313 or to otherwise further the purposes of EPCRA section 313 (information factor). The Earthworks petitioners argued that the oil and gas extraction industry met the chemical factor because drilling, well development, and hydraulic fracturing at well sites use many chemicals listed on the TRI. With respect to the activity factor, the petitioners maintained that the industry manufactured, processed, and otherwise used TRI chemicals via well completions, well development, and hydraulic fracturing, among other processes. Finally, petitioners argued that the information factor was satisfied because existing federal and state disclosure laws were "inadequate." The petition is still under review. As the use of hydraulic fracturing and horizontal drilling to initiate production from oil and gas wells has increased, owners of property located near oil and gas operations have expressed concerns about the potential effects of these activities on the environment. Additionally, some worry that the proximity of oil and gas operations to their homes will cause a decline in the values of their properties. In response to these concerns, many local governments have increased their regulation of hydraulic fracturing and related oil and gas production activities. Some requirements imposed by local governments appear to be intended to regulate the land use aspects of oil and gas operations. However, other requirements have tended toward regulation of the technical aspects of oil and gas operations. In addition to raising questions about the relationship between federal and state authority, the increase in local regulation of hydraulic fracturing has led to questions about the relationship between state and local authority. Regulation of oil and gas operations is an area of mixed state and local concern. It implicates the state's interest in the safe and efficient development of its natural resources and the local government's interest in regulating land uses to protect the public from harm to property values, health, and the environment. In matters of mixed state and local concern, states retain authority over local governments, even when municipalities enjoy some degree of independence from the state as a result of "home rule" provisions. However, the Pennsylvania Supreme Court held that the state could not preempt municipal zoning restrictions when it would violate guarantees contained in the state's constitution. The question of state preemption of municipal land use and zoning powers arises when both state and local governments seek to regulate oil and gas production. Although the doctrine of preemption may differ among the states, most jurisdictions recognize three types of preemption: (1) express preemption, in which the express language of the state statute or regulation shows that the state intended to preempt all local control over regulation of a particular subject matter; (2) occupation of the field, in which the state's regulatory scheme is so comprehensive that it leaves the locality no room in which to regulate; and (3) conflict preemption, in which a local law is preempted to the extent that it conflicts with the application of the state law. When a state law expressly preempts requirements imposed on oil and gas operations by localities, state courts have engaged in statutory interpretation to determine the scope of the preemption. For example, in 2014 the New York Court of Appeals issued a decision finding that zoning restrictions enacted by two municipalities did not conflict with the state's mineral resource laws. The municipalities claimed that the zoning restrictions were valid exercises of the state's Home Rule law, which empowers local governments to pass laws for the "protection and enhancement of [their] physical and visual environment" and for the "government, protection, order, conduct, safety, health and well-being of persons or property therein," and that their exercise of this authority to restrict certain drilling practices was not preempted by the state's oil and gas law. The court agreed, finding that the preemption language in the state oil and gas law limited "only local laws that purport to regulate the actual operations of oil and gas activities, not zoning ordinances that restrict or prohibit certain land uses within town boundaries."  In the court's opinion, the new zoning restrictions "are directed at regulating land use generally and do not attempt to govern the details, procedures or operations of the oil and gas industries." As a result the court found that the local zoning restriction did not preempt the state's oil and gas laws. In the case of Robinson Township v. Commonwealth , a Pennsylvania appeals court considered a state law (Act 13) that expressly preempted local zoning laws. The court held that towns' substantive due process rights were violated by the state when Pennsylvania passed a law that required local governments to allow certain oil and gas facilities in all of their zoning districts, subject only to minor limitations such as setback requirements. Pennsylvania had argued that the law would advance the commonwealth's legitimate interest in the safe and efficient development of its oil and gas resources by eliminating differences in local zoning ordinances that had burdened the industry and its investors with expense and uncertainty. However, the court held that this mandate was irrational and an improper exercise of the state's police power because it allowed incompatible uses in zoning districts, and thus denied the town's substantive due process under the state constitution. The Pennsylvania Supreme Court subsequently affirmed the appeals court's holding that provisions of Act 13 preempting certain municipal zoning restrictions on oil and gas facilities were invalid under the Pennsylvania constitution. A West Virginia case illustrates the doctrine of field preemption in the oil and gas context. In Northeast Natural Energy, LLC v. City of Morgantown , a state court held that state law left no room for local regulation of oil and gas development and production. With regard to conflict preemption, state courts have considered whether the local requirement interferes with the state's regulatory scheme governing oil and gas development so as to result in an "operational conflict" with the state's objectives. Courts considering whether a particular local regulation is preempted under this test generally evaluate each requirement imposed by the regulation on a case-by-case basis to determine whether there is a conflict. In some instances, courts must examine not only what the local regulation requires on its face but also how the regulation is applied in practice by the local government. Under the operational conflicts test, the Colorado Supreme Court held that state law preempted a home rule city's total ban on oil and gas drilling . In July 2014, a Colorado district court held that state law preempted the city of Longmont's ban on hydraulic fracturing, stating that, "The operational conflict in this case is obvious. The [Colorado Oil and Gas Conservation] Commission permits hydraulic fracturing and Longmont prohibits it." Some states have tried to use alternative methods of accommodating joint state and local regulatory authority over oil and gas operations. Colorado offers one example. In a February 2012 executive order, Colorado Governor John Hickenlooper wrote that "proving operational conflict is an adversarial, cumbersome, time consuming, and expensive process." The governor created a task force to consider how local governments could coordinate their regulatory efforts with the state to avoid litigation. In April 2012, the task force issued a letter in which it wrote that its members had "determined that drawing bright lines between state and local jurisdictional authority was neither realistic nor productive." Members of the task force recommended that local governments enter into memoranda of understanding with operators and intergovernmental agreements with the Colorado Oil and Gas Conservation Commission (COGCC) to address local concerns. The task force also suggested that the local governments designate a representative to provide input to operators and the COGCC during the permitting process. Owners of property located near oil and gas operations have brought common law tort claims against companies that operate oil and gas wells and related infrastructure. Plaintiffs have claimed that damages have occurred as a result of hydraulic fracturing and related oil and gas operations, including contamination of land from drilling waste placed into pits on the plaintiffs' properties; noise and air pollution from natural gas compressor stations; contamination of water supplies; damage to a house allegedly caused by vibrations from nearby drilling activity; and personal injury. Common law causes of action brought under state tort law have included claims for nuisance, trespass, negligence, and strict liability, among others. Plaintiffs have sought monetary and, in some cases, injunctive relief, including remediation of contaminated property and medical monitoring. Often in these cases, some of the damages are alleged to have occurred underground or in the air above a plaintiff's property. As a result, plaintiffs may have difficulty demonstrating that the activities of the defendants caused them harm. In some cases, defendants have requested that courts enter modified case management orders (MCMOs) requiring plaintiffs to specifically make a prima facie showing of exposure, injury, and causation prior to the full discovery process by submitting expert opinions regarding the nature of the substances to which the plaintiffs were allegedly exposed; allowing access to the plaintiffs' medical records; and providing other supporting data. In Colorado, defendants initially succeeded in having one case dismissed after entry of such an order because the plaintiffs failed to "produce sufficient information and expert opinions upon which to establish the prima facie elements of their claims." However, a Colorado appeals court later reversed the trial court's entry of the order. In some cases courts have declined to enter MCMOs when there are a limited number of parties to the litigation and the claims are relatively simple. One question that arises when a court considers whether defendants are subject to strict liability for their operations is whether hydraulic fracturing and related oil and gas production activities are abnormally dangerous as a matter of law. Section 519 of the Restatement (Second) of Torts states that "[o]ne who carries on an abnormally dangerous activity is subject to liability for harm ... of another resulting from the activity, although he has exercised the utmost care to prevent the harm." In determining whether an activity is abnormally dangerous, courts generally consider six factors: (a) existence of a high degree of risk of some harm to the person, land or chattels of others; (b) likelihood that the harm that results from it will be great; (c) inability to eliminate the risk by the exercise of reasonable care; (d) extent to which the activity is not a matter of common usage; (e) inappropriateness of the activity to the place where it is carried on; and (f) extent to which its value to the community is outweighed by its dangerous attributes. It appears that few courts have considered the issue. In an April 2014 summary judgment order, a federal district court judge wrote that "based on an analysis of the six factors set forth in the Restatement (Second) of Torts ... hydraulic fracturing does not legally qualify as an ultra-hazardous activity giving rise to strict tort liability." In another case, a court speculated that it may be difficult for plaintiffs to meet factors (d), (e), and (f) in the Restatement definition at the summary judgment stage. With respect to trespass claims, the Texas Supreme Court considered whether the subsurface hydraulic fracturing of a natural gas well that extended into an adjacent property was a trespass "for which the value of gas drained as a result may be recovered as damages." The court held that such damages could not be recovered because of the rule of capture, which "gives a mineral rights owner title to the oil and gas produced from a lawful well bottomed on the property, even if the oil and gas flowed to the well from beneath another owner's tract." In another case, plaintiffs argued that the defendant committed a trespass when it engaged in acts that were not necessary to the extraction of minerals on the plaintiff's surface property. Plaintiffs have also argued that emissions of air pollution over their land constitute a trespass. As discussed previously, regulation of practices associated with oil and gas exploration and production is primarily left to the states and municipalities that have overseen the practice for decades. Federal regulation of these practices is usually limited to the realm of environmental impacts. This, however, is not the case when it comes to oil and gas exploration and production on federal lands. The Bureau of Land Management (BLM), an agency within the Department of the Interior, oversees leasing and permitting for oil and gas on federal lands. On March 26, 2015, BLM promulgated a hydraulic fracturing rule applicable to oil and gas operations on federal and Indian lands. However, the final rule was set aside by the U.S. District Court for the District of Wyoming, and this decision is currently under appeal (see below). The rule revised BLM's oil and gas rules related to hydraulic fracturing, which were promulgated in 1982 and last revised in 1988, before the widespread use of hydraulic fracturing and horizontal drilling. BLM estimated that the rule would affect roughly 2,800 hydraulic fracturing operations each year; however, based on previous levels of activity on federal lands, the rule could affect as many as 3,800 operations annually, and total compliance costs could reach $45 million annually. The rule would require operators that plan to employ fracking as part of an oil or natural gas drilling operation on federal or Indian land to document to BLM compliance with the following requirements: Submit a plan with detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures; Design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate usable water, monitor the cementing operations during well construction, and take remedial action if there are indications that the cementing is inadequate; Perform a successful Mechanical Integrity Test prior to the fracking operation; Monitor well pressure during the fracking operation and cease operations if it exceeds 500 pounds per square inch; Manage the recovered "flowback" fluids in above-ground storage tanks that meet certain specifications; and Disclose the chemicals used in the fracking operation to the BLM and to the public (with limited exceptions for trade secrets as demonstrated through an affidavit). The Final Rule also would authorize st ates and tribes to work with BLM to craft variances from specific regulatory provisions that would allow compliance with state or tribal requirements to be accepted as compliance with the BLM rule if the state or tribal provision is at least as protective as the pertinent BLM provision . After publication of the Final Rule, a number of states and organizations brought an action in the U.S. District Court for the District of Wyoming seeking to enjoin its enforcement. These petitioners argued that BLM lacked statutory authority to regulate hydraulic fracturing, citing the 2005 amendments to the SDWA discussed above as evidence of congressional intent to exclude hydraulic fracturing from federal oversight unless diesel fuels are involved. The court found that the petitioners had demonstrated the likelihood of success on the merits, and thus enjoined enforcement of the BLM Final Rule. Nine months later the court ruled on the merits and set aside the BLM Final Rule. The federal government appealed the decision to the U.S. Court of Appeals for the Tenth Circuit. The government will likely argue that its broad authority to regulate activities on federal lands under the Federal Land Policy and Management Act, including the power to "take any action necessary to prevent unnecessary or undue degradation of the lands," provides sufficient basis for the promulgation of the BLM Final Rule. The government also will likely cite its authority under Section 226(g) of the Mineral Leasing Act to "regulate all surface-disturbing activities conducted pursuant to any lease issued under this chapter." The Tenth Circuit's decision on this matter will set an important precedent with respect to the federal government's ability to regulate hydraulic fracturing and potentially other environmental concerns related to oil and natural gas exploration and production on federal lands. On February 8, 2016, the BLM proposed a rule to update standards to reduce venting and flaring from oil and gas production activities on onshore federal and Indian leases. The proposal would clarify when produced gas lost through venting, flaring, or leaks is subject to royalties and would replace provisions governing venting, flaring, and royalty-free use of gas issued in 1980. The proposed rule would limit natural gas venting to specified circumstances and also limit the rate of routine flaring of natural gas associated with oil well development. BLM expects to issue a final venting and flaring rule in late 2016. In the 114 th Congress, several bills propose to expand federal regulation of hydraulic fracturing activities, while others would limit federal involvement. This section discusses some of this legislation. The Fracturing Responsibility and Awareness of Chemicals Act of 2015 (FRAC Act) has been introduced in the House ( H.R. 1482 ) and the Senate ( S. 785 ). The bills would amend the SDWA to (1) require disclosure of the chemicals used in the fracturing process, and (2) repeal the hydraulic fracturing exemption established in EPAct 2005, and amend the term "underground injection" to include the injection of fluids used in hydraulic fracturing operations, thus authorizing EPA to regulate this process under the SDWA. Additionally, S. 785 would authorize states to seek primary enforcement authority for hydraulic fracturing operations, regardless of whether the state had obtained primacy for other types of UIC wells, including Class II wells. The Safe Hydration is An American Right in Energy Development Act of 2015 ( H.R. 1515 ) also would amend the SDWA to create a new prohibition on fracking unless the party conducting the fracking operations agrees to comply with new testing and data reporting requirements. Legislation also has been introduced to require baseline and follow-up testing of potable groundwater in the vicinity of hydraulic fracturing operations. H.R. 1515 , the Safe Hydration is an American Right in Energy Development Act of 2015, would amend the SDWA to prohibit hydraulic fracturing unless the person proposing to conduct the fracturing operations agreed to testing and reporting requirements regarding underground sources of drinking water. H.R. 1515 would require testing prior to, during, and after hydraulic fracturing operations. Testing would be required for any substance EPA determines would indicate damage associated with hydraulic fracturing operations. The bill also would require EPA to post on its website all test results, searchable by zip code. H.R. 1647 and S. 15 , the Protecting States' Rights to Promote American Energy Security Act, would amend the Mineral Leasing Act to prohibit the Department of the Interior from enforcing any federal regulation, guidance, or permit requirement regarding hydraulic fracturing relating to oil, gas, or geothermal production activities on or under any land in any state that has regulations, guidance, or permit requirements for hydraulic fracturing. Although this language is broadly applicable to any federal regulation, guidance, and permit requirements "regarding hydraulic fracturing," the prohibition on enforcement applies only to the Department of the Interior, and therefore would presumably impact only hydraulic fracturing operations on lands managed by the depart ment. The bill also would require the Department of the Interior to defer to state regulations, permitting, and guidance for all activities related to hydraulic fracturing relating to oil, gas, or geothermal production activities on federal land regardless of whether those rules were duplicative, more or less restrictive, or did not meet federal guidelines. The House version of the bill also would direct the Comptroller General to conduct a study "examining the economic benefits of domestic shale oil and gas production resulting from the process of hydraulic fracturing." Other legislation has also been introduced in the 114 th Congress to limit the authority of the Department of the Interior to regulate hydraulic fracturing on federal and Indian lands. Environmental statutes enforced by EPA contain several key exemptions for hydraulic fracturing and related oil and gas production activities. For example, an amendment to the SDWA passed as a part of the Energy Policy Act of 2005 clarified that the underground injection control requirements found in the SDWA do not apply to hydraulic fracturing, although the exclusion does not extend to the use of diesel fuel in hydraulic fracturing operations. In addition, drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy are exempt from regulation as hazardous wastes under Subtitle C of RCRA. Under EPCRA, facilities used by the oil and gas extraction industry are generally not included in the industry codes required to report under the Toxics Release Inventory (TRI). Environmental groups have filed petitions seeking regulation of hydraulic fracturing and related activities under various environmental laws enforced by EPA. In September 2010, an environmental advocacy group filed a petition seeking to have EPA regulate drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy as hazardous waste under Subtitle C of RCRA. In August 2011, environmental advocacy organizations petitioned EPA to promulgate rules under Section 4 and Section 8 of TSCA for chemical substances and mixtures used in oil and gas exploration or production. In October 2012, several environmental advocacy organizations asked EPA to require the oil and gas extraction industry to report the toxic chemicals it releases under the TRI program. Regulation of hydraulic fracturing by local governments has raised questions about state preemption of municipal land use and zoning powers. Courts in a few states have ruled that local governments may regulate where drilling occurs but not how it occurs. In addition, owners of property located near oil and gas operations have brought common law state tort claims against operators, including claims for negligence, strict liability, nuisance, and trespass to land. Although this litigation is still in its early stages, it appears that courts have already faced questions about causation; whether hydraulic fracturing is an abnormally dangerous activity; and whether hydraulic fracturing may constitute a subsurface trespass to land. A recent federal district court decision invalidated BLM's adoption of safety and disclosure requirements for hydraulic fracturing on federal lands, although an appeal of that decision is pending.

Summary: Hydraulic fracturing is a technique used to recover oil and natural gas from underground low permeability rock formations, such as shales and other unconventional formations. Its use along with horizontal drilling has been responsible for an increase in estimated U.S. oil and natural gas reserves. Hydraulic fracturing and related oil and gas production activities have been controversial because of their potential effects on public health and the environment. Several environmental statutes have implications for the regulation of hydraulic fracturing by the federal government and states. An amendment to the Safe Drinking Water Act (SDWA) passed as a part of the Energy Policy Act of 2005 (EPAct 2005) clarified that the Underground Injection Control (UIC) requirements found in the SDWA do not apply to hydraulic fracturing, although the exclusion does not extend to the use of diesel fuel in hydraulic fracturing operations. The underground injection of wastewater generated during oil and gas production (including hydraulic fracturing) does require a UIC permit under the SDWA, as do injections for enhanced oil and gas recovery operations. Under the Clean Water Act (CWA), parties seeking to discharge produced water may have to apply for a permit under the National Pollutant Discharge Elimination System. Under the Clean Air Act (CAA), the Environmental Protection Agency (EPA) has issued new rules covering emissions of volatile organic compounds from hydraulic fracturing operations. Provisions of the Resource Conservation and Recovery Act (RCRA) exempt drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy from regulation as hazardous wastes under Subtitle C of RCRA. However, these wastes are subject to other federal laws (such as the SDWA and the CWA), as well as to state requirements. Facility owners and operators and other potentially responsible parties could potentially face liability under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) for cleanup costs, natural resource damages, and the costs of federal public health studies, if hydraulic fracturing results in the release of hazardous substances at or under the surface in a manner that may endanger public health or the environment. The National Environmental Policy Act (NEPA) requires federal agencies to consider the environmental impacts of proposed federal actions before proceeding with them. An agency would be obligated to consider the impacts of an action that involves hydraulic fracturing if that action takes place on federal lands or when there is otherwise a sufficient federal nexus to hydraulic fracturing. Under the Emergency Planning and Community Right-to-Know Act (EPCRA), owners or operators of facilities where certain hazardous hydraulic fracturing chemicals are present above certain thresholds may have to comply with emergency planning requirements; emergency release notification obligations; and hazardous chemical storage reporting requirements. In August 2011, environmental groups petitioned EPA to promulgate rules under the Toxic Substances Control Act (TSCA) for chemical substances and mixtures used in oil and gas exploration or production. While the federal government's oversight of hydraulic fracturing generally is limited to protection of the environment and public health pursuant to the aforementioned statutes, it does have some authority to regulate oil and natural gas exploration and production on federal lands. Whether this authority extends to particular regulations governing hydraulic fracturing is currently in dispute. The Bureau of Land Management published a rule on hydraulic fracturing on federal and Indian lands in March 2015; however, the rule was struck down by a U.S. District Court in June 2016. The matter is currently on appeal. At the state level, hydraulic fracturing tort litigation has raised questions about causation; whether hydraulic fracturing is an abnormally dangerous activity; and whether hydraulic fracturing may constitute a subsurface trespass to land. Also, several municipalities have attempted to ban hydraulic fracturing through zoning restrictions and other local laws, creating potential conflicts with oil and gas industry regulation at the state level.