Oil and gas reservoirs vary in their geological makeup, location, and size. Regardless of the reservoir, unconventional oil and gas development involves a number of activities, many of which are also conducted in conventional oil and gas drilling. This section describes the types and locations of oil and gas reservoirs and the key stages of oil and gas development. Oil and natural gas are found in a variety of geologic formations. In conventional reservoirs, oil and gas can flow relatively easily through a series of pores in the rock to the well. Shale and tight sandstone formations generally have low permeability and therefore do not allow oil and gas to easily flow to the well. Shale and tight sandstone formations can occur at varying depths, including thousands of feet beneath the surface. For example, the Bakken shale formation in North Dakota and Montana ranges from 4,500 to 11,000 feet beneath the surface. Coalbed methane formations, often located at shallow depths of several hundred to 3,000 feet, are generally formations through which gas can flow more freely; however, capturing the gas requires operators to pump water out of the coal formation to reduce the pressure and allow the gas to flow. Shale, tight sandstone, and coalbed methane formations are located within basins, which are large-scale geological depressions, often hundreds of miles across, which also may contain other oil and gas resources. There is no clear and consistently agreed upon distinction between conventional and unconventional oil and gas, but unconventional sources generally require more complex and expensive technologies for production, such as the combination of horizontal drilling and multiple hydraulic fractures. See figure 1 for a depiction of conventional and unconventional reservoirs. Unconventional reservoirs are located throughout the continental United States on both private lands and federal lands that are administered by BLM, Forest Service, Park Service, and FWS (see fig. 2). Developing unconventional reservoirs involves a variety of activities, many of which are also conducted in conventional oil and gas drilling. Siting and site preparation. The operator identifies a location for the well and prepares the area of land where drilling will take place—referred to as a well pad. In some cases, the operator will build new access roads to transport equipment to the well pad or install new pipelines to transport the oil or gas that is produced. In addition, the operator will clear vegetation from the area and may place storage tanks (also called vessels) or construct pits on the well pad for temporarily storing fluids (see fig. 3). In some cases, multiple wells will be located on a single well pad. Drilling, casing, and cementing. The operator conducts several phases of drilling to install multiple layers of steel pipe—called casing—and cement the casing in place. The layers of steel casing are intended to isolate the internal portion of the well from the outlying geological formations, which may include underground drinking water supplies. As the well is drilled deeper, progressively narrower casing is inserted further down the well and cemented in place. Throughout the drilling process, a special lubricant called drilling fluid, or drilling mud, is circulated down the well to lubricate the drilling assembly and carry drill cuttings (essentially rock fragments created during drilling) back to the surface. After vertical drilling is complete, horizontal drilling is conducted by slowly angling the drill bit until it is drilling horizontally. Horizontal stretches of the well typically range from 2,000 feet to 6,000 feet long but can be as long as 12,000 feet in some cases. Hydraulic fracturing. Operators sequentially perforate steel casing and pump a fluid mixture down the well and into the target formation at high enough pressure to cause the rock within the target formation to fracture. The sequential fracturing of a well can use between 2 million and 5.6 million gallons of water. Operators add a proppant, such as sand, to the mixture to keep the fractures open despite the large pressure of the overlying rock. About 98 percent of the fluid mixture used in hydraulic fracturing is water and sand, according to a report about shale gas development by the Ground Water Protection Council. The fluid mixture—or hydraulic fracturing fluid—generally contains a number of chemical additives, each of which is designed to serve a particular purpose. For example, operators may use a friction reducer to minimize friction between the fluid and the pipe, acid to help dissolve minerals and initiate cracks in the rock, and a biocide to eliminate bacteria in the water that cause corrosion. The number of chemicals used and their concentrations depend on the particular conditions of the well. After hydraulic fracturing, a mixture of fluids, gases, and dissolved solids flows to the surface (flowback), after which production can begin, and the well is said to have been completed. Operators use hydraulic fracturing in many shale and tight sandstone formations (see fig. 4). Some coalbed methane wells are hydraulically fractured (see fig. 5), but operators may use different combinations of water, sand, and chemicals than with other unconventional wells. In addition, operators must “dewater” coalbed methane formations in order to get the natural gas to begin flowing—a process that can generate large amounts of water. Well plugging. Once a well is no longer producing economically, the operator typically plugs the well with cement to prevent fluid migration from outlying formations into the well and to prevent downward drainage from inside the well. In some cases, wells may be temporarily plugged so that the operator has the option of reopening the well in the future. In some states with a long history of oil and gas development, wells drilled decades ago may not have been properly plugged—or the plug may have deteriorated. Site reclamation. Once the well is plugged, the operator takes steps to restore the site to make it acceptable for specific uses, such as farming. For example, reclamation may involve removing equipment from the well pad, closing pits, backfilling soil, and restoring vegetation. Sometimes, when a well starts production, operators reclaim the portions of a site affected by the initial drilling activity. Waste management and disposal. Throughout the drilling, hydraulic fracturing, and subsequent production activities, operators must manage and dispose of several types of waste. For example, operators must manage produced water, which, for purposes of this report includes flowback water—the water, proppant, and chemicals used for hydraulic fracturing—as well as water that occurs naturally in the oil- or gas-bearing geological formation. Operators temporarily store produced water in tanks or pits, and some operators may recycle it for reuse in subsequent hydraulic fracturing. Options for permanently disposing of produced water vary and may include, for example, injecting it underground into wells Operators also generate solid wastes designated for such purposes. such as drill cuttings and could potentially generate small quantities of hazardous waste. See table 1 for additional methods for managing and disposing of waste. We recently issued a report on the quantity, quality, and management of water produced during oil and gas production. See GAO, Energy-Water Nexus: Information on the Quantity, Quality, and Management of Water Produced during Oil and Gas Production, GAO-12-156 (Washington, D.C.: Jan. 9, 2012). Requirements from eight federal laws apply to the development of oil and gas from unconventional sources. In large part, the same requirements apply to conventional and unconventional oil and gas development. There are exemptions or limitations in regulatory coverage for preventive programs authorized by six of these laws, though EPA generally retains its authorities under federal environmental and public health laws to respond to environmental contamination. States may have regulatory programs related to some of these exemptions or limitations in federal regulatory coverage; state requirements are discussed later in this report. Parts of the following eight federal environmental and public health laws apply to unconventional oil and gas development: Safe Drinking Water Act (SDWA) Clean Water Act (CWA) Clean Air Act (CAA) Resource Conservation and Recovery Act (RCRA) Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) Emergency Planning and Community Right-to-Know Act (EPCRA) Toxic Substances Control Act (TSCA) Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA) There are exemptions or limitations in regulatory coverage related to the first six laws listed above. In large part, the same requirements apply to conventional and unconventional oil and gas development. This section discusses each of these laws in brief; for more details about seven of these laws, please see appendixes II through VIII. SDWA is the main federal law that ensures the quality of drinking water.Two key aspects of SDWA that are part of the regulatory framework governing unconventional oil and gas development are the Underground Injection Control (UIC) program and the imminent and substantial endangerment provision. Under SDWA, EPA regulates the injection of fluids underground through its UIC program, including the injection of produced water from oil and gas development. The UIC program protects underground sources of drinking water by setting and enforcing standards for siting, constructing, and operating injection wells. Injection wells in the UIC program fall into six different categories based on the types of fluids being injected. The wells used to manage fluids associated with oil and gas production, including produced water, are Class II wells. EPA officials estimate there are approximately 151,000 permitted Class II UIC wells in operation in the United States. Two types of wells account for nearly all the Class II UIC wells in the United States (see fig. 7), as follows: Enhanced recovery wells inject produced water or other fluids or gases into oil- or gas-producing formations to increase the pressure in the formation and force additional oil or gas out of nearby producing wells. EPA documents estimate that about 80 percent of Class II wells are enhanced recovery wells. Disposal wells inject produced water or other fluids associated with oil and gas production into formations that are intended to hold the fluids permanently. EPA documents estimate that about 20 percent of Class II wells are disposal wells. UIC regulations include minimum federal requirements for most Class II UIC wells; these requirements are generally applicable only where EPA implements the program. For example, for most new Class II UIC wells, an operator must, among other things (1) obtain a permit from EPA or a state, (2) demonstrate that casing and cementing are adequate, and (3) pass an integrity test prior to beginning operation and at least once every 5 years. In addition, when proposing a new Class II UIC well, an operator must identify any existing water or abandoned production or injection wells generally within one-quarter mile of the proposed well. During the life of the Class II UIC well, the operator has to comply with monitoring requirements, including tracking the injection pressure, rate of injection, and volume of fluid injected. SDWA authorizes EPA to approve by rule a state to be the primary enforcement responsibility—called primacy—for the UIC program, which means that a state assumes responsibility for implementing its program, including permitting and monitoring UIC wells. Generally, to be approved for primacy, state programs must be at least as stringent as the federal program for each of the well classes for which primacy is sought; however, SDWA also includes alternative provisions for primacy related to Class II wells whereby, in lieu of adopting requirements consistent with EPA’s Class II regulations, a state can demonstrate to EPA that its program is effective in preventing endangerment of underground sources of drinking water. Five of the six states in our review (Colorado, North Dakota, Ohio, Texas, and Wyoming) have been granted primacy for Class II wells under the alternative provisions. Pennsylvania has not applied for primacy, so EPA directly implements the program there. Please see appendix IX for more information about UIC requirements in the six states in our review. As discussed, the UIC program regulates the injection of fluids underground. Historically, the UIC program was not used to regulate hydraulic fracturing, even though fracturing entails the injection of fluid underground. In 1994, in light of concerns that hydraulic fracturing of coalbed methane wells threatened drinking water, citizens petitioned EPA to withdraw its approval of Alabama’s Class II UIC program because the state failed to regulate hydraulic fracturing. The case ended up before the United States Court of Appeals for the Eleventh Circuit, which held that the definition of underground injection included hydraulic fracturing. The court’s decision was made in the context of hydraulic fracturing of a coalbed methane formation in Alabama but raised questions about whether hydraulic fracturing would be included in UIC programs nationwide. UIC regulations at the time and now provide that ‘‘ny underground injection, except into a well authorized by rule or except as authorized by permit issued under the UIC program, is prohibited.’’ 40 C.F.R. 144.11 (2005) (2011). The Energy Policy Act provision did not exempt injections of diesel fuel during hydraulic fracturing from the definition of underground injection. EPA’s position is that underground injection of diesel fuel as part of hydraulic fracturing requires a UIC permit or authorization by rule. program. The guidance is directed at EPA permit writers in states where EPA directly implements the program; the guidance does not address state-run UIC programs (including five of the six states in our review). EPA’s draft guidance is applicable to any oil and gas wells using diesel in hydraulic fracturing (not just coalbed methane wells). The draft guidance provides recommendations related to permit applications, area of review (for other nearby wells), well construction, permit duration, and well closure. SDWA also gives EPA authority to issue orders when the agency receives information about present or likely contamination of a public water system or an underground source of drinking water that may present an imminent and substantial endangerment to human health. In December 2010, EPA used this authority to issue an emergency administrative order to an operator in Texas alleging that the company’s oil and gas production facilities near Fort Worth, Texas, caused or contributed to methane contamination in two nearby private drinking water wells. EPA contended that this methane contamination posed an explosion hazard and therefore was an imminent and substantial threat to human health. EPA’s order required the operator to take six actions, specifically: (1) notify EPA whether it intended to comply with the order, (2) provide replacement water supplies to landowners, (3) install meters to monitor for the risk of explosion at the affected homes, (4) conduct a survey of any additional private water wells within 3,000 feet of the oil and gas production facilities, (5) develop a plan to conduct soil and indoor air monitoring at the affected dwellings, and (6) develop a plan to investigate how methane flowed into the aquifer and private drinking water wells. The operator disputed the validity of EPA’s order and noted that the order does not provide any way for the company to challenge EPA’s findings. Nevertheless, the operator implemented the first three actions EPA listed in the order. In January 2011, EPA sued the operator in federal district court, seeking to enforce the remaining three provisions of the order. In March 2011, the regulatory agency that oversees oil and gas development in Texas held a hearing examining the operator’s possible role in the contamination of the water wells and issued an opinion in which it concluded that the operator had not caused the contamination. In March 2012, EPA withdrew the original emergency administrative order, and the operator agreed to continue monitoring 20 private water wells near its production sites for 1 year. According to EPA officials, resolving the lawsuit allows the agency to shift its focus away from litigation and toward a joint EPA-operator effort in monitoring. For more details about SDWA, please see appendix II. To restore and maintain the nation’s waters, CWA authorizes EPA to, among other things, regulate pollutant discharges and respond to spills affecting rivers and streams. Several aspects of CWA are applicable to oil and gas well pad sites, but statutory exemptions limit EPA’s regulatory authority. Several elements of CWA and implementing regulations are relevant to oil and gas development from onshore unconventional sources. First, the National Pollutant Discharge Elimination System (NPDES) program regulates industrial sites’ wastewater and stormwater discharges to waters of the United States (surface waters). Second, spill reporting and spill prevention and response planning requirements pertain to certain threats to U.S. navigable waters and adjoining shorelines. In addition, under certain circumstances, EPA has response authorities; for example, it can generally bring suit or take other actions to protect the public health and welfare from actual or threatened discharges of oil or hazardous substances to U.S. navigable waters and adjoining shorelines. EPA’s NPDES program limits the types and amounts of pollutants that industrial sites, industrial wastewater treatment facilities, and municipal wastewater treatment facilities (often called publicly-owned treatment works or POTWs) can discharge into the nation’s surface waters by requiring these facilities to have and comply with permits listing pollutants and their discharge limits. As required by CWA, EPA develops effluent limitations for certain industrial categories based on available control technologies and other factors to prevent or treat the discharge. EPA established multiple subcategories for the oil and gas industry; relevant here are: (1) onshore, (2) agricultural and wildlife water use, and (3) stripper wells—that is, wells that produce relatively small amounts of oil. For the onshore and agricultural and wildlife water use subcategories, EPA established effluent limitations guidelines for direct dischargers that establish minimum requirements to be used by EPA and state NPDES permit writers. Specifically, the onshore subcategory has a zero discharge limit for discharges to surface waters, meaning that no direct discharges to surface waters are allowed. EPA documents explain that this is because there are technologies available—such as underground injection—to dispose of produced water generated at oil and gas well sites without directly discharging them to surface waters. Given that the NPDES permit limit would be “no discharge,” EPA officials said that they were unaware of any instances in which operators had applied for these permits. EPA officials did mention, however, an instance in which an operator discharged produced water to a stream and was fined by EPA under provisions in CWA. For example, in 2011, EPA Region 6 assessed an administrative civil penalty against a company managing an oil production facility in Oklahoma for discharging brine and produced water to a nearby stream. The company ultimately agreed to pay a $1,500 fine and conduct an environmental project, which included extensive soil remediation near the facilities. Effluent limitations guidelines for the agricultural and wildlife water use subcategory cover a geographical subset of wells in the westthe quality of produced water from the wells is good enough for watering crops and livestock or to support wildlife in streams. The effluent limitations guideline for this subcategory allows such discharges of produced water for these purposes as long as the water meets a minimum quality standard for oil and grease. EPA officials identified 349 facilities with discharge permits in this subcategory. Officials also stated in which that individual permits may contain limits for pollutants other than oil and grease. EPA has not established effluent limitations guidelines for stripper wells, and EPA and state NPDES permit writers currently use their best professional judgment to determine the effluent limits for permits on a case-by-case basis. EPA explained in a 1976 Federal Register notice that unacceptable economic impacts would occur if the agency developed effluent limitations guidelines for stripper wells and that the agency could revisit this decision at a later date. In July 2012, EPA officials confirmed that the agency currently has no plans to develop an effluent limitations guideline for stripper wells. EPA also has not established effluent limitations guidelines for coalbed methane wells and EPA and state NPDES permit writers currently use their best professional judgment to determine the effluent limits for permits on a case-by-case basis. EPA officials explained that the process of extracting natural gas from coalbed methane formations is fundamentally different from traditional oil and gas development, partly because of the large volume of water that must be removed from the coalbed methane formation prior to production. Given these differences, coalbed methane wells are not included in any of EPA’s current subcategories. EPA announced in 2011 that, based on a multiyear study of the coalbed methane industry, the agency will develop effluent limitations guidelines for produced water discharges from coalbed methane formations. In the course of developing these guidelines, EPA officials told us that they will analyze the economic feasibility of each of the available technologies for disposing of the large volumes of produced water from coalbed methane wells and that EPA plans to issue proposed guidelines in the summer of 2013. In addition to setting effluent limitations guidelines for direct discharges of pollutants to surface waters, CWA requires EPA to develop regulations that establish pretreatment standards. These standards apply when wastewater is sent to a POTW before being discharged to surface waters, and the standards must prevent the discharge of any pollutant that would interfere with, or pass through, the POTW. To date, EPA has not set pretreatment standards specifically for produced water, though there are some general requirements; for example, discharges to POTWs cannot cause the POTW to violate its NPDES permit or interfere with the treatment process. In October 2011, EPA announced its intention to develop pretreatment standards specific to the produced water from shale gas development. EPA officials told us that the agency intends to conduct a survey and use other methods to collect additional data and information to support this rulemaking. Officials expect to publish the first Federal Register notice about the survey by the end of 2012 and to publish a proposed rule in 2014. In addition to CWA’s requirement for NPDES permits for discharges from industrial sites, the 1987 Water Quality Act amended CWA to establish a specific program for regulating stormwater discharges, such as those related to rainstorms, though oil and gas well sites are largely exempt from these requirements. EPA generally requires that facilities get NPDES permits for discharges of stormwater associated with industrial and construction activities, but the Water Quality Act of 1987 specifically exempted oil and gas production sites from permit requirements for stormwater discharges, as long as the stormwater was not contaminated by, for example, raw materials or waste products. exemption and EPA’s implementing regulations, oil and gas well sites are only required to get NPDES permits for stormwater discharges if the facility has had a discharge of contaminated stormwater that includes a reportable quantity of a pollutant or contributes to the violation of a water quality standard. The 2005 Energy Policy Act expanded the language of the exemption to include construction activities at oil and gas well sites, meaning that uncontaminated stormwater discharges from oil and gas construction sites also do not require NPDES permits. So while other industries must generally obtain NPDES permits for construction activities that disturb an acre or more of land, operators of oil and gas well sites are generally not required to do so. The 1987 Water Quality Act also exempted oil and gas processing, treatment, and transmission facilities from permit requirements for stormwater discharges. National Response Center, which is managed by the U.S. Coast Guard and serves as the sole federal point of contact for reporting oil and chemical spills in the United States. Oil discharges must be reported if they cause a film or sheen on the surface of the water or shorelines or if they violate water quality standards. The National Response Center shares information about spills with other agencies, including EPA Regional offices, which allows EPA to follow up on reported spills, as appropriate. CWA also authorized spill prevention and response planning requirements as promulgated in the Spill Prevention, Control, and Countermeasure (SPCC) rule. Facilities that are subject to SPCC rules are required to prepare and implement a plan describing, among other things, how they will control, contain, clean up, and mitigate the effects of any oil discharges that occur. Onshore oil and gas well sites, among others, are subject to this rule if they have total aboveground oil storage capacity greater than 1,320 gallons and could reasonably be expected, based on location, to discharge oil into U.S. navigable waters or on adjoining shorelines. The amount of oil storage capacity at oil and gas well sites tends to vary based on whether the well is being drilled, hydraulically fractured, or has entered production. For example, during drilling at well sites located near these waters, operators generally have to comply with SPCC requirements if fuel tanks for the drilling rig exceed the 1,320 gallon threshold. According to EPA officials, nearly all drill rigs have fuel tanks larger than 1,320 gallons, and so most well sites are subject to the SPCC rule during drilling if they are near these waters. Oil and gas well sites that are subject to the SPCC rule were required to comply by November 2011 or before starting operations. In accordance with CWA, EPA directly administers the SPCC program rather than delegating authority to states. EPA regulations generally do not require facilities to report SPCC information to EPA, including whether or not they are regulated. As a result, EPA does not know the universe of SPCC-regulated facilities. To ensure that regulated facilities are meeting SPCC requirements, EPA Regional personnel may inspect these facilities to evaluate their compliance. EPA officials said that some of these inspections were conducted as follow-up after spills were reported and that most inspections are conducted during the production phase, since drilling and hydraulic fracturing are of much shorter durations, making it difficult for inspectors to visit these sites during those times. According to EPA officials, Regional personnel inspected 120 oil and gas well sites nationwide in fiscal year 2011 and found noncompliance at 105 of these sites. These violations ranged from paperwork inconsistencies to more serious violations, such as a lack of secondary containment around stored oil or failure to implement an SPCC plan (though EPA officials were unable to specifically quantify the number of more serious violations). EPA officials said that EPA has addressed some of the 105 violations through enforcement actions. CWA also provides EPA with authorities to address the discharge of pollutants and to address actual or threatened discharges of oil or hazardous substances in certain circumstances. For example, under one provision, EPA has the authority to address actual or threatened discharges of oil or hazardous substances into U.S. navigable waters or on adjoining shorelines upon a determination that there may be an imminent and substantial threat to the public health or welfare of the United States, by bringing suit or taking other action, including issuing administrative orders that may be necessary to protect public health and welfare. Under another provision, EPA has authority to obtain records and access to facilities, among other things, in order to determine if a person is violating certain CWA requirements. For example, EPA conducted initial investigations in Bradford County, Pennsylvania, following a 2011 spill of hydraulic fracturing and other fluids that entered a stream. Citing its authority under CWA and other laws,from the operator about the incident, including information about the chemicals involved and the environmental effects of the spill. Meanwhile, the Pennsylvania Department of Environmental Protection signed a consent order and agreement with the operator in 2012 that required the operator to pay fines and implement a monitoring plan for the affected stream. For more details about CWA, please see appendix III. CAA, a federal law that regulates air pollution from mobile and stationary sources, was enacted to improve and protect the quality of the nation’s air. Under CAA, EPA sets national ambient air quality standards for the six criteria pollutants––ground level ozone, carbon monoxide, particulate matter, sulfur dioxide, nitrogen oxides, and lead––at levels it determines are necessary to protect public health and welfare. States then develop state implementation plans (SIP) to establish how the state will attain air quality standards, through regulation, permits, policies, and other means. States must obtain EPA approval for SIPs; if a SIP is not acceptable, EPA may assume responsibility for implementing and enforcing CAA in that state. CAA also authorizes EPA to regulate emissions of hazardous air pollutants, such as benzene. In addition, under CAA, EPA requires reporting of greenhouse gas emissions from a variety of sources, including oil and gas wells. In accordance with CAA, EPA has progressively implemented more stringent diesel emissions standards to lower the amount of key pollutants from mobile diesel-powered engines since 1984. These standards apply to a variety of on- and off-road diesel-powered engines, including trucks used in the oil and gas industry to move materials to and from well sites and compressors used to drill and hydraulically fracture wells. Diesel exhaust contains nitrogen oxides and particulate matter. Emissions standards may set limits on the amount of pollution a vehicle or engine can emit or establish requirements about how the vehicle or engine must be maintained or operated, and generally apply to new vehicles. For example, the most recent emissions standards for construction equipment began to take effect in 2008 and required a 95 percent reduction in nitrogen oxides and a 90 percent reduction in particulate matter from previous standards. EPA estimates that millions of older mobile sources—including on-road and off-road engines and vehicles—remain in use. It is projected that over time, older sources will be taken out of use and be replaced by the lower-emission vehicles, ultimately reducing emissions from mobile sources. New Source Performance Standards (NSPS) apply to new stationary facilities or modifications to stationary facilities that result in increases in air emissions and focus on criteria air pollutants or their precursors. For the oil and gas industry, the key pollutant is volatile organic compounds, a precursor to ground level ozone formation. Prior to 2012, EPA’s NSPS were unlikely to affect oil and gas well sites because (1) EPA had not promulgated standards directly targeting well sites and (2) to the extent that EPA promulgated standards for equipment that may be located at well sites, the capacity of equipment located at well sites was generally too low to trigger the requirement. For example, in 1987, EPA issued NSPS for storage vessels containing petroleum liquids; however, the standards apply only to tanks above a certain size, and EPA officials said that most storage tanks at oil and gas sites are below the threshold. In April 2012, EPA promulgated NSPS for the oil and natural gas production industry which, when fully phased-in by 2015, will require reductions of volatile organic compound emissions at oil and gas well sites, including wells using hydraulic fracturing. Specifically, these new standards are related to pneumatic controllers, well completions, and certain storage vessels as follows: Pneumatic controllers. According to EPA, when pneumatic controllers are powered by natural gas, they may release natural gas and volatile organic compounds during normal operations. The new standards set limits for the amount of gas (as a surrogate for volatile organic compound emissions) that new and modified pneumatic controllers can release per hour. EPA’s regulatory impact analysis for the NSPS estimates that about 13,600 new or modified pneumatic controllers will be required to meet the standard annually; EPA also estimates that the oil and gas production sector currently uses about 400,000 pneumatic controllers. Well completions for hydraulically fractured natural gas wells. EPA’s NSPS for well completions focus on reducing the venting of volatile organic compounds during flowback after hydraulic fracturing. According to EPA’s regulatory impact analysis, natural gas well completions involving hydraulic fracturing vent approximately 230 times more natural gas and volatile organic compounds than natural gas well completions that do not involve hydraulic fracturing. The regulatory impact analysis attributes these emissions to the practice of routing flowback of fracture fluids and reservoir gas to a surface impoundment (pit) where natural gas and volatile organic compounds escape to the atmosphere. To reduce the release of volatile organic compounds from hydraulically fractured natural gas wells, EPA’s new rule will require operators to use “green completion” techniques to capture and treat flowback emissions so that the captured natural gas can be sold or otherwise used. EPA’s regulatory impact analysis for the rule estimates that more than 9,400 wells will be required to meet the new standard annually. Storage vessels. Storage vessels are used at well sites (and in other parts of the oil and gas industry) to store crude oil, condensate, and produced water. These vessels emit gas and volatile organic compounds when they are being filled or emptied and in association with changes of temperature. EPA’s NSPS rule will require storage vessels that emit more than 6 tons per year of volatile organic compounds to reduce these emissions by at least 95 percent. EPA’s regulatory impact analysis for the rule estimates that approximately 300 new storage vessels used by the oil and gas industry will be required to meet the new standards annually. EPA officials said they anticipate that most of these storage vessels will be located at well sites. EPA also regulates hazardous air pollutants emitted by stationary sources. In accordance with the 1990 amendments to CAA, EPA does this by identifying categories of industrial sources of hazardous air pollutants and requiring those sources to comply with emissions standards, such as by installing controls or changing production practices. These National Emission Standards for Hazardous Air Pollutants (NESHAP) for each industrial source category include standards for major sources, which are defined as sources with the potential to emit 10 tons or more per year of a hazardous air pollutant or 25 tons or more per year of a combination of pollutants, as well as for area sources, which are sources of hazardous air pollutants that are not defined as major sources. Generally, EPA or state regulators can aggregate emissions from related or nearby equipment to determine whether the unit or facility should be regulated as a major source. However, in determining whether the oil or gas well is a major source of hazardous air pollutants, CAA expressly prohibits aggregating emissions from oil and gas wells (with their associated equipment) and emissions from pipeline compressors or pumping stations. EPA initially promulgated a NESHAP for oil and natural gas production facilities for major sources in 1999 and promulgated amendments in April 2012. NESHAPs generally identify emissions points that may be present at facilities within each industrial source category. The source category for oil and natural gas production facilities includes oil and gas well sites and other oil and gas facilities, such as pipeline gathering stations and natural gas processing plants. The NESHAP for the oil and natural gas production facilities major source category includes emissions points (or sources) that may or may not normally be found at well sites at sizes that would tend to meet the major source threshold. EPA officials in each of the four Regions we contacted were unaware of any specific examples of oil and natural gas wells being regulated as major sources of hazardous air pollutants before the April 2012 amendments. These amendments, however, changed a key definition used to determine whether a facility (such as a well site) is a major source. Specifically, EPA modified the definition of the term “associated equipment” such that emissions from all storage vessels and glycol dehydrators (used to remove water from gas) at a facility will be counted toward determining whether a facility is a major source. EPA’s regulatory impact analysis and other technical support documents for the April 2012 amendments did not estimate how many oil and natural gas well sites would be considered major sources under the new definition. EPA also promulgated a NESHAP for oil and natural gas production facilities for area sources in 2007. The 2007 area source rule addresses emissions from one emissions point, triethylene glycol dehydrators, which are used to remove water from gas. Triethylene glycol dehydrators can be located at oil and gas well sites or other oil and gas facilities, such as natural gas processing plants. Area sources are required to notify EPA that they are subject to the rule, but EPA does not track whether the facilities providing notification are well sites or other oil and natural gas facilities, so it is difficult to determine to what extent oil and gas well sites are subject to the area source NESHAP. In addition to specific programs for regulating hazardous air pollutants, CAA establishes that operators of stationary sources that produce, process, store, or handle listed or extremely hazardous substances have a general duty to identify hazards that may result from accidental releases, take steps needed to prevent such releases, and minimize the consequences of such releases when they occur. Methane is one of many hazardous substances of concern due to their flammable properties. Some EPA Regional officials said that they use infrared video cameras to conduct inspections to identify leaks of methane from storage tanks or other equipment at well sites. For example, EPA Region 6 officials said they have conducted 45 inspections at well sites from July 2010 to July 2012 and issued 10 administrative orders related to violations of the CAA general duty clause. said that all well sites are required to comply with the general duty clause but that EPA prioritizes and selects sites for inspections based on risk. EPA Region 6 includes the states of Arkansas, Louisiana, New Mexico, Oklahoma, and Texas. CAA also requires EPA to publish regulations and guidance for chemical accident prevention at facilities using substances that pose the greatest risk of harm from accidental releases; the regulatory program is known as the Risk Management Program. The extent to which a facility is subject to the Risk Management Program depends on the regulated substances present at the facility and their quantities, among other things. EPA’s list of regulated substances and their thresholds for the Risk Management Program was initially established in 1994 and has been revised several times. The regulated chemicals that may be present at oil and gas well sites include components of natural gas (e.g., butane, propane, methane, and ethane). However, a 1998 regulatory determination from EPA provided an exemption for naturally-occurring hydrocarbon mixtures (i.e., crude oil, natural gas, condensate, and produced water) prior to entry into a natural gas processing plant or petroleum refinery; EPA explained at the time that these chemicals do not warrant regulation and that the general duty clause would apply in certain risky situations. Since naturally-occurring hydrocarbons at well sites generally have not entered a processing facility, they are not included in the threshold determination of whether the well site should be subject to the Risk Management Program. EPA officials said that generally, unless other flammable or toxic regulated substances were brought to the site, well sites would not trip the threshold quantities for the risk management regulations. In September 2011, the U.S. Chemical Safety and Hazard Investigation Board (Chemical Safety Board) released a report describing 26 incidents involving fatalities or injuries related to oil and gas storage tanks located at well sites from 1983 through 2010. The report found that these accidents occurred when the victims—all young adults—gathered at rural unmanned oil and gas storage sites lacking fencing and warning signs and concluded that such sites pose a public safety risk. The report also noted that exploration and production storage tanks are exempt from the Risk Management Program requirements of CAA and recommended that EPA publish a safety alert to owners and operators of exploration and production facilities with flammable storage tanks advising them of their CAA general duty clause responsibilities, and encouraging specific measures to reduce these risks. The Chemical Safety Board requested that EPA provide a response stating how EPA will address the recommendation. EPA responded in June 2012, stating its intent to comply with the recommendation. As of 2012, oil and natural gas production facilities are required to report their greenhouse gas emissions to EPA on an annual basis as described in EPA’s greenhouse gas reporting rule. According to EPA documents, oil and gas well sites may emit greenhouse gases, including methane and carbon dioxide, from sources including: (1) combustion sources, such as engines used on site, which typically burn natural gas or diesel fuel, and (2) indirect sources, such as equipment leaks and venting.greenhouse gas reporting rule requires oil and gas production facilities (defined in regulation as all wells in a single basin that are under common ownership or control) that emit more than 25,000 metric tons of carbon dioxide equivalent at the basin level to report their annual emissions of carbon dioxide, methane, and nitrous oxide from equipment leaks and venting, gas flaring, and stationary and portable combustion. EPA documents estimate that emissions from approximately 467,000 onshore wells are covered under the rule. For more details about CAA, please see appendix IV. RCRA, passed in 1976, established EPA’s authority to regulate the generation, transportation, treatment, storage, and disposal of hazardous wastes. Subsequently, the Solid Waste Disposal Act Amendments of 1980 created a separate process by which oil and gas exploration and production wastes, including those originating within a well, would not be regulated as hazardous unless EPA conducted a study of wastes associated with oil and gas development and then determined that such wastes warranted regulation as hazardous waste, followed by congressional approval of the regulations. EPA conducted the study and, in 1988, issued a determination that it was not warranted to regulate oil and gas exploration and production wastes as hazardous. Based on this EPA determination, drilling fluids, produced water, and other wastes associated with the exploration, development, or production of oil or gas are not regulated as hazardous. According to EPA guidance issued in 2002, these exempt wastes include wastes that come from within the well, as well as wastes generated from field operations. Conversely, wastes generated from other activities at well sites may be regulated as hazardous. For example, discarded unused hydraulic fracturing fluids and painting wastes, among others, may be present at well sites and are “non-exempt,” and could be regulated as hazardous, depending on the specific characteristics of the wastes. Facilities that generate more than 100 kilograms (220 pounds) of hazardous waste per month are regulated as generators of hazardous waste and, among other things, are required to have an EPA identification number and to use the RCRA manifest system for tracking hazardous waste. Facilities generating smaller quantities of hazardous waste are not subject to these requirements. EPA headquarters officials said they do not have data on how many well sites may be hazardous waste generators, but that states may have more information about quantities of hazardous wastes at well sites. As such, we asked state officials responsible for waste programs whether they were aware of well sites being classified as small-quantity hazardous waste generators, and officials in all six states we reviewed indicated that they were unaware of well sites having sufficient quantities of hazardous wastes to be subject to those regulations. In September 2010, the Natural Resources Defense Council submitted a petition to EPA requesting that the agency regulate waste associated with oil and gas exploration and production as hazardous. The petition asserts that EPA should revisit the 1988 determination not to regulate these wastes as hazardous because, among other things, EPA’s underlying assumptions concerning the availability of alternative disposal practices, the adequacy of state regulations, and the potential for economic harm to the oil industry are no longer valid. According to EPA officials, the agency is currently reviewing the information provided in the petition but does not have a time frame for responding. RCRA also authorizes EPA to issue administrative orders, among other things, in cases where handling, treatment, or storage of hazardous or solid waste may present an imminent and substantial endangerment to health or the environment. EPA has used RCRA’s imminent and substantial endangerment authorities related to oil and gas well sites. For example, EPA Region 8 issued RCRA imminent and substantial endangerment orders to operators in Wyoming after discovering that pits near oil production sites were covered with oil and posed a hazard to birds. For more details about RCRA, please see appendix V. Congress passed CERCLA in 1980 to protect public health and the environment by addressing the cleanup of hazardous substance releases. CERCLA establishes a system governing the reporting and cleanup of releases of hazardous substances and provides the federal government the authority to respond to actual and threatened releases of hazardous substances, pollutants, and contaminants that may endanger public health and the environment. CERCLA requires operators of oil and gas sites to report certain releases of hazardous substances and gives EPA authority to respond to certain releases but excludes releases of petroleum (e.g., crude oil and other petroleum products) from these provisions. As previously discussed, releases of petroleum products are covered by CWA if the release threatens U.S. navigable waters or adjoining shorelines. EPA officials identified some instances of petroleum spills in dry areas that did not reach surface waters and explained that EPA had no role related to the investigation or cleanup of these incidents. We identified regulatory provisions in five of six states requiring cleanup of oil spills even if they do not reach surface waters. For hazardous substances, CERCLA has two key elements relevant for the unconventional oil and gas industry: release reporting and EPA’s investigative and response authority. Similar to the requirements to report oil spills under CWA, CERCLA requires operators to report releases of hazardous substances above reportable quantities to the National Response Center. The National Response Center shares information about spills with other agencies, including EPA Regional offices, which allows EPA the opportunity to follow up on reported spills. EPA also has investigative and response authority under CERCLA, including provisions allowing EPA broad access to information and the authority to enter property to conduct an investigation or a removal of contaminated material. EPA has the following authorities, among others: Investigative. EPA may conduct investigations—including activities such as monitoring, surveying, and testing—in response to actual or threatened releases of hazardous substances or pollutants or contaminants. EPA can also require persons to provide information about alleged releases or threat of release. EPA officials described several instances in which the agency used CERCLA’s investigative and information gathering authorities relating to alleged hazardous substance releases from oil and gas well sites. For example, EPA used CERCLA authority to investigate private water well contamination potentially related to nearby shale gas well sites in Dimock, Pennsylvania. In addition, EPA is currently using the same authority to investigate private water well contamination potentially related to tight sandstone well sites in Pavillion, Wyoming. Response. EPA has the authority to respond to releases of hazardous substances itself and to issue administrative orders requiring a company potentially responsible for a release of hazardous substances, which may pose an imminent and substantial endangerment, to take response actions, as well as to seek relief in a federal court. EPA officials could not provide a recent example where the agency used this authority to issue an administrative order at a well site, but EPA used the response authority to conduct sampling and to provide temporary drinking water to residents with contaminated wells in Dimock, Pennsylvania. For more details about CERCLA, please see appendix VI. Among other things, EPCRA provides individuals and their communities with access to information regarding storage or release of certain chemicals in their communities. Two provisions of EPCRA—release notification and chemical storage reporting—apply to oil and gas well sites. The release notification provisions require companies that produce, use, or store certain chemicals to notify state and local emergency planning authorities of certain releases that would affect the community. Spills that are strictly on-site would not have to be reported under EPCRA but may still have to be reported to the National Response Center under provisions of CWA or CERCLA. In addition, companies would have to comply with EPCRA’s chemical storage reporting provisions, which require facilities storing or using hazardous or extremely hazardous chemicals over certain thresholds to submit an annual inventory report including detailed chemical information to state and local emergency planning authorities and the local fire department. When asked whether oil and gas well sites would commonly trigger EPCRA’s release notification and chemical storage reporting requirements, EPA officials said these requirements could be triggered at every well site. EPCRA also established the Toxics Release Inventory (TRI)––a publicly available database containing information about chemical releases from more than 20,000 industrial facilities––but EPA regulations for the TRI do not require oil and gas well sites to report to TRI. Specifically, these provisions of EPCRA generally require certain facilities that manufacture, process, or otherwise use any of more than 600 listed chemicals to report annually to EPA and their respective states on chemicals used above threshold quantities; the amounts released to the environment; and whether they were released into the air, water, or soil. EPCRA specified certain industries subject to the reporting requirement—which did not include oil and gas exploration and development—and also provided authority for EPA to add or delete industries going forward. EPA issued regulations to implement the TRI in 1988 and chose not to change the list of industries subject to the provision at that time. In 1997, EPA promulgated a rule adding seven industry groups to the list of industries required to report releases to the TRI, including coal mining and electrical utilities that combust coal and/or oil. In developing the 1997 rule, EPA considered including oil and gas exploration and production but did not do so because, according to EPA’s notice in the Federal Register for the final rule, there were concerns about how “facility” would be defined for this industry. At that time, EPA’s stated rationale was that the oil and gas exploration and production industry is unique in that it may have related activities over a large geographic area and, while together these activities may involved the management of chemicals regulated by the TRI program, taken at the smallest unit—an individual well—the chemical and other thresholds are unlikely to be met. According to EPA officials, EPA is in the preproposal stage of developing a new rule to add additional industrial sectors into the TRI program but is not planning to include the oil and gas exploration and production industry. EPA officials said that adding oil and gas well sites would likely provide an incomplete picture of the chemical uses and releases at these sites and would, therefore, be of limited utility in providing information to communities. For more details about EPCRA, please see appendix VII. TSCA authorizes EPA to regulate the manufacture, processing, use, distribution in commerce, and disposal of chemical substances and mixtures. TSCA provides EPA with several authorities by which EPA may assess and manage chemical risks, including the authority to (1) collect information about chemical substances, (2) require companies to conduct testing on chemical substances, and (3) take action to protect adequately against unreasonable risks. TSCA allows chemical companies to assert confidentiality claims on information provided to EPA; if the information provided meets certain criteria, EPA must protect it from disclosure to the public. EPA maintains a list of chemicals that are or have been manufactured or processed in the United States, called the TSCA inventory. Of the over 84,000 chemicals currently in the TSCA inventory, about 62,000 were already in commerce when EPA began reviewing chemicals in 1979. Since then, EPA has reviewed more than 45,000 new chemicals, of which approximately 20,000 were added to the inventory after chemical companies began manufacturing them. As part of EPA’s Study on the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, EPA is currently analyzing information provided by nine hydraulic fracturing service companies, including a list of chemicals used in hydraulic fracturing operations. EPA officials said that they expect most of the chemicals disclosed by the service companies to appear on the TSCA inventory list, provided that chemicals are not classified solely as pesticides. EPA officials do not expect to be able to compare the list of chemicals provided by the nine hydraulic fracturing service companies to the TSCA inventory until the release of a draft report of the Study on the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources for peer review, expected in late 2014. In August 2011, EPA received a petition from the environmental group Earthjustice and 114 others asking the agency to exercise TSCA authorities and issue rules to require manufacturers and processors of chemicals used in oil and gas exploration and production to develop and provide certain information to EPA. According to the petition, EPA and the public currently lack adequate information about the health and environmental effects of chemicals used in oil and gas exploration and production, and EPA should exercise its TSCA authorities to ensure that chemicals used in oil and gas exploration and production do not present an unreasonable risk of harm to health and the environment. In a letter to the petitioners, EPA granted the petition in part, stating there is value in beginning a rulemaking process under TSCA to obtain data on chemical substances used in hydraulic fracturing. EPA’s letter also stated that the TSCA proposal would focus on providing an aggregate picture of the chemical substances used in hydraulic fracturing, which would complement and not duplicate well-by-well disclosure programs that exist in some states. The letter also indicates that the agency is drafting an Advance Notice of Proposed Rulemaking on this issue. As of August 31, 2012, EPA has not released a publication date for this proposed rulemaking. EPA also intends to convene a stakeholder process to gather additional information for use in developing a proposed rule. For more details about TSCA, please see appendix VIII. FIFRA, as amended, mandates that EPA administer pesticide registration requirements and authorizes EPA to regulate the use, sale, and distribution of pesticides to protect human health and preserve the environment. FIFRA requires that EPA register new pesticides; pesticide registration is a very specific process that is not valid for all uses of a particular chemical. Instead, each registration describes the chemical and its intended use (i.e., the crops/sites on which it may be applied), and each use must be supported by research data. According to EPA officials, some pesticides registered under FIFRA are used in hydraulic fracturing, and EPA has approved registrations of some pesticides for this purpose. According to a report about shale gas development by the Ground Water Protection Council, operators may use pesticides to kill bacteria or other organisms that may interfere with the hydraulic fracturing process. For example, glutaraldehyde may be used by operators to eliminate bacteria that produce byproducts that cause corrosion inside the well and was reregistered for this purpose by EPA in 2007. As discussed above, in six of the eight federal environmental and public health laws identified, there are exemptions or limitations in regulatory coverage related to the oil and gas exploration and production industry (there are two exemptions related to CAA). All of these exemptions are related to programs designed to prevent pollution (see table 2). For example, under CWA, EPA generally requires permits for stormwater discharges at construction sites, which prevents sediment from entering nearby streams. However, the Water Quality Act of 1987 and Energy Policy Act of 2005 largely exempted the oil and gas exploration and production sector from these stormwater permitting requirements. Four of the exemptions are statutory (related to SDWA, CWA, CAA, and CERCLA), and three are related to regulatory decisions made by EPA (related to CAA, RCRA, and EPCRA). States may have regulatory programs related to some of these exemptions or limitations in federal regulatory coverage. For example, although oil and gas exploration and production wastes are not regulated under RCRA as hazardous, which reduces the federal role in management of such wastes, they are nonetheless solid wastes. State regulations may govern management of solid waste, and certain EPA regulations address minimum requirements for how solid waste disposal facilities should be designed and operated. The exemptions do not limit the authorities EPA has under federal environmental and public health laws to respond to environmental contamination. Table 3 lists EPA authorities that may be applicable when conditions or events at a well site present particular risk to the environment or human health. As noted throughout this report, EPA has used several of these authorities at oil and gas wells. For example, as discussed above, EPA Region 8 has used RCRA’s imminent and substantial endangerment authorities to issue RCRA imminent and substantial endangerment orders to operators in Wyoming after discovering that pits near oil production sites were covered with oil and posed a hazard to birds. Similarly, as discussed above, EPA is using CERCLA’s response authority to investigate private water well contamination in Pavillion, Wyoming. Whether an authority is available depends on requisite conditions being met in a given instance. EPA officials said that, in some instances, response authorities of multiple federal environmental laws could be used to address a threat to public health or the environment. In 2001, EPA and the Department of Justice developed a memo advocating that officials consider the specifics of a situation and use the most appropriate authority. See appendixes II through VI for a more detailed discussion of these authorities. The six states in our review implement additional requirements governing a number of activities associated with oil and gas development. One of the states—Pennsylvania—is also part of the Delaware River Basin Commission—a regional commission that implements additional requirements. All six states have updated some aspects of their requirements in recent years. In addition to implementing and enforcing certain aspects of federal requirements with EPA approval and oversight, the six states in our review implement additional requirements governing a number of activities associated with oil and gas development. State requirements often do not explicitly differentiate between conventional and unconventional development but, in recent years, states have begun to promulgate some requirements that apply specifically to unconventional development. States have regulatory requirements related to a variety of activities involved in developing unconventional reservoirs, including siting and site preparation; drilling, casing, and cementing; hydraulic fracturing; well plugging; site reclamation; waste management and disposal; and managing air emissions. Table 4 compares selected state requirements and related federal environmental and public health requirements; a more comprehensive table is available in appendix X. Several studies noted that development practices and state requirements may vary based on a number of factors, including geology, climate, and the type of resource being developed. We did not assess whether all requirements are appropriate for all states as part of this review. All six states we reviewed have state requirements regarding site selection and preparation, though the specifics of their requirements vary. Specifically, states have requirements for baseline testing of water wells, required setbacks from water sources, and stormwater management, among others. For example, three of the six states—Colorado, Ohio, and Pennsylvania—have requirements that encourage or require operators to conduct baseline water testing in certain cases. Colorado requires testing of certain nearby wells when a proposed coalbed methane well is located within a quarter-mile of a conventional gas well or a plugged and abandoned well. In Ohio, baseline water well sampling is required within 1,500 feet of any proposed horizontal well or within 300 feet of any kind of well proposed in an urban area. Pennsylvania does not require baseline testing, but state law presumes operators to be liable for any pollution of water wells within 2,500 feet of an unconventional well that occurs within 12 months of drilling activities, including hydraulic fracturing. Operators in Pennsylvania can defend against this presumption if they have predrilling tests conducted by an independent certified laboratory showing that the pollution predated drilling. State regulators in Pennsylvania said that nearly all companies in Pennsylvania conduct baseline testing of nearby water wells, in many cases up to 4,000 feet from the drilling site. Five of the six states—Colorado, North Dakota, Ohio, Pennsylvania, and Wyoming—we reviewed have requirements related to setbacks for well sites or equipment from certain water sources. For example, in Ohio, oil and gas wells and associated storage tanks generally may not be within 50 feet of a stream, river, or other body of water. In Pennsylvania, unconventional wells may not be drilled within 500 feet of water wells without written owner consent unless the operator cannot otherwise access its mineral rights and demonstrates that additional protective measures will be utilized. In Pennsylvania, there are also setbacks from public water supplies and certain other bodies of water such as springs and wetlands. Oil and gas operations are generally not subject to certain stormwater permitting requirements under the Clean Water Act, but four of the six states we contacted—Colorado, North Dakota, Pennsylvania, and Wyoming—have their own stormwater permitting requirements. For example, the Wyoming Department of Environmental Quality requires permit coverage for stormwater discharges from all construction activities disturbing 1 or more acres. These permits require the operator to develop a stormwater management program, including best management practices, that can be reviewed by the Wyoming Department of Environmental Quality. In North Dakota, operators must obtain a permit for construction activities that disturb 5 or more acres, and state officials said that nearly all oil and gas drilling projects meet this threshold. This permit also requires the operator to develop a stormwater management program and implement best management practices for managing stormwater, such as using straw bales or dikes to manage water runoff. We did not identify any stormwater permitting requirements for Ohio and Texas, but their state regulations address stormwater in other ways. For example, operators in Ohio are required to comply with the state’s best management practices during construction, such as design guidelines for constructing access roads. Texas regulations prohibit operators from causing or allowing pollution of surface water and encourage operators to implement best management practices to minimize discharges, including discharges of sediment during storm events. States have additional requirements relating to erosion control, site preparation, and surface disturbance minimization. For more details about state siting and site preparation requirements, see appendix IX. All of the six states in our review have requirements related to how wells are to be drilled and casing should be installed and cemented in place, though the specifics of their requirements vary. For example, states have different requirements regarding how deep operators must run surface casing to protect groundwater. In Pennsylvania, operators are required to run surface casing approximately 50 feet below the deepest fresh groundwater or at least 50 feet into consolidated rock, whichever is deeper. Generally, the surface casing may not be set more than 200 feet below the deepest fresh groundwater unless necessary to set the casing in consolidated rock. Different casing and cementing requirements apply in Pennsylvania when drilling through coal formations, which state regulators said is common in the southwest part of the state. In Texas, operators are required to run surface casing to protect all usable quality water, as defined by the Texas Commission on Environmental Quality. The depth of the surface casing may be specified in a letter by the commission or in rules specific to a particular oil or gas field, which account for local considerations. In no case may surface casing be set deeper than 200 feet below the specified depth without prior approval from the Texas Railroad Commission, the oil and gas regulator in Texas. Operators in Wyoming are generally required to run surface casing to reach a depth below all known or reasonably estimated usable groundwater as defined in regulations and generally 100 to 120 feet below certain permitted water supply wells within a quarter-mile, but certain coalbed methane wells are exempt from these requirements. Until 2012, Ohio did not specify a depth to which surface casing was required to be set but according to state regulators, the depth of the casing used to protect groundwater was dictated through the permitting process, and regulators and operators were generally following the same casing and cementing requirements for unconventional wells as they would for Class II UIC wells. Ohio adopted new regulations effective August 2012 that generally require operators to run surface casing at least 50 feet below the base of the deepest underground source of drinking water or at least 50 feet into bedrock, whichever is deeper. Among the six states we contacted, North Dakota and Ohio are the only states with specific casing and cementing provisions for horizontal wells. However, all six states have some requirements—whether through law, regulation, or the permitting process—that generally require operators to provide regulatory officials with information about the vertical and horizontal drilling paths. For example, an application for a permit to drill a horizontal well in Wyoming must include information about the vertical and horizontal paths of the well, and operators must provide notice to owners within a half-mile of any point on the entire length of the well. In addition, operators must (1) provide notification and obtain approval from the Wyoming Oil and Gas Conservation Commission before beginning horizontal drilling and (2) file a description of the exact path of the well, known as a directional survey, within 30 days of well completion. North Dakota requires a different permit to drill a horizontal well than it does for a vertical well, and the horizontal permit contains information about the horizontal path of the well. For more details about state drilling, casing, and cementing requirements, see appendix IX. All six states we reviewed have requirements for disclosing the chemicals used in hydraulic fracturing, but the specific requirements vary (see table 5). Four states—Colorado, North Dakota, Pennsylvania, and Texas— require disclosure through the website FracFocus, which is a joint project of the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. For example, operators that perform hydraulic fracturing in Texas are required to upload certain information to the website FracFocus within 30 days after completion of the well or 90 days after the drilling operation is completed, whichever is earlier. Information required to be uploaded to FracFocus includes, among other things, the operator’s name; the date of completion of hydraulic fracturing; the well location; the total volume of water used to conduct fracturing; and chemicals used, including their trade names, suppliers, intended use, and concentration. In Ohio, companies have options as to how to disclose information, including through FracFocus. Wyoming’s chemical disclosure requirements were developed prior to the development of FracFocus, and the state does not require operators to disclose information through the website. Among the six states we contacted, Wyoming is the only state that requires operators to disclose certain chemical information prior to conducting hydraulic fracturing. Specifically, as part of their application for permit to drill, operators are required to submit information on the chemicals proposed to be used during hydraulic fracturing. Five of the six states—Colorado, Ohio, Pennsylvania, Texas, and Wyoming—have specific provisions for protecting information on hydraulic fracturing fluids that is claimed as confidential business information or trade secrets. Four of the six states—Colorado, Ohio, Pennsylvania, and Texas—specifically require that the information must be provided to health professionals for diagnosis or treatment and to certain officials responding to a spill or a release. For example, in Texas, if an operator claims that a chemical is subject to trade secret protection, the chemical family or other similar description must generally be provided. Operators in Texas may not withhold information, including trade secrets, about chemicals used during hydraulic fracturing from health professionals or emergency responders who need the information for diagnostic, treatment, or other emergency response purposes, but health professionals and emergency responders must hold the information confidential except as required for sharing with other health professionals, emergency responders, or accredited laboratories for diagnostic or treatment purposes. Texas’ regulations also allow for certain entities—including the owner of the land on which the well is located, an adjacent landowner, and relevant state agencies—to challenge a claim to trade secret protection. Five of the six states—Colorado, North Dakota, Ohio, Pennsylvania, and Wyoming—have additional requirements specifically related to hydraulic fracturing. For example, Colorado, North Dakota, Ohio, and Wyoming require operators to continuously monitor certain pressure readings during hydraulic fracturing and to notify the state if pressure exceeds a certain threshold. Ohio also requires the suspension of operations when anticipated pressures are exceeded. North Dakota has mechanical integrity requirements specific to hydraulic fracturing, including requirements for specific types of casing, valves, and other equipment, which vary based on different fracturing scenarios. In addition, Colorado, Ohio, Pennsylvania, and Wyoming require operators to notify state regulators prior to conducting hydraulic fracturing, which provides state regulators the opportunity to conduct inspections during the hydraulic fracturing. Colorado requires notice 48 hours prior to conducting hydraulic fracturing, and Ohio and Pennsylvania require notice 24 hours prior. Wyoming does not require a specific period of notice. In Wyoming, benzene, toluene, ethylbenzene, and xylene (BTEX compounds) and petroleum distillates may only be used for hydraulic fracturing with prior authorization from state oil and gas regulators. Pennsylvania law requires blowout preventers to be used when drilling into an unconventional formation. For more details about state hydraulic fracturing requirements, see appendix IX. All six states in our review have requirements regarding well plugging, such as notifying the state prior to plugging or using specific materials or methods to do so. For example, operators in Colorado must obtain prior approval from state regulators for the plugging method and provide notice of the estimated time and date of plugging. Colorado regulations specify that the material used for plugging must be placed in the well in a manner that permanently prevents migration of oil, gas, water, or other substances out of the formation in which it originated. Cement plugs must be a minimum of 50 feet in length and must extend a minimum of 50 feet above each zone to be protected. After plugging the well, operators must submit reports of plugging and abandonment to the Colorado Oil and Gas Conservation Commission and include information specifying the fluid used to fill the wellbore, information about the cement used, date of work, and depth of plugs. In Pennsylvania, operators must follow (1) specific provisions for well plugging based on whether the well is located in a coal area or noncoal area or (2) an alternate approved method. Prior to plugging a well in an area underlain by a workable coal seam, the oil and gas operator must notify the state and the coal company to permit representatives to be present at the plugging. In addition, all six states have programs to plug wells that were improperly plugged and have been abandoned, though their level of activity varies. For example, state regulators in Texas said that the primary objective of their program, which began in 1983, is to plug abandoned oil and gas wells that are causing pollution or threatening to cause pollution for which a responsible operator does not exist; the responsible operator failed to plug the well; or the responsible operator failed to otherwise bring the wells into compliance. As of 2009, Texas state regulators had plugged 30,000 wells, and approximately 8,000 potentially abandoned wells remained throughout the state. Officials stated, however, that many of these abandoned wells may be re-used for development of previously overlooked reservoirs. State regulators in North Dakota said that the number of abandoned wells in the state is very low compared with other states because the state was fairly late to oil and gas development—with major development starting in the 1950s—and that the state had a good tracking system in place during the early days of development. State regulators in North Dakota used funds from its well plugging program to plug two wells in the last year. For more details about state well plugging requirements, see appendix IX. All six states in our review have requirements for site reclamation, though the extent of the requirements varies. Five states—Colorado, Ohio, North Dakota, Pennsylvania, and Wyoming—have requirements both for backfilling soil and for revegetating areas. For example, in Colorado, final reclamation must generally be complete within 3 months of plugging a well on crop land and within 12 months on noncrop land. Reclamation in Colorado involves returning segregated soil horizons to their original relative positions; returning crop land to its original contour; as near as practicable, returning noncrop land to its original contour to achieve erosion control and long-term stability; and adequately tilling to establish a proper seedbed. In Wyoming, operators must begin reclamation within 1 year of permanent abandonment of a well or last use of a pit and in accordance with the landowner’s reasonable requests, or to resemble the original vegetation and contour of adjoining lands. In addition, where practical, topsoil must be stockpiled during construction for use in reclamation. Texas has requirements for contouring soil, but we did not identify requirements for revegetating the area. For more details about state site reclamation requirements, see appendix IX. All six states in our review have some requirements regarding waste management and disposal, though specific requirements and practices vary across and within states. For example, regulators in Colorado said that the method of waste disposal varies based on the geological formation being exploited and the location of the production well. In some parts of the state, they said that the produced water generated is very salty and is therefore generally disposed of in a Class II UIC well. In contrast, in the Raton Basin—a coalbed methane formation near the border with New Mexico—the produced water is of sufficiently good quality that much of it is discharged to surface waters, according to state regulators. All six states we reviewed have requirements regarding the use of pits for storage of produced water, drill cuttings, and other substances. For example, in North Dakota, a lined pit may be temporarily used to retain solids or fluids generated during activities including well completion, but the contents of the pits must be removed within 72 hours after operations have ceased and must be disposed of at an authorized facility. Pennsylvania requires that certain pits be lined and requires the liners to meet certain permeability, strength, thickness, and design standards; the pit itself must also be constructed so that it will not tear the liner and can bear the weight of the pit contents. In addition, Colorado and Wyoming require pitless drilling systems (tanks) to be used in certain circumstances. For example, Colorado requires pitless drilling systems for produced water from new oil and gas wells within a specified distance of certain drinking water supply areas, and Wyoming requires pitless drilling systems in areas where groundwater is less than 20 feet below the surface. Underground injection of produced water in Class II UIC wells is a common method of disposal of produced water in five of the six states we reviewed. For example, state regulators in Ohio said that there are 177 Class II UIC disposal wells currently in operation, and 98 percent of the fluid waste from oil and gas wells in Ohio is disposed of in these Class II UIC wells. As noted previously, five out of the six states we reviewed have primary responsibility for regulating injection wells, whereas EPA implements the program in Pennsylvania. The five states in our review that have been granted primacy for their Class II UIC programs obtained it under the alternative provisions in which they demonstrate to EPA that their program is effective in preventing endangerment of underground sources of drinking water, in lieu of adopting all Class II UIC requirements in EPA regulations. All states have requirements for Class II UIC wells relating to casing and cementing, operating pressure, mechanical integrity testing, well plugging, and the monitoring and reporting of certain information, among other requirements. For example, North Dakota requires the operators of all new Class II UIC wells to demonstrate the mechanical integrity of the well and requires existing Class II UIC wells to demonstrate continued mechanical integrity at least once every 5 years. In North Dakota, mechanical integrity is demonstrated by showing that there is no significant leak in, for example, the casing; and there is no significant fluid movement into an underground source of drinking water through vertical channels adjacent to the injection well. Texas also requires operators to demonstrate the mechanical integrity of Class II UIC wells generally by conducting specified pressure tests before commencing injection, after conducting maintenance, and every 5 years. With regard to monitoring and reporting, Ohio requires operators to monitor injection pressures and volumes for each disposal well on a daily basis and to report annually on maximum and monthly average pressure and volumes. Aside from underground injection, there are several other options for disposal of produced water, though the specifics vary across and within states. For example, regulatory agencies issue NPDES permits in Colorado, Texas, and Wyoming for direct discharges to surface waters in certain cases; in doing so, the states must apply, where applicable, EPA’s effluent limitations guidelines discussed above. According to state regulators in Wyoming, the state has about 1,000 currently active permits for discharges of produced water from coalbed methane formations and 500 permits for produced water from conventional formations. In contrast, state regulators in North Dakota said that there are no direct surface discharges of produced water in their state because the produced water is too salty. Some states, such as Colorado and Pennsylvania, also have commercial facilities, which treat produced water before discharging it to surface waters. In addition, disposal to a POTW is an option in Ohio and Pennsylvania, but there have been some recent efforts to restrict such disposal. One concern regarding disposal to POTWs is that these facilities may not have the technology necessary to remove key pollutants, including total dissolved solids, from the waste stream. In 2010, Ohio’s Environmental Protection Agency (OEPA) approved a permit modification that allowed a POTW in Warren, Ohio, to accept 100,000 gallons per day of produced water with concentrations of less than 50,000 milligrams per liter of total dissolved solids, which was then diluted and discharged to surface waters. However, the Director of OEPA subsequently issued a determination in 2011 that the permit had been unlawfully issued because Ohio law does not generally permit the disposal of produced water through a POTW. In response, OEPA did not reauthorize the POTW to accept produced water when its NPDES permit came up for renewal in 2012. In July 2012, however, OEPA’s decision was reversed by an administrative review commission, which held that the matter was outside of OEPA’s jurisdiction. Instead, the power to prohibit disposal to a POTW lies with the Ohio Department of Natural Resources. Accordingly, the commission removed the NPDES permit’s prohibition on accepting produced water. Prior to 2011, POTWs in Pennsylvania also accepted produced water from oil and gas well sites. The Pennsylvania Department of Environmental Protection issued administrative orders to POTWs in Pennsylvania requiring, among other things, that the POTWs restrict the volume of oil and gas wastewater they were accepting, evaluate the impacts of oil and gas wastewaters on their treatment process, and submit certain samples of oil and gas wastewater accepted for treatment. In addition, the state of Pennsylvania requested that operators of Marcellus shale gas wells stop delivering produced water to POTWs and began revising the POTWs’ NPDES permits. State officials later reported that POTWs in Pennsylvania were no longer accepting produced water from the Marcellus shale, and EPA Regional officials said that they believe that POTWs are accepting less produced water. In addition to permanent disposal of produced water, all six states in our review allow for recycling or other reuses of produced water. For example, according to a 2011 report, over 50 percent of the produced water in Colorado is recycled. In addition, state regulators in Pennsylvania said that the best option for dealing with produced water in the state is recycling, and the Department of Environmental Protection can track what percentage of recycled water was used in hydraulic fracturing based on information required on well completion reports. Approximately 90 percent of produced water in Pennsylvania is recycled, according to state regulators. The Texas Railroad Commission has approved several recycling projects in the Barnett Shale to reduce the amount of fresh water used in development activities there. Four of the six states—Colorado, North Dakota, Ohio, and Wyoming—also allow operators to reuse certain types of fluid waste for road applications. For example, in Ohio, produced water, excluding flowback from hydraulic fracturing, may be used for dust and ice suppression on roads with the approval of local governments; approximately 1 percent of produced water is used in this way. In Wyoming, road and land applications may be permitted as reuses of produced water. North Dakota allows road but not land application of produced water. Regulatory agencies in all six states implement requirements for the disposal of waste such as drill cuttings. For example, in Colorado, drill cuttings may be buried in pits at the well site, an activity which is regulated by the Colorado Oil and Gas Conservation Commission. Drill cuttings taken off site for disposal at a commercial waste facility must comply with the regulations of the state’s Department of Public Health and Environment that govern those facilities. Texas allows drill cuttings to be landfarmed on the well site where they were generated with the written permission of the surface owner of the site if they were obtained using drilling fluids with a chloride concentration of 3,000 milligrams per liter or less. Texas allows on-site burial of drill cuttings that were obtained using drilling fluids with a chloride concentration in excess of 3,000 milligrams per liter. In North Dakota, operators frequently bury drill cuttings on-site where the North Dakota Industrial Commission’s Oil and Gas Division has authority, but, in some cases, the drill cuttings may be disposed of at a landfill under the jurisdiction of the Department of Health due to shallow groundwater or permeable subsoil. As discussed earlier in this report, officials in the six states we reviewed were not aware of any oil or gas well sites that would be regulated as small-quantity generators of hazardous waste under RCRA. Pursuant to RCRA, regulation of waste that is not considered hazardous is largely a state responsibility. Some states have special categories of waste and associated additional requirements that apply to industrial wastes generally, or oil and gas wastes specifically. For example, waste from crude oil and natural gas exploration and production in North Dakota is called special waste. Special waste landfills must be permitted and comply with specific design standards. Currently, there are four special waste landfills in North Dakota with another five proposed special waste landfills at the beginning stages of the permitting process. State regulators said that special waste consists mostly of drill cuttings but can also include other things such as contaminated soil. In Pennsylvania, oil and gas waste falls into a category of waste called residual waste that applies to, among other things, certain wastes from industrial, mining, or agricultural operations. Residual waste disposal must be permitted and is subject to processing and storage rules. All six states in our review have requirements for managing and disposing of wastes, such as oilfield equipment, drilling solids, and produced water that have been exposed to or contaminated with naturally-occurring radioactive material (NORM) or technologically-enhanced NORM.occurs naturally in some geologic formations that also contain oil or gas and when NORM is brought to the surface during drilling and production, it remains in drill cuttings and produced water and, under certain conditions, creates scales or deposits on pipes or other oilfield equipment. Officials at the Colorado Department of Public Health and Environment said that they set tiers for how to manage materials that contain NORM based on their level of radioactivity. In addition, they said that the department is working with the Colorado Oil and Gas Conservation Commission to require operators to perform certain tests on produced water before allowing produced water to be used for road application. Texas officials said that the state requires operators to identify NORM-contaminated equipment with the letters “NORM” by securely attaching a clearly visible waterproof tag or marking with a legible waterproof paint or ink. In addition, Texas requires operators to dispose of oil and gas NORM waste by methods that are specifically authorized by rule or specifically permitted. State regulators in Wyoming said that a lot of NPDES permits for direct discharges to surface waters have limits on radioactivity that would probably lead the operator to dispose of produced water contaminated with NORM in a Class II UIC well. For more details about states waste management and disposal requirements, see appendix IX. Five of the six states we reviewed have permitting or registration requirements for managing air emissions from oil and gas production sites. In addition, all six states have requirements related to venting and flaring of gas and limiting or managing emissions of hydrogen sulfide—a hazardous and deadly gas—at drilling sites. Five of the six states we reviewed —Colorado, North Dakota, Ohio, Texas, and Wyoming—have developed permitting or registration requirements that apply to oil and gas development. For example, according to state regulators, the vast majority of production wells in Colorado require air permits. Operators with certain condensate tanks and tank batteries are required to obtain a permit if the tanks have uncontrolled actual emissions of volatile organic compounds greater than or equal to 2 tons per year in areas which are not attaining certain air quality standards (nonattainment areas) or greater than or equal to 5 tons per year in an attainment area. As part of the permit requirements, operators in nonattainment areas must reduce emissions of volatile organic compounds by 90 percent from uncontrolled actual emissions during certain times of the year, and by 70 percent during other times, and reduce emissions by 90 percent for dehydration systems. In Ohio, an operator meeting certain requirements must obtain an air permit that lists each source of emissions; all applicable rules that apply to the sources, including federal and state requirements; operational restrictions; monitoring; recordkeeping; reporting; and testing requirements. Wyoming officials noted that oil and gas facilities are subject to general state permitting requirements but did not identify any permitting requirements specific to air emissions from oil and gas development. In Wyoming, state regulators have worked with industry to achieve voluntary reductions from mobile sources in certain parts of the state that may soon not meet air quality standards for ozone. Specifically, officials at the Wyoming Department of Environmental Quality said that they have asked operators in certain areas to agree to implement voluntary reductions in volatile organic compounds and nitrogen oxides and to install controls on diesel engines on mobile drilling rigs; regulators then include these requirements in the air permit issued to the operator. North Dakota and Texas also have permitting or registration requirements, and Pennsylvania is in the process of developing an inventory for oil and gas emissions information. All six states have some requirements for flaring excess gas encountered during drilling and production, which may otherwise pose safety hazards and contribute to emissions. For example, operators in Pennsylvania who encounter excess gas during drilling or hydraulic fracturing must capture the excess gas, flare it, or divert it away from the drilling rig in a manner that does not create a hazard to public health and safety. According to state regulators in Wyoming, the Oil and Gas Conservation Commission has jurisdiction for flaring prior to production when the primary concern with flaring is safety. For flaring that occurs after production has begun, the Department of Environmental Quality requires 98 percent combustion efficiency. All six states have safety requirements to limit and manage emissions of hydrogen sulfide—a hazardous and deadly gas—at drilling sites. For example, in Texas, operators are subject to detailed requirements in areas where exposure to hydrogen sulfide could exceed a certain threshold if a release occurred, taking into consideration whether the area of potential exposure includes any public areas such as roads. Requirements relate to posting warning signs, using fencing, maintaining protective breathing equipment at the well site, installing a flare line and a suitable method for lighting the flare, and conducting training. In some cases, hydrogen sulfide requirements overlap with flaring requirements. For example, flares used for treating gas containing hydrogen sulfide in North Dakota must be equipped and operated with an automatic ignitor or a continuous burning pilot, which must be maintained in good working order, including flares that are used for emergency purposes only. For more details about state requirements for managing air emissions, see appendix IX. One of the states in our review—Pennsylvania—is also part of a regional commission that implements additional requirements governing several aspects of natural gas development. Specifically, the Delaware River Basin Commission is a regional body whose members include the governors of Delaware, New Jersey, New York, Pennsylvania, as well as the U.S. Army Corps of Engineers’ Division Engineer for the North Atlantic Division. The commission regulates water quantity and quality within the basin, which spans approximately 13,500 square miles. In December 2010, the Delaware River Basin Commission published draft Natural Gas Development Regulations, which are currently under consideration for adoption, and the commission will not issue any permits for shale gas wells within the basin until the final regulations have been adopted. The draft regulations propose a number of requirements related to the protection of certain landscapes and waters and how to handle wastewater generated by natural gas development. For example, the proposed regulations require that produced water stored on the well pad be kept in enclosed tanks. In addition, operators of treatment and/or discharge facilities proposing to accept natural gas wastewater would be required to provide the commission with information on the contents of the proposed discharge and submit a study showing that the proposed discharge could be adequately treated. Natural gas well operators would also be required to have natural gas development plans for projects that exceed certain thresholds for acreage or number of wells. According to commission officials, the natural gas development plans would allow the commission to consider the cumulative impacts of development from numerous well pads, associated roads, and pipeline infrastructure, and to minimize and mitigate disturbance on lands most critical to water resources, such as core forests and steep slopes. The plans will also help protect water resources for approximately 15 million people, including residents of New York City and Philadelphia. All six states in our review have updated some aspects of their requirements in recent years. Key examples include the following: Colorado made extensive amendments to its oil and gas regulations in 2008, which included, among other things, restrictions on locating wells near drinking water sources, measures to manage stormwater, and requirements to consult with the Colorado Division of Wildlife in certain cases to minimize adverse impacts on wildlife. According to state officials, these regulatory updates served three primary purposes: (1) address the growing impacts of increased oil and gas development; (2) implement state legislation passed in 2007 directing the Colorado Oil and Gas Conservation Commission to work with the Colorado Department of Public Health and Environment and the Colorado Division of Wildlife to update its regulations; and (3) update existing rules to enhance clarity, respond to new information, and reflect current practices and procedures. In 2012, North Dakota implemented 26 rule changes, including the requirement for operators to drain pits and properly dispose of their contents within 72 hours after well completion, servicing, or plugging operations have ceased. According to state officials, this change was implemented in response to a number of pit overflows that occurred during the spring melt in 2010 and 2011. In 2012, Ohio adopted new oil and gas well construction regulations to implement state legislation passed in 2010. The new regulations include casing and cementing requirements and requirements to disclose the chemicals used in hydraulic fracturing. Pennsylvania passed legislation in 2012 which, among other things, requires unconventional wells to be sited at greater setback distances from existing buildings and water wells than was previously required for all wells and requires chemical disclosure through FracFocus. In addition, the new legislation increases the distance from which an operator of an unconventional well may be presumed liable in the event of pollution of nearby water wells from 1,000 feet to 2,500 feet. The Texas Commission on Environmental Quality updated its air emissions regulations for oil and gas facilities in 2011, including emissions limitations for nitrogen oxide and volatile organic compounds. Texas officials told us that changes included requirements for operators to install controls on stationary compressor engines and storage tanks. In addition, operators in the Dallas-Fort Worth area have agreed to voluntarily reduce emissions of volatile organic compounds by replacing pneumatic valves with no-bleed or low-bleed valves which helps to address nonattainment issues in the area while also reducing emissions of hazardous air pollutants. Texas also adopted a regulation in December 2011 regarding chemical disclosure requirements in order to implement state legislation passed several months earlier. In 2010, Wyoming updated its chemical disclosure requirements. According to state regulators, operators were always required to provide notification to the Wyoming Oil and Gas Conservation Commission before conducting hydraulic fracturing, but recent regulatory changes clarified these requirements and also added detailed requirements on what information was required to be disclosed. In the last 3 years, Colorado, Ohio, and Pennsylvania volunteered to have parts of their regulations reviewed by the State Review of Oil and Natural Gas Environmental Regulations (STRONGER) program, which is administered by the Ground Water Protection Council and brings together state, industry, and environmental stakeholders to review state oil and gas environmental regulations and make recommendations for improvement. Ohio and Pennsylvania have made regulatory changes that reflect STRONGER’s recommendations. For example, STRONGER completed a review of Pennsylvania’s regulations in September 2010. The review team commended the state for encouraging baseline groundwater testing in the vicinity of wells but also recommended that the state consider whether the testing radius should be expanded to take into account the horizontal portions of fractured wells. As discussed above, in 2012, Pennsylvania passed legislation that increases the distance from which an operator of an unconventional well may be presumed liable in the event of pollution of nearby water wells from 1,000 feet to 2,500 feet. State regulators said that the addition was in response to the state’s September 2010 STRONGER review and the Governor’s Marcellus Shale Advisory Commission. State regulators are also considering additional regulatory changes in response to the remaining recommendations of the Governor’s Marcellus Shale Advisory Board. Federal land management agencies, including the Bureau of Land Management (BLM), Forest Service, National Park Service, and Fish and Wildlife Service (FWS) manage federal lands for a variety of purposes. Specifically, both the Forest Service and BLM manage their lands for multiple uses, including oil and gas development; recreation; and provision of a sustained yield of renewable resources, such as timber, fish and wildlife, and forage for livestock. By contrast, the Park Service manages its lands to conserve the scenery, natural and historical objects, and wildlife so they remain unimpaired for the enjoyment of present and future generations. Similarly, FWS manages national wildlife refuges for the benefit of current and future generations, seeking to conserve and, where appropriate, restore fish, wildlife, plant resources, and their habitats. Each of these agencies imposes additional requirements for oil and gas development on its lands to meet its obligations with respect to its mission. These additional federal requirements are the same for conventional and unconventional oil and gas development. In some cases, the surface rights to a piece of land and the right to extract oil and gas—called mineral rights—are owned by different parties. For example, private mineral rights might underlie lands where the surface is managed by a federal agency. Requirements for developing mineral rights vary based on whether the mineral rights are owned by the federal government or by a private entity. Requirements for operators developing federally owned mineral rights are imposed by federal agencies during planning and leasing processes carried out by federal agencies. Operators must also meet specific requirements during several of the activities involved in oil and gas development. BLM has primary authority for issuing leases and permits for federal oil and gas resources even in cases when surface lands are managed by other federal agencies or owned by private landowners. The majority of federal oil and gas leases underlie lands managed by BLM or the Forest Service, but there are some federal oil and gas resources available for leasing under lands managed by other federal agencies or private landowners. Altogether, BLM oversees oil and gas development on approximately 700 million subsurface acres. Pub. L. No. 91-190 (1970), codified as amended at 42 U.S.C. §§ 4321-4347 (2012). either an environmental assessment or environmental impact statement.After the planning process, BLM takes the lead in preparing the NEPA analysis for leases when the surface lands are managed by BLM or owned by a private landowner (see table 6). For Forest Service lands, the Forest Service takes the lead in preparing the NEPA analysis and coordinates with BLM so that BLM’s subsequent leasing decision can be supported by the same analysis. At both agencies the NEPA review focuses on how the sale of leases may affect the environment and public health and, according to BLM officials, often includes mitigation measures that ultimately become stipulations on leases and permits for that tract of federal land. After the environmental impact statement is completed, BLM sells the lease to an operator through an auction or by other means. After acquiring a lease for the development of federal oil and gas, an operator is required to submit an application for permit to drill (APD) for individual wells to BLM. According to BLM officials, the APD is a comprehensive plan for drilling and related activities, which is approved by BLM. Prior to permit issuance for the proposed drilling activity, BLM is required to document that needed reviews under NEPA have been conducted. According to officials, at this step BLM conducts site-specific NEPA analysis, often drawing on the previous NEPA analysis conducted prior to the lease sale, but supplemented with more specifics about the proposed well site and related facilities, such as access roads or pipelines. The environmental review may also identify mitigation measures that could be used to reduce the environmental effects of drilling. The APD includes two key components: (1) the drilling plan, which describes the plan for drilling, casing, and cementing the well; and (2) the surface use plan of operations, which describes surface disturbances, such as road construction to the well pad and installation of any needed pipelines or other infrastructure. BLM is responsible for reviewing and approving the APD as a whole but gets input from the surface land management agency regarding the surface use plan of operations. For example, the Forest Service is responsible for review and approval of the surface use plan of operations component of the APD. After reviewing the operator’s APD, BLM approves the APD, often by attaching conditions of approval and requiring the operator to take mitigation measures as described in the environmental review or recommended by the surface land management agency. Once the APD is approved, and any state or local approvals are obtained, the operator can begin work. BLM has overall responsibility for ensuring compliance with approved APDs but coordinates with other surface land management agencies as appropriate. According to BLM officials, BLM is responsible for inspections and enforcement related to drilling operations, including running tests on casing and cementing. In addition, BLM officials said that they coordinate with surface land management agencies regarding surface conditions. Forest Service officials said that the Forest Service is responsible for conducting inspections relative to surface uses authorized by the surface use plan of operations. These officials said that if Forest Service personnel note possible noncompliance related to drilling or production operations, they notify and coordinate with BLM. Similarly, officials said that, if BLM conducts an inspection and notices potential violations of the surface use plan of operations, they contact the Forest Service. Operators of wells accessing federal oil and gas also face requirements related to activities involved in oil and gas development. Specifically, these requirements are related to siting and site preparation; drilling, casing, and cementing; well plugging; site reclamation; waste management and disposal; and managing air emissions. Requirements are as follows: Siting and site preparation. BLM requires an operator to identify all known oil and gas wells within a 1-mile radius of the proposed location. BLM does not require baseline testing of groundwater near the proposed well site. BLM generally prohibits an operator from conducting operations in areas highly susceptible to erosion, such as floodplains or wetlands, and recommends that operators avoid steep slopes and consider temporarily suspending operations when weather-related conditions, such as freezing or thawing ground, would cause excessive impacts. Drilling, casing, and cementing. As discussed above, operators must submit detailed drilling plans as part of their APD. The drilling plan must be sufficiently detailed for BLM to appraise the technical adequacy of the proposed project and must include, among other things: (1) geologic information about the formations that the operator expects to encounter while drilling; (2) whether these formations contain oil, gas, or useable water and, if so, how the operator plans to protect such resources; (3) a proposed casing plan, including details about the size of the casing and the depths at which each layer of casing will be set; (4) the estimated amount and type of cement to be used in the well; and (5) a description of any horizontal drilling that is planned. Well plugging. Operators are required to provide notice to and get approval from BLM prior to plugging a well and to comply with specific technical standards in plugging the well. Site reclamation. Operators describe their plans for reclamation in the surface use plan of operations submitted as part of the APD. BLM requires operators to return the disturbed land to productive use. All well pads, pits, and roads must be reclaimed and revegetated. Interim and final reclamation generally must be completed within 6 months of the well entering production and being plugged, respectively. Waste management and disposal. In the surface use plan of operations, operators must describe the methods and locations proposed for safe disposal of wastes, such as drill cuttings, salts, or chemicals that result from drilling the proposed well. The description must also include plans for the final disposition of drilling fluids and any produced water recovered from the well. Managing air emissions. For operations in formations that could contain hydrogen sulfide, BLM requires a hydrogen sulfide operations drilling plan, which describes safety systems that will be used, such as detection and monitoring equipment, flares, and protective equipment for essential personnel. In some cases, BLM and states may regulate similar activities; in such cases, operators must comply with the more stringent regulation. For example, North Dakota state requirements allow the use of pits only for short-term storage of produced water. BLM generally allows the use of pits for longer-term storage of produced water, but operators cannot do so on federal lands in North Dakota due to state requirements. See appendix X for a comparison of federal environmental requirements, state requirements, and additional requirements that apply on federal lands. BLM recently proposed new requirements for oil and gas development on federal lands. Specifically, in May 2012, BLM proposed regulations that update and add to its current requirements related to hydraulic fracturing. As proposed, these regulations would require operators of wells under federal leases to (1) publicly disclose the chemicals they use in hydraulic fracturing; (2) take certain steps to ensure the integrity of the well, including complying with certain cementing standards and confirming through mechanical integrity testing that wells to be hydraulically fractured meet appropriate construction standards; and (3) develop plans for managing produced water from hydraulic fracturing and store flowback water from hydraulic fracturing in a lined pit or a tank. According to BLM officials, BLM’s proposed rule is intended to improve stewardship and operational efficiency by establishing a uniform set of standards for hydraulic fracturing on public lands. According to BLM officials, a final rule is expected in the fall of 2012. Subject to some restriction, owners of mineral rights that underlie federal lands have the legal authority to explore for oil and gas and, if such resources are found, to develop them. Federal land management agencies’ authorities to control the surface impacts of drilling for privately owned minerals underlying federal lands vary based on a variety of factors, including which federal agency is responsible for managing the surface lands. According to BLM officials, private mineral owners seeking to develop oil and gas would need to obtain a right-of-way grant from BLM for any surface disturbance, including the well pad, but otherwise BLM has limited authority over the private owners’ use and occupancy of the BLM- managed surface lands. Officials said that BLM would have the same rights as a private surface owner under state law to hold a mineral rights owner to “reasonable surface use.” BLM officials explained that BLM would perform a NEPA analysis prior to issuing the right-of-way grant. According to officials, the agency applies its general regulations for granting rights of way, but BLM did not have specific guidance regarding oversight of private mineral operations on BLM lands. According to Forest Service officials, Forest Service authority related to the development of privately owned minerals is limited because private mineral owners have the legal right to develop such resources. The Forest Service manages a large number of wells accessing privately owned minerals. Specifically, Forest Service officials said that, of the 19,000 operating oil and gas wells on Forest Service lands, about three- fourths are producing privately owned minerals. Forest Service officials explained that the Forest Service evaluates the effects of the development and, through negotiations with the operator, tries to reach agreement on certain mitigation measures. Officials explained that these mitigation measures are generally not as stringent or specific as mitigation measures used on federal leases. In addition, Forest Service officials explained that enforcement options are limited for environmental damage from development of privately owned minerals. Generally, the Forest Service can work with state oil and gas agencies to have them enforce any relevant state requirements regarding surface impacts, or the Forest Service can seek an injunction from the court to stop damaging actions and then pursue possible damages or restitution via the court. According to Forest Service officials, development of privately owned minerals has been a particular challenge in the Alleghany National Forest in Pennsylvania where privately owned minerals underlie more than 90 percent of the forest. Forest Service officials stated that there are approximately 1,000 new wells drilled in this forest each year, most of which are shallow conventional oil development. Officials said that the pace of this development has made it difficult for the Forest Service to manage other forest uses, such as recreation and timber extraction. See GAO, National Wildlife Refuges: Opportunities to Improve the Management and Oversight of Oil and Gas Activities on Federal Lands, GAO-03-517 (Washington, D.C.: Aug. 28, 2003). partly because FWS does not currently have regulations that directly address oil and gas development. FWS officials said that the agency is developing a proposed rule that will set requirements for operators developing privately owned minerals. Officials expect an Advance Notice of Proposed Rulemaking to be issued in calendar year 2012. FWS officials said that, despite having minimal requirements for operators drilling for privately owned minerals, they can use other federal authorities and work with federal and state agencies to minimize or remediate injury to FWS lands. For example, FWS worked with EPA to respond to a spill of produced water into a stream on a National Wildlife Refuge in Louisiana in 2005, in violation of CWA. EPA, the Coast Guard, and the Department of Justice worked together on the case, and the operator ultimately paid $425,000 to FWS for the two affected wildlife refuges. According to agency officials, however, without specific regulations, FWS faces challenges conducting daily management and oversight of oil and gas activities on FWS lands. The Park Service’s 9B regulations govern potential impacts to all park system resources and values resulting from exercise of private oil and gas rights within Park Service administered lands. These regulations require an operator to submit a proposed plan of operations to the Park Service, which outlines the activities that are proposed for Park Service lands, including drilling, production, transportation, and reclamation. The regulations also outline certain requirements for operators, including that operations be located at least 500 feet from surface waters, that fences be used to protect people and wildlife, and that during reclamation the operator reestablish native vegetation. The Park Service analyzes the operator’s proposed plan of operations to ensure that the proposed plan complies with the 9B regulations. Also, in determining whether it can approve an operation, the Park Service undertakes an environmental analysis under NEPA. Once the Park Service approves the proposed plan of operations, the operator can begin drilling. The Park Service continues to have access to the site for monitoring and enforcement purposes. In November 2009, the Park Service issued an Advance Notice of Proposed Rulemaking to update its 9B regulations; a proposed rule is expected in September 2013, according to agency officials. Federal and state agencies reported facing several challenges in regulating oil and gas development from unconventional reservoirs. Specifically, EPA officials reported that their ability to conduct inspection and enforcement activities and limited legal authorities are challenges. In addition, BLM and state officials reported that hiring and retaining staff and educating the public are challenges. Officials at EPA reported that conducting inspection and enforcement activities for oil and gas development from unconventional reservoirs is challenging due to limited information, as well as the dispersed nature of the industry and the rapid pace of development. More specifically, according to EPA headquarters officials, enforcement efforts can be hindered by a lack of information in a number of areas. For example, in cases of alleged groundwater contamination, EPA would need to link changes in groundwater quality to oil and gas activities before taking enforcement actions. However, EPA officials said that often no baseline data exist on the quality of the groundwater prior to oil and gas development. These officials also said that linking groundwater contamination to a specific activity may be difficult even in cases where baseline data are available because of the variability and complexity of geological formations. As discussed earlier in this report, in 2005, the Energy Policy Act amended SDWA to specifically exempt hydraulic fracturing from the UIC program, unless diesel fuel is used in the hydraulic fracturing process. the agency does not know which operators are using diesel. Similarly, with respect to CWA, EPA officials said it is difficult to assess operators’ compliance with the SPCC program, which establishes spill prevention and response planning requirements in accordance with CWA, because EPA does not know the universe of operators with tanks subject to the SPCC rule. In addition, related to CAA, EPA headquarters officials said that it would be difficult for EPA to find oil and gas wells that are subject to but noncompliant with NESHAPs because EPA does not have information on the universe of oil and gas well sites with the equipment that are significant to air emissions. Also, according to EPA Region 8 officials, these requirements are “self-implementing,” and EPA would only receive notice from a facility that identifies itself as subject to the rules. Several EPA officials also mentioned that the dispersed nature of the industry and the rapid pace of development make conducting inspections and enforcement activities difficult. For example, officials in EPA Region 5 said that it is a challenge to locate the large number of new well sites across Ohio and to get inspectors out to these sites because EPA generally does not receive information about new wells or their location. EPA headquarters officials also mentioned that many oil and gas production sites are not continuously staffed, so EPA needs to contact operators and ensure that someone will be present before visiting a site to conduct an inspection. Officials in EPA Region 6 said that the dispersed nature of the industry, the high level of oil and gas development in the Region, and the cost of travel have made it difficult to conduct enforcement activities in their Region. EPA officials in headquarters said that SDWA is a difficult statute to enforce because of the variation across states. Specifically, SDWA authorizes EPA to approve, for states that elect to assume this responsibility, individual states’ programs as alternatives to the federal UIC Class II regulatory program. As a result, EPA’s enforcement actions have to be specific to each state’s program, which increases the complexity for EPA. In addition, SDWA requires that EPA approve each state’s UIC program by regulation rather than through an administrative process, and many of the federal regulations for state UIC programs are out of date. EPA officials said that this has hindered enforcement efforts, and some cases have been abandoned because EPA can only enforce those aspects of state UIC regulations that have been approved by federal regulation. EPA officials also reported that the scope of their legal authorities for regulating oil and gas development is a challenge. For example, EPA officials in headquarters and Regional offices told us that the exclusion of exploration and production waste from hazardous waste regulations under RCRA significantly limits EPA’s role in regulating these wastes. For example, if a hazardous waste permit was required, then EPA would obtain information on the location of well sites, how much hazardous waste is generated at each site, and how the waste is disposed of; however, operators are not required to obtain hazardous waste permits for oil and gas exploration and production wastes, limiting EPA’s role. As discussed earlier in this report, EPA is currently considering a petition to revisit the 1988 determination not to regulate these wastes as hazardous, but according to officials, has no specific time frame for responding. In addition, as we described earlier in this report, officials in Region 8 noted that EPA cannot use either its CERCLA or CWA emergency response authority to respond to spills of oil if there is no threat to U.S. navigable waters or adjoining shorelines because those statutory authorities do not extend to such situations. Officials at BLM, Forest Service, and state agencies reported challenges hiring and retaining staff. For example, BLM officials in North Dakota said recruiting is a challenge because the BLM pay scale is relatively low compared with the current cost of living near the oil fields in the Bakken formation. Similarly, BLM officials in North Dakota and headquarters both said that retaining employees is difficult because qualified staff are frequently offered more money for private sector positions within the oil and gas industry. BLM officials in Wyoming told us that their challenges related to hiring and retaining staff have made it difficult for the agency to keep up with the large number of permit requests and meet certain inspection requirements. We previously reported that BLM has encountered persistent problems in hiring, training, and retaining sufficient staff to meet its oversight and management responsibilities for oil and gas operations on federal lands. For example, in March 2010, we reported that BLM experienced high turnover rates in key oil and gas inspection and engineering positions responsible for production verification activities. We made a number of recommendations to address this and other issues—and the agency agreed—but we reported in 2011 that the human capital issues we identified with BLM’s management of onshore oil and gas continue. State oil and gas regulators in two of the six states we reviewed—North Dakota and Texas—also reported challenges with employees leaving their agencies for higher paying jobs in the private sector. Officials from the North Dakota Industrial Commission––which regulates oil and gas development––said they have partially mitigated this challenge by removing state geologists and engineers from the traditional state pay scale and offering signing and retention bonuses. In addition, state environmental regulators in three of the six states—North Dakota, Pennsylvania, and Wyoming—also mentioned challenges related to hiring or retaining staff. For example, air regulators in the Wyoming Department of Environmental Quality said that retaining qualified staff is challenging, as staff leave for higher-paying private sector positions. These officials said that 6 of their 22 air permit-writing positions are vacant as of June 2012. State regulators in Colorado and Ohio did not report facing this challenge. In addition, FWS officials reported that they have inadequate staffing for oil and gas development issues and noted that additional regional and field positions could help FWS implement a more comprehensive oil and gas program. BLM and state officials reported that providing information and education to the public is a challenge. Specifically, BLM headquarters officials mentioned that hydraulic fracturing has attracted the interest of the public and that BLM has been fielding many information requests about its use in oil and gas development. In addition, officials in five of the six states— Colorado, Ohio, Pennsylvania, Texas, and Wyoming—reported challenges related to public education. For example, regulators in Ohio said that their agency has conducted more public outreach in the last year than in the past 20 years and, in response to this public interest in shale drilling and hydraulic fracturing, they will be adding more communications staff. Similarly, oil and gas development is moving into areas of Colorado that are not accustomed to this development, and state officials in both the Department of Public Health and Environment and the Oil and Gas Conservation Commission said that they have spent a lot of time providing the public with information on topics including hydraulic fracturing. State regulators in Wyoming said that educating the public has been a challenge since coalbed methane and tight sandstone development in Wyoming is very different than, for example, shale gas development in Pennsylvania, but the media do not always make this clear. State regulators in North Dakota did not report public education as a challenge. We provided a draft of this report to EPA and to the Departments of Agriculture and the Interior for review and comment. The Departments of Agriculture and Interior provided written comments on the draft, which are summarized below and appear in their entirety in appendixes XI and XII, respectively. In addition, both Departments and EPA provided technical comments, which we incorporated as appropriate. In its written comments, the Department of Agriculture agreed with our findings and noted that the Forest Service also faces challenges hiring and retaining qualified staff. In response, we added this information to the report. In its written comments, the Department of the Interior provided additional clarifying information on its efforts concerning BLM’s proposed rule on hydraulic fracturing and steps BLM is taking to hire and retain skilled technical staff. In response, we included additional information in the report about BLM’s proposed rule on hydraulic fracturing. As agreed with your offices, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date. At that time, we will send copies of this report to the appropriate congressional committees, the EPA Administrator, the Secretaries of Agriculture and the Interior, the Director of the Bureau of Land Management, and other interested parties. In addition, this report will be available at no charge on the GAO website at http://www.gao.gov. If you or your staff members have any questions about this report, please contact me at (202) 512-3841 or trimbled@gao.gov. Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report. GAO staff who made major contributions to this report are listed in appendix XIII. To identify federal and state environmental and public health requirements governing onshore oil and gas development from unconventional reservoirs, we analyzed federal and state laws, regulations, and guidance, as well as reports on federal and state requirements. We defined unconventional reservoirs as including shale gas deposits, shale oil, coalbed methane, and tight sandstone formations. We focused our analysis on requirements that apply to activities on the well pad and wastes or emissions generated at the well pad rather than on downstream infrastructure such as pipelines or refineries. In particular, we identified and reviewed eight key federal environmental and public health laws, specifically the Safe Drinking Water Act; Clean Water Act; Clean Air Act; Resource Conservation and Recovery Act; Comprehensive Environmental Response, Compensation, and Liability Act; Emergency Planning and Community Right-to-Know Act; Toxic Substances Control Act; and Federal Insecticide, Fungicide, and Rodenticide Act. We also reviewed corresponding regulations such as the Environmental Protection Agency’s (EPA) New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants for the Oil and Gas Industry and guidance such as EPA’s Guidance for Implementation of the General Duty Clause of the Clean Air Act. To identify state requirements, we identified and reviewed laws and regulations in a nonprobability sample of six selected states—Colorado, North Dakota, Ohio, Pennsylvania, Texas and Wyoming. We selected states with current unconventional oil or gas development and large reservoirs of unconventional oil or gas. In addition, we ensured that the selected states included a variety of types of unconventional reservoirs, differing historical experiences with the oil and gas industry, and that some of the selected states have significant oil and gas development on federal lands. Because we used a nonprobability sample, the information that we collected from those states cannot be generalized to all states but can provide illustrative examples. To complement our analysis of federal and state laws and regulations, we interviewed officials in federal and state agencies to discuss how federal and state requirements apply to the oil and gas industry (see table 7). In particular, we interviewed officials in EPA headquarters and four Regional offices where officials are responsible for implementing and enforcing programs within the six states we selected, including Region 3 for Pennsylvania, Region 5 for Ohio, Region 6 for Texas, and Region 8 for Colorado, North Dakota, and Wyoming. We also interviewed state officials responsible for implementing and enforcing requirements governing the oil and gas industry and environmental or public health requirements in each of the six states we selected. For three of these states—Colorado, North Dakota, and Wyoming—we conducted these interviews in person. We also interviewed officials from the Delaware River Basin Commission—a regional body that manages and regulates certain water resources in four states, including Pennsylvania. We also contacted officials from environmental, public health, and industry organizations to gain their perspectives and to learn about ongoing litigation or petitions that may impact the regulatory framework. We selected environmental organizations that had made public statements about federal or state requirements for oil and gas development and public health organizations representing state and local health officials and communities. The selected organizations are a nonprobability sample, and their responses are not generalizable. In addition, we visited drilling, hydraulic fracturing, and production sites in Pennsylvania and North Dakota and met with company officials to gather information about these processes and how they are regulated at the federal and state levels. We selected these companies based on their operations in the six states we selected. To identify additional requirements that apply to unconventional oil and gas development on federal lands, we reviewed laws, such as the National Environmental Policy Act (NEPA), as well as regulations and guidance promulgated by the Bureau of Land Management (BLM), Fish and Wildlife Service (FWS), Forest Service, and National Park Service. We also interviewed officials responsible for overseeing oil and gas development on federal lands, including officials in BLM headquarters and in field offices in the states we selected where there is a significant amount of oil and gas development on federal lands, including Colorado, North Dakota, and Wyoming; and in National Park Service, Forest Service, and FWS headquarters. Oil and gas development may also be subject to tribal or local laws, but we did not include an analysis of these laws in the scope of our review. To determine challenges that federal and state agencies face in regulating oil and gas development from unconventional reservoirs, we reviewed several reports conducted by environmental and public health organizations, industry, academic institutions, and government agencies that provided perspectives on federal and state regulations and associated challenges. We also collected testimonial evidence, as described above, from knowledgeable federal and state officials, as well as industry, environmental, and public health organizations. We conducted this performance audit from November 2011 to September 2012 in accordance with generally accepted government auditing standards. Those standards require that we plan and perform the audit to obtain sufficient, appropriate evidence to provide a reasonable basis for our findings and conclusions based on our audit objectives. We believe that the evidence obtained provides a reasonable basis for our findings and conclusions based on our audit objectives. The Safe Drinking Water Act (SDWA or the Act) was originally passed by Congress in 1974 to protect public health by ensuring a safe drinking water supply. Under the act, EPA is authorized to set standards for certain naturally-occurring and man-made contaminants in public drinking water systems, among other things. Key aspects of SDWA for unconventional oil and gas development include provisions regarding underground injection and EPA’s imminent and substantial endangerment authority. SDWA also regulates the placement of wastewater and other fluids underground through the Underground Injection Control (UIC) program.This program provides safeguards to ensure that wastewater or any other fluid injected underground does not endanger underground sources of drinking water; these sources are defined by regulation as an aquifer or its portion: 1) (i) Which supplies any public water system; or (ii) Which contains a sufficient quantity of groundwater to supply a public water system; and (A) Currently supplies drinking water for human consumption; or (B) Contains fewer than 10,000 mg/l total dissolved solids; and 2) Which is not an exempted aquifer. Thus, the program is intended to protect not only those aquifers (or portions thereof) that are currently used for drinking water, but those that possess certain physical characteristics indicating they may be viable future drinking water sources. EPA regulations establish criteria for exempting aquifers.the regulations establish that the criterion that an aquifer “cannot now and In particular, will not in the future serve as a source of drinking water” may be met by demonstrating that the aquifer is mineral, hydrocarbon or geothermal energy producing, or demonstrated by a permit applicant as having commercially producible minerals or hydrocarbons. States or EPA typically initially identified exempt aquifers when UIC programs were established, and according to EPA, states may have added exempt aquifers since then. While EPA has the information from the initial applications, the agency does not have complete information for the additional exemptions, although under EPA regulations certain of these subsequent exemptions are considered program revisions and must be approved by EPA. EPA is currently collecting information about the location of all exempted aquifers, and an official estimated that there are 1,000-2,000 such designations (including portions of aquifers). There are six classes or categories of wells regulated through the UIC program. Class II wells are for the management of fluids associated with oil and gas production, and they include wells used to dispose of oil and gas wastewater and those used to enhance oil and gas production. SDWA § 1422(b)(2), 42 U.S.C. § 300h-1(b)(2) (2012). See also SDWA §§ 1421(b)(1), 1422(b)(1), (3), 42 U.S.C. §§ 300h(b)(1), 300h-1(b)(1), (b)(3) (2012) (establishing requirements and responsibilities for states with primacy). permitting, monitoring, and enforcement for UIC wells within the state. Generally, to be approved as the implementing authority (primacy), state programs must be at least as stringent as the federal program and show that their regulations contain effective minimum requirements for each of the well classes for which primacy is sought. Alternately, SDWA section 1425 provides that to obtain this authority over Class II wells only, a state with an existing oil and gas program may, instead of meeting and adopting the applicable federal regulations, demonstrate that its program is effective in preventing endangerment to underground sources of drinking water. With respect to the six states in this review, Texas, North Dakota, Colorado, Wyoming, and Ohio have each been granted primacy for Class II wells under the alternative provisions (SDWA section 1425). EPA directly implements the entire UIC program in Pennsylvania. Class II wells include saltwater (brine) disposal wells, enhanced recovery wells, and hydrocarbon storage wells. These wells are common, particularly in states with historical oil and gas activity. EPA officials estimate there are approximately 151,000 Class II UIC wells in operation in the United States; about 80 percent of these wells are for enhanced recovery, about 20 percent are for disposal, and there are approximately 100 wells for hydrocarbon storage. In Pennsylvania, the one state in our review in which EPA directly implements the Class II program, EPA Region 3 officials stated that there are five active Class II disposal wells. Recently, Region 3 issued permits for two Class II disposal wells in Pennsylvania, which were appealed. On appeal, the Environmental Appeals Board remanded the permits back to EPA for further consideration, finding that the Region failed to clearly articulate its regulatory obligations or compile a record sufficient to assure the public that the Region relied on accurate and appropriate data in satisfying its obligations to account for and consider all drinking water wells within the area of review of the injection wells. The Environmental Appeals Board denied all other claims against EPA. Under the remand, EPA may take further action consistent with the decision, which could include such actions as additions or revisions to the record and reconsideration of the permits. With respect to applications, according to Region 3 officials, until recently EPA did not receive many applications for new Class II brine disposal wells in Pennsylvania. EPA officials said that they have received five permit applications for such wells in the last 4 months and expect continued interest in the future. Under SDWA, UIC programs are to prohibit underground injection, other than into a well that is authorized by rule or permitted. Class II UIC wells must meet requirements contained in either EPA regulations, or relevant state regulations. Federal regulations for Class II wells include construction, operating, monitoring and testing, reporting, and closure requirements. For example, one requirement of federal regulations is that all of the preexisting wells located in the area of review, and that were drilled into the same formation as the proposed injection well must be identified. For such wells which are improperly sealed, completed, or abandoned, the operator must also submit a plan of actions necessary to prevent movement of fluid into underground sources of drinking water— known as ‘‘corrective actions,’’ such as plugging, replugging, or operational pressure limits—which are considered in permit review. Permits may be conditioned upon a compliance schedule for such corrective actions. According to EPA, in Pennsylvania many old wells have had to be replugged in order to ensure they cannot present a potential pathway for migration. Regarding seismicity concerns, the federal regulations for Class II UIC wells require applicants for Class II UIC wells to identify faults if known or suspected in the area of review. requirement that a well must be sited to inject into a formation that is separated from any protected aquifer by a confining zone that is free of known open faults or fractures within the area of review. In a permit process, EPA (in direct implementation states) or the state can require additional information (including geology) to ensure protection of underground sources of drinking water. For example, Region 3 officials said the Region routinely determines whether there is the potential for fluid movement out of the injection zone via faults and fractures, as well as abandoned wells, by calculating a zone of endangering influence around the injection operation. Under the general standard, if a proposed or ongoing injection was, due to seismicity, believed to endanger underground sources of drinking water, EPA or the state could act, as the burden is on the applicant to show the injection well will not endanger such sources.line that was not identified or known at the time of the UIC permit approval, EPA (in direct implementation states) or the state can go back to the well owner or operator and ask for additional information, which the owner or operator would be obligated to provide. In addition there is a general Officials said that if a seismic event occurs along a fault For additional information on the Class II UIC requirements applicable under EPA’s program in Pennsylvania, see appendix IX. 40 C.F.R. §§ 146.24, 146.24(a)(2) (2012). Historically, UIC programs did not include hydraulic fracturing injections as among those subject to their requirements. In 1994, in light of concerns that hydraulic fracturing of coalbed methane wells threatened drinking water, the Legal Environmental Assistance Foundation petitioned EPA to withdraw its approval of Alabama’s Class II UIC program. EPA denied the petition, but on appeal, the United States Court of Appeals for the Eleventh Circuit held that the definition of underground injection included hydraulic fracturing and ordered EPA to reconsider the issue. Subsequently, Alabama revised its program to include injection of hydraulic fracturing fluids, and EPA approved it pursuant to SDWA section 1425 in 2000. The Legal Environmental Assistance Foundation appealed the approval and, in 2001, the Eleventh Circuit partially remanded the approval, directing EPA to regulate hydraulic fracturing as Class II UIC wells rather than a Class II-like activity. Alabama amended its regulations in 2001 and 2003. EPA issued a determination in 2004 addressing the question on remand and found that the hydraulic fracturing portion of Alabama’s UIC program relating to coalbed methane production, which was previously approved under the alternative effectiveness provision, complied with the requirements for Class II UIC wells. EPA initiated a study in 2000 to further examine the issue of fracturing in coalbed methane in areas of underground sources of drinking water. EPA officials said the study showed diesel fuel was the primary risk. Subsequently, in 2003, EPA entered into a memorandum of agreement with three major fracturing service companies in which the companies voluntarily agreed to eliminate diesel fuel in hydraulic fracturing fluids injected into coalbed methane production wells in underground sources of drinking water. According to EPA officials, the agreement is still in effect insofar as the agency has not received any termination notices. EPA officials did not know of any permits issued by Alabama, or any other state, for hydraulic fracturing injections during this time frame. EPA also did not modify its direct implementation of Class II UIC programs to expressly include hydraulic fracturing. On December 7, 2004, EPA’s Assistant Administrator for Water responded to a congressional request for information on EPA’s actions on this issue. The letter summarizes EPA’s study findings—that the potential threat to underground sources of drinking water posed by hydraulic fracturing of coalbed methane wells is low, but there is a potential threat through the use of diesel fuel as a constituent of fracturing fluids where coalbeds are colocated with an underground source of drinking water. Pub. L. No. 109–58 § 322, 119 Stat. 594 (2005) (modifying SDWA § 1421(d)(1), 42 U.S.C. § 300h(d)(1) (2012)). fluids other than diesel fuel in connection with hydraulic fracturing is not subject to federal UIC regulations, including both EPA direct implementation requirements and federal minimum requirements for state programs. The provision, however, did not exempt injection of diesel fuels in hydraulic fracturing from UIC programs. EPA has prepared a draft guidance document to assist with permitting of hydraulic fracturing using diesel fuels under SDWA UIC Class II; a public comment period for this draft guidance closed in August 2012. EPA explained that the guidance does not substitute for UIC Class II regulations, rather the guidance focuses on specific topics useful for tailoring Class II requirements to the unique attributes of hydraulic fracturing when diesel fuels are used. EPA’s draft guidance is applicable to any oil and gas wells using diesel in hydraulic fracturing (not just coalbed methane wells). The draft guidance provides recommendations related to permit applications, area of review (for other nearby wells), well construction, permit duration, and well closure. The guidance states that it does not address state UIC programs, although states may find it useful. EPA officials told us that they recently identified wells for which publicly available data suggest diesel was used in hydraulic fracturing. EPA officials stated the agency also has some information on diesel use in hydraulic fracturing of shale formations from a 2011 congressional investigation. EPA officials said there are no EPA-issued permits authorizing diesel to be used in hydraulic fracturing, and they believe no applications for such permits have been submitted to EPA to date. EPA officials also said that they were not aware of any state UIC programs that had issued such permits. Generally, EPA is authorized to enforce any applicable requirement of a federal or state UIC program as promulgated in 40 C.F.R. pt. 147, including Class II UIC programs approved under the alternative provision. However, according to officials, EPA has not promulgated all of the states’ modifications to UIC programs, and the federal regulations are out-of-date, hindering EPA’s ability to directly enforce some state program provisions. EPA may issue administrative orders or, with the Department of Justice, initiate a civil action when a person violates any requirement of an applicable UIC program. Where a state has primacy, EPA must first notify the state, and may act after 30 days if the state has not commenced an appropriate enforcement action. SDWA also provides EPA with authority to access records, inspect facilities, and require provision of information. Specifically, EPA has authority, for the purpose of determining compliance, to enter any facility or property of any person subject to an applicable UIC program, including inspection of records, files, papers, processes, and controls. Under EPA’s UIC program enforcement authorities, EPA has issued administrative compliance orders and administrative penalty orders relating to SDWA UIC Class II Wells. According to officials, most cases are administrative and handled at the Regional level. Officials said that there were more than 200 administrative orders related to the UIC program from 2004-2008 and that it is likely that a majority of these were related to Class II wells. For example, EPA Region 3 signed a consent agreement in Venango County, Pennsylvania, where injections of produced water were made into abandoned wells not permitted under the UIC program. In another case, Region 3 told us it has issued an administrative order against an operator for failure to conduct mechanical integrity tests. According to EPA, the order requires the operator to plug many of these wells, and to bring the wells they plan to continue to operate into compliance with their financial responsibility. Region 3 also took a penalty action against an operator for failure to report a mechanical integrity failure and continued operation after the failure. According to officials, EPA was able to confirm during well rework that there was no fluid movement outside the well’s casing and no endangerment to an aquifer. While SDWA generally does not directly regulate land use activities that may pose risk to drinking water supplies, SDWA gives EPA authority to issue imminent and substantial endangerment orders or take other actions deemed necessary “upon receipt of information that a contaminant which is present in or is likely to enter a public water system or an underground source of drinking water…which may present an imminent and substantial endangerment to the health of persons, appropriate State and local authorities have not acted to protect the health of such persons.” As noted above, the term “underground source of drinking water” includes not only active water supplies but also aquifers (or portions thereof) with certain physical characteristics. EPA has used this imminent and substantial endangerment authority in several incidents where oil or gas wells have been alleged to contaminate drinking water. For example, EPA Region 8 has conducted long-term investigation and monitoring of groundwater contamination from an oilfield in Poplar, Montana, of a water supply serving Poplar, as well as the Fort Peck Indian Reservation. EPA determined that there are several plumes of produced water (brine) in the East Poplar aquifer, which supplies private and public drinking water wells. Several pathways of contamination have been identified, including unlined pits, spills, and a leaking plugged oil well. EPA issued a SDWA imminent and substantial endangerment order in 2010 to three companies operating wells in the oilfield, each of which challenged the order in federal court. Following mediation, EPA and the parties entered an administrative order on consent in which the parties agreed to monitor the public drinking water supply for specified parameters and, if certain triggers are met or exceeded, to take actions to ensure the public water system meets water quality standards and pay reimbursement costs to the public water system. In another case, on December 7, 2010, EPA issued an administrative order to a well operator in Texas alleging methane contamination affecting private wells and directly related to its oil and gas production EPA subsequently filed a complaint in U.S. District Court facilities. seeking injunctive relief to enforce the order’s requirements and civil penalties for the operator’s noncompliance with the order. A few days later, the operator filed a petition for review of the order with the Fifth Circuit Court of Appeals. The operator’s position was that the order is not a final agency action and that EPA has the burden of proving its claim in the district court enforcement action, and its enforcement would violate due process. On March 29, 2012, EPA withdrew its administrative order, and the parties moved for voluntary dismissal of both cases. In a letter to EPA, the operator agreed to conduct sampling of 20 private water wells for 1 year. Under the Clean Water Act (CWA), EPA regulates discharges of pollutants to waters of the United States; for the purpose of this document, we generally refer to such waters, including jurisdictional rivers, streams, wetlands, and other waters, as surface waters. Discharges may include wastewater, including produced water, and stormwater. In addition, together with the U.S. Army Corps of Engineers, EPA regulates discharge of dredged or fill material into these waters. Under CWA section 311 and the Oil Pollution Act, establish, in relevant part, requirements for the prevention of, preparedness for, and response to oil discharges at certain facilities, including among others oil drilling and production facilities.requirements may include Facility Response Plans and Spill Prevention, Control, and Countermeasure (SPCC) Plans. EPA also has certain response and enforcement authorities relevant to these requirements. This review focuses on EPA regulatory activities under these programs relevant to unconventional oil and gas development activities. CWA § 311, 33 U.S.C. § 1321 (2012); Oil Pollution Act of 1990, Pub. L. No. 101-380, 104 Stat. 484 (classified as amended at 40 U.S.C. ch. 40, §§ 2701 – 2761 (2012) and amending sections of CWA). See also Exec. Order 12,777, 56 Fed. Reg. 54,757 (1991). CWA is the primary federal law designed to restore and maintain the chemical, physical, and biological integrity of the nation’s waters. Among other things, EPA and delegated states administer CWA’s National Pollutant Discharge Elimination System (NPDES) program, which limits the types and amounts of pollutants that facilities such as industrial and municipal wastewater treatment plants may discharge into the nation’s surface waters. Facilities such as municipal wastewater treatment plants and industrial sites, including oil and gas well sites, need a permit if they have a point source discharge to surface waters. Other than stormwater runoff as discussed below, discharges of pollutants from an oil or gas well site to surface water require an NPDES permit. According to EPA, wastewater associated with shale gas extraction can include total dissolved solids, fracturing fluid additives, metals, and naturally occurring radioactive materials, and may be disposed by transport to publicly- owned or other wastewater treatment plants, particularly in some locations where brine disposal wells are unavailable. According to EPA, produced water from coalbed methane gas extraction can include high salinity and pollutants such as chloride, sodium, sulfate, bicarbonate, fluoride, iron, barium, magnesium, ammonia, and arsenic, and some produced water is discharged to surface water in certain geographical areas. EPA and delegated states issue discharge permits that set conditions in accordance with applicable technology-based effluent limitations guidelines that EPA has established for various industrial categories, and may also include water-quality based effluent limitations. When EPA issues effluent limitations guidelines for an industrial category, it may include both limitations for direct dischargers (point sources that introduce pollutants directly into waters of the United States) and pretreatment standards applicable to indirect dischargers (facilities that discharge into publicly-owned wastewater treatment plants). EPA has developed effluent limitations guidelines for several subcategories of the oil and gas extraction industry. The guidelines generally apply to facilities engaged in the production, field exploration, drilling, well completion, and well treatment in the oil and gas extraction industry. The guidelines applicable to the wells in the scope of this review—essentially, oil and gas wells located on land and drilling unconventional reservoirs—include those for the onshore subcategory, agricultural and wildlife water use subcategory, and stripper wells. The guidelines for these subcategories were finalized in 1979. For the onshore and agricultural and wildlife water use subcategories, EPA established effluent limitations guidelines for direct dischargers. EPA did not establish guidelines for stripper wells, explaining that unacceptable economic impacts would occur from use of the then- evaluated technologies, and that the agency could revisit this decision at a later date. EPA officials we spoke with said that they are not aware of any reconsideration of this decision, and that this is not an issue on the current regulatory agenda. EPA also did not establish pretreatment requirements for either onshore or stripper well subcategories. Existing effluent limitations guidelines do not apply to wastewater discharges from coalbed methane extraction. As EPA subsequently explained, because there was no significant coalbed methane production in 1979, the oil and gas extraction rulemakings did not consider coalbed methane extraction in any of the supporting analyses or records. EPA officials also told us that the coalbed methane process is fundamentally different than traditional oil and gas exploration because of the volume of water that must be removed from the coalbed before production can begin, which they see as a significant distinction for potentially applicable technology. As will be discussed later in this appendix, in October 2011, EPA announced its intention to develop effluent limitations guidelines and standards for wastewater discharges from the coalbed methane industry. When an oil and gas well proposing to discharge pollutants to a surface water is not covered by the existing guidelines, effluent limitations included in the permit are determined on a case-by-case basis by the relevant permitting authority, using best professional judgmentapplicable state rules or guidance. EPA officials were not aware of any other unconventional oil and gas extraction processes, besides coalbed methane extraction, that are not covered by the existing effluent limitations guidelines. Table 8 summarizes the coverage and key requirements of the existing guidelines. there shall be no discharge of waste water pollutants into navigable waters from any source associated with production, field exploration, drilling, well completion, or well treatment (i.e., produced water, drilling muds, drill cuttings, and produced sand). Because an NPDES permit is only required where a facility discharges or proposes to discharge a pollutant, and as the technology-based requirement of “no discharge” must be applied in the permit, facilities subject to a “no discharge” limit are not required to apply for such permits. According to the 1976 Federal Register Notice of the Proposed Rule, technologies for managing produced water to achieve no discharge to surface waters were expected to include evaporation ponds, or underground injection, either for enhanced recovery of oil or gas in the producing formation or for disposal to a deep formation. Further, EPA indicated that drilling muds, drill cuttings, well treatment wastes, and produced sands would be disposed by land disposal so as not to reach navigable waterways. The effluent limitations guideline for the Oil and Gas Extraction point source category also established a subcategory for Agricultural and Wildlife Water Use to cover a geographical subset of operations in which produced water is of good enough quality to be used for wildlife or livestock watering or other agricultural uses and that the produced water is actually put to such use during periods of discharge. This subcategory guideline is only applicable to facilities located west of the 98th meridian, which extends from approximately the eastern border of North Dakota south through central Texas. EPA explained in the preamble to this rule that “t is intended as a relatively restrictive subcategorization based on the unique factors of prior usage in the Region, arid conditions and the existence of low salinity, potable water.” “no discharge of waste pollutants into navigable waters from any source (other than produced water) associated with production, field exploration, drilling, well completion, or well treatment (i.e., drilling muds, drill cuttings, and produced sands),” and for produced water discharges a daily maximum limitation of 35 milligrams per liter of oil and grease. At oil and gas well sites meeting the conditions of location, produced water quality, and use of produced water for wildlife or livestock watering or agricultural use, the produced water may be discharged to waters of the United States. In terms of water quality, the produced water must be and must not exceed the daily maximum for “good enough” for this use, oil and grease. States generally issue these permits, and are responsible for determining whether the water is of appropriate water quality for the beneficial use.guidance on this topic. EPA is responsible for oversight and has not issued EPA has not revised the guildeines, such as to add limitations for additional pollutants, to define “good enough” water quality, or to establish potentially more stringent guidelines. EPA officials stated that it has not done so because in certain locations the produced water from oil and gas development is high quality, and because treatment would cost more than injection, thus discouraging the beneficial use of this water. With respect to the subcategories of oil and gas wells covered by the effluent limitations guidelines, discharges are authorized only for oil and gas wells under the Agricultural and Wildlife Water Use and Stripper well subcategories. These well sites that discharge wastewater to surface waters must, as noted above, obtain a NPDES permit from the permitting authority (state, tribe, or EPA). The permit is to incorporate the applicable effluent limitations guideline, if one exists, and include effluent monitoring and reporting requirements. Officials also stated that individual permits may contain limits for pollutants other than oil and grease. According to EPA, 349 discharge permits in the Agricultural and Wildlife Water Use subcategory have been issued. Most of these permitted discharges are located in Wyoming, Montana, and Colorado. On October 26, 2011, EPA announced in its Final 2010 Effluent Limitations Program Plan that the agency will develop effluent limitations guidelines and standards for wastewater discharges from the coalbed methane extraction industry. With respect to coalbed methane extraction, as noted above, there is no existing effluent limitations guideline applicable to associated wastewaters. Coalbed methane operations discharging wastewaters to surface waters must nonetheless obtain a NPDES permit, but in the absence of a federal effluent limitations guideline, the permitting authority determines the permit limits based on best professional judgment, as well as any applicable state rules or guidelines. EPA had identified the industry for consideration in prior years, and initiated work leading to a detailed study beginning in 2007. found that states are primarily issuing individual permits, but they are also issuing some general permits and watershed permits covering one or more wells through a streamlined process. According to EPA officials, eastern states have generally based effluent limitations in permits on the coal mining effluent limitations guideline, although that guideline does not have limitations for total dissolved solids or chlorides that are key components of produced water. In the six states reviewed, EPA identified 861 coalbed methane discharge permits.most coalbed methane wastewater discharges have NPDES permits. initiate rulemaking. EPA is in the preproposal stage of rulemaking for the coalbed methane effluent guidelines and standards.indicates the projected date for publication of the proposed rule is June 2013. Facilities discharging industrial wastewater to publicly-owned treatment works (POTW) treatment plants are subject to general pretreatment requirements. In addition, the POTW receiving such industrial wastewaters also has responsibilities related to its own permit and to receiving these wastewaters. EPA has issued general pretreatment requirements applicable to all existing and new indirect dischargers of pollutants (other than of purely domestic, or sanitary, sewage) to a POTW, including any dischargers of wastewaters associated with oil and gas wells. Notably, such discharges are subject to a general requirement that the pollutants do not cause pass through or interference with the POTW. For a discharge to cause pass through, it must contribute to violation of the POTW’s NPDES permit; to cause interference, it must contribute to the noncompliance of its sewage sludge use or disposal. Other standard provisions for indirect discharges involve a prohibition on corrosive discharges. According to EPA officials, in produced water, concerns for corrosivity would be related to high chlorides and sulfides which could adversely affect pipes and gaskets in the POTW. EPA has stated that NPDES permits for POTWs typically do not contain effluent limits for some of the pollutants of concern from shale gas wastewater, and that some of these pollutants may be harmful to aquatic Specifically, if a POTW did not include information in its NPDES life. permit application indicating that the POTW would receive oil and gas wastewater, or did not otherwise adequately characterize the incoming wastewater as including certain pollutants of concern, the permit may not include limits for these pollutants, as permits generally only contain limits for those pollutants reasonably expected to be present in the wastewater. Regarding pass through, in which an indirect industrial discharger contributes to violation of the receiving POTW’s NPDES permit, Region 3 officials said that POTW operators had not indicated that NPDES violations were caused by oil and gas wastewaters received at the plant, with the following exception. In 2011, EPA issued an administrative order for compliance and request for information to a POTW in New Castle, Pennsylvania, in relation to permit effluent limit violations. The POTW experienced violations of its suspended solids limits spanning over a year, and attributed the violations to salty wastewater from natural gas production it was receiving. The order required the POTW to take several actions including to cease accepting oil and gas exploration and production wastewater until completing an evaluation and sampling, and to eliminate and prevent recurrence of the violations. Generally, local governments operating POTWs are responsible for ensuring that indirect dischargers comply with any applicable national pretreatment standards. Certain POTWs are required to develop pretreatment programs, which set out a facility’s approach to developing, issuing, and enforcing pretreatment requirements on any indirect dischargers to the particular plant. EPA or states may be responsible for ensuring these POTWs meet their obligations and for approving the POTW’s pretreatment plans. According to EPA, regardless of pass through or interference, POTWs should not accept indirect discharges of produced water if the wastewaters have different characteristics than those for which the POTW was originally permitted, without providing adequate notice to the permitting authority. If a POTW accepts oil and gas wastewater with characteristics that were not considered at the time of the permit issuance, then the permit may not adequately protect the receiving water from potential violations of water quality standards. In other words, a POTW may meet its permit limits, yet still contribute to a violation of water quality standards, if the permit does not reflect consideration of all the pollutants actually present, and their concentrations, in the incoming wastewater and in the discharge. According to Region 3 officials, EPA has conducted several investigations of whether discharges from POTWs accepting oil and gas wastewater have prevented receiving waters from meeting water quality standards. Region 3 officials stated that a major impediment to this evaluation was that the NPDES permits reviewed did not have effluent limits or monitoring requirements for the pollutants of concern. EPA also stated that it has data from a 2009 Pennsylvania Department of Environmental Protection violation report documenting a fishkill attributed to a spill of diluted produced water in Hopewell Township, PA. In March 2011, EPA’s Office of Water issued to the Regions a set of questions and answers that provide state and federal permitting authorities in the Marcellus shale region with guidance on permitting treatment and disposal of wastewater from shale gas extraction. guidance states that POTWs must provide adequate notice to the permitting authority (EPA or the authorized state) of any new introduction of pollutants into the POTW from an indirect discharger, if the discharger would be subject to NPDES permit requirements if it were discharging directly to a surface water, among other things. EPA officials indicated that if a POTW is accepting types of wastewater that were not on its original application, EPA could require a modification of the POTW’s NPDES permit, or object to a NPDES renewal that did not address these wastewaters and the facility’s ability to treat them. POTWs may also initiate inclusion of these wastewaters in their permits or permit renewals. For example, EPA Region 3 officials stated that four POTW operators in Pennsylvania in the NPDES renewal process have indicated the intent to continue accepting oil and gas wastewater. In addition, in cases with pass through or interference, EPA could require a POTW to develop a pretreatment program. EPA’s website indicates the agency plans to supplement the existing Office of Water questions and answers document with additional guidance directed to permitting authorities, pretreatment control authorities and POTWs, to provide assistance on how to permit POTWs and other centralized wastewater treatment facilities by clarifying existing CWA authorities and obligations. Specifically, EPA plans to issue two guidance documents, one for permit writers and another for POTWs. With respect to shale gas extraction, the effluent limitations guideline for the onshore subcategory in effect since 1979 has prohibited direct discharges of associated wastewaters; however, EPA has not established pretreatment standards for indirect discharges of such wastewaters. EPA requested and received comments on whether to initiate a rulemaking for the industry in recent years. In 2011, EPA announced it will initiate a rulemaking to develop such pretreatment standards. EPA reviewed existing data, but did not conduct a study to develop data as it had for coalbed methane. EPA found that pollutants in wastewaters associated with shale gas extraction are not treated by the technologies typically used at POTWs or many centralized treatment facilities. the potential to affect drinking water supplies and aquatic life. On this basis, EPA concluded that pretreatment standards are appropriate and decided to initiate a rulemaking. EPA intends to conduct a survey, among other things, to collect information on management of produced water to support the rulemaking. Finally, EPA noted that if it obtains information indicating that POTWs are already adequately treating shale gas wastewater, the agency could adjust the rulemaking plans accordingly.operators of Marcellus shale gas wells stop delivering produced water to POTWs, potentially avoiding the issue. EPA officials stated that other states may nonetheless have a need to utilize POTWs to address these wastewaters and hence could benefit from pretreatment standards. Further, EPA stated that resulting discharges have For example, the state of Pennsylvania requested that EPA is in the preproposal stage of this rulemaking, and EPA’s website indicates the projected date for publication of the proposed rule is 2014. 76 Fed. Reg. at 66,295-96. According to EPA, POTWs typically have permits that do not contain limits for the pollutants of concern in shale gas wastewater; the secondary treatment requirements do not address such pollutants, and is it uncommon for these permits to contain water quality based limitations for such pollutants. Id. at 66,297. Thus, such wastewaters likely pass through the POTWs receiving such wastewaters and the POTWs may not monitor for these pollutants in their effluent. Id. at 66,297. In 1987, the Water Quality Act amended CWA to establish a specific program for regulating stormwater discharges of pollutants to waters of the United States. Among other things, the amendments clarified EPA authority to require an NPDES permit for discharges of stormwater from several categories, including in relevant part those associated with industrial activity and construction activity. EPA subsequently issued regulations that address stormwater discharges from several source categories, including certain industrial activities and construction activities. Generally, industrial sites obtain coverage for stormater through a general permit, such as the multisector general permit or construction general To do so, the facility operator submits a notice of intent, and permit. agrees to meet general permit conditions. For example, conditions for the construction general permit include applicable erosion and sediment control, site stabilization, and pollution prevention requirements. oil and gas exploration, production, processing, or treatment operations or transmission facilities composed entirely of flows which are from conveyances or systems of conveyances (including but not limited to pipes, conduits, ditches, and channels) used for collecting and conveying precipitation runoff and which are not contaminated by contact with, or do not come into contact with, any overburden, raw material, intermediate products, finished product, byproduct, or waste products located on the site of such operations. Interpreting the provision exempting oil and gas facilities, EPA issued regulations requiring permits for contaminated stormwater from oil and gas facilities. To determine whether a discharge of stormwater from an oil or gas facility is contaminated, EPA regulations establish that if a facility has had a stormwater discharge that resulted in a discharge exceeding an EPA reportable quantity requiring notification under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) or section 311 of CWA, or which contributes to violation of a water quality standard, the permit requirement is triggered for that facility. Regarding stormwater at oil and gas well sites, officials said it is unlikely there is a permit requirement because it is rare that stormwater would come into contact with raw materials. Nonetheless, if a facility anticipates having a stormwater discharge that includes a reportable quantity of oil or may result in a violation of water quality standards, then the facility would be obligated to apply for a NPDES permit. In applying for the permit, however, the facility has to agree not to discharge pollutants in a reportable quantity and not to discharge pollutants so as to cause a water quality violation. Given this, it is unclear whether facilities would apply for such a permit after they have had a release of a reportable quantity or contributing to a water quality violation. Furthermore, according to officials, EPA relies upon operators self-identifying based on reportable quantities or water quality violations. Despite these factors, EPA reviewed available data for the five states in which EPA administers the NPDES program, including Texas, and identified some stormwater general permit notifications for facilities that could be well sites. EPA regulations require permits for stormwater discharges from construction activities including clearing, grading, and excavating that result in land disturbance. Beginning in 1990, EPA began regulating stormwater discharges from construction sites disturbing more than 5 acres of land under its Phase I rule. Under Phase II rules issued in 1999, EPA regulated stormwater discharges from construction sites disturbing between 1 and 5 acres of land, with initial permit applications due in 2003. With respect to oil and gas well sites, under the statutory provisions and EPA’s Phase 1 stormwater regulations, discharges of stormwater from construction activity would have required a permit only for sites disturbing more than 5 acres and where the stormwater is contaminated by contact with, or comes into contact with, any overburden, raw material, intermediate products, finished product, byproduct, or waste products located on the site of such operations. According to EPA officials, the agency believed few oil and gas sites met these conditions. They further explained that when EPA conducted the Phase II rulemaking for the smaller 1 to 5 acre sites, the agency assumed incorrectly that oil and gas well sites would be smaller than 1 acre and thus did not include oil and gas well sites in their economic analysis of the rule. After the rule’s issuance as it became aware that such sites would fall under the rule, and in light of industry objections over the lack of economic analysis, EPA delayed Phase II implementation at oil and gas well sites until 2006. Before implementation of Phase II regulations at oil and gas well sites began, the Energy Policy Act of 2005 was enacted. The Energy Policy Act of 2005 amended CWA to specifically define the activities included in the oil and gas stormwater exemption. Where the law already exempted from NPDES permit requirements discharges of stormwater from “oil and gas exploration, production, processing, or treatment operations or transmission facilities,” the Energy Policy Act of 2005 added a definition of this term as “all field activities or operations associated with exploration, production, processing, or treatment operations, or transmission facilities, including activities necessary to prepare a site for drilling and for the movement and placement of drilling equipment, whether or not such field activities or operations may be considered to be construction activities.” In response to these amendments, in 2006, EPA revised a key provision of the regulations concerning oil and gas stormwater discharges. The revision provided that discharges of sediment from oil or gas facility construction activities and contributing to a water quality standard violation would not trigger a permit requirement. This revision was vacated and remanded by the Ninth Circuit in 2008. EPA has not subsequently revised the regulations applicable to stormwater discharges from oil and gas facilities; the pre-2006 regulations remain in effect as to this industry. EPA officials said the agency intends to revise its regulations to address the court’s vacatur in an upcoming stormwater rulemaking, with the proposal expected in 2013. According to EPA officials, during construction, oil and gas well sites would have no permit requirement because of the statutory exemption. For violations of the law, or applicable regulations or permits, EPA has authority to issue administrative orders requiring compliance, impose administrative penalties, as well as to bring suit and, in conjunction with the Department of Justice, to impose civil penalties. Among other things, EPA can take such actions if a well operator violates the CWA prohibition on unauthorized discharges of pollutants to surface waters. EPA also has information-gathering and access authority relative to point source owners and operators, which could include certain oil and gas well site operations. For example, EPA has authority to inspect facilities where an effluent source is located. As an example of enforcing the prohibition of unauthorized discharges, in 2011, EPA Region 6 assessed an administrative civil penalty against a company managing an oil production facility in Oklahoma for discharging brine and produced water to a nearby stream. entered a consent agreement with an oil production company in Colorado for unauthorized discharges of produced water from a multiwell site due to a failed gas eliminator valve in a produced water transportation pipeline. The produced water travelled overland for 333 feet, then entered a stream tributary to an interstate river. The company agreed to pay a civil penalty and to conduct a macroinvertebrate study for the affected watershed. American Petroleum & Environmental Consultants, Inc., Cease and Desist Administrative Order, EPA Docket No. CWA-06-2012-1760 (Dec. 12, 2011). take such other action as may be necessary, upon receipt of evidence that a pollution source or combination of sources is presenting an imminent and substantial endangerment to the health of persons or to the livelihood of persons. Unlike the analogous provisions of several other major environmental laws, however, CWA section 504 does not expressly mention administrative orders. EPA’s Oil Pollution Prevention regulations, promulgated and amended pursuant to CWA and the Oil Pollution Act, impose spill prevention and response planning requirements on oil and gas well sites that meet thresholds. Specifically, the Spill Prevention, Control, and Countermeasure (SPCC) Rule applies to sites with underground and/or aboveground storage tanks above certain thresholds and where oil could be discharged into or upon navigable waters.production facilities, among others, generally are subject to the rule if they (1) have an aggregate oil storage capacity of greater than 1,320 gallons in aboveground oil storage containers or a total oil storage capacity greater than 42,000 gallons in completely buried storage tanks and (2) could reasonably be expected, due to their location, to discharge harmful Onshore oil and gas quantities of oil into or upon U.S. navigable waters or adjoining shorelines. The SPCC rule, as amended, requires each owner or operator of a regulated facility to prepare and implement a plan that describes how the facility is designed, operated, and maintained to prevent oil discharges into or upon U.S. navigable waters and adjoining shorelines. The plan must also include measures to control, contain, clean up, and mitigate the effects of these discharges. EPA regulations specify requirements for SPCC plans for onshore oil drilling and oil production facilities. Onshore drilling facilities must meet the general requirements for such plans, as well as meet specific discharge prevention and containment procedures: (1) position or locate mobile drilling or workover equipment so as to prevent a discharge; (2) provide catchment basins or diversion structures to intercept and contain discharges of fuel, crude oil, or oily drilling fluids; and (3) install a blowout prevention (BOP) assembly and well control system before drilling below any casing string or during workover operations. Oil production facilities are exempt from the SPCC security provisions. 73 Fed. Reg. 74,236 (Dec. 5, 2008). reviewed the spill data for the oil production sector contained in its study of the exploration and production sector…While these data do not characterize the extent of environmental damage caused by oil discharges from small oil production facilities, they demonstrate that the volume of oil discharged from onshore oil production facilities increasing, and the number of oil discharges on a yearly basis has remained the same, despite a decline in crude oil production. In addition, oil production facilities are often unattended, and typically located in remote areas, which potentially increases the risk of environmental damage from an oil discharge of oil. Various development activities at oil and gas well sites involve storage of oil that may trigger the SPCC regulations to impose these requirements. During initial exploration and drilling, the capacity of the fuel tank of the drill rig is the primary way the SPCC rule could be triggered, and EPA officials said that almost all drill rigs exceed the threshold capacity. During well completion and workover, where hydraulic fracturing is conducted, EPA officials said the capacity of the fuel tank in the turbines and pumps being used for fracturing typically exceed the threshold. As to wells in the production phase, they said there would generally be no SPCC requirement at dry gas wells, because they would not be storing condensate on-site. For wet gas and oil production, the size of the condensate or oil tanks on the site would be the key to whether SPCC is triggered. Id. at 58,802. See also Considerations for the Regulation of Onshore Oil Exploration and Production Facilities Under the Spill Prevention, Control, and Countermeasure Regulation (40 C.F.R. part 112)) (available at www.regulations.gov document EPA–HQ– OPA–2007–0584–0015). EPA has developed guidance related to SPCC applicability and compliance for oil production, drilling, and workovers. According to officials, EPA is currently developing a “frequently asked questions” document about the SPCC program and hydraulic fracturing. This document is being developed in response to an influx of questions about how the SPCC rule applies to gas well sites, particularly from companies active in the Marcellus shale. According to EPA officials, while the SPCC is focused on oil, wet gas wells involve condensates, some of which have traditionally been deemed liquid hydrocarbons and included in the program. In particular, questions have arisen over the lightest condensates (C2 and C4 hydrocarbons), which are usually in gaseous form at standard temperatures and pressures and hence are not included in the SPCC program, whereas storage of heavier condensates, such as C6+ hydrocarbons, has been included (as liquids) in the SPCC program. EPA directly administers the SPCC program. require facilities to report to the agency that they are subject to the SPCC rule and, as of 2008, EPA did not know the universe of SPCC-regulated facilities, but the agency was considering developing some data. EPA officials stated that they have significant data but not complete data because of the lack of a registration or submittal requirement. To ensure that facility owners and operators are meeting SPCC requirements, EPA personnel inspect selected regulated facilities to determine their compliance with the regulations. For some facilities, the SPCC compliance date was in November 2011. EPA is working to develop a national database of sites inspected under the SPCC rule. Officials said that the SPCC program’s database includes 120 inspections at oil and gas production facilities for fiscal year 2011, of which 105 had some form of noncompliance, which varies in significance from paperwork inconsistencies to more serious violations (though EPA officials were unable to specifically quantify the number of more serious violations). The Clean Water Act does not provide EPA with the authority to authorize states to implement the program in its place. According to EPA headquarters officials, EPA generally selects facilities for inspection based on spill reports EPA receives through the National Response Center. The Oil Pollution Prevention Regulation also requires an owner or operator of nontransportation onshore facilities that could, because of location, reasonably be expected to cause substantial harm to the environment by discharging oil into or on the navigable waters or shorelines, to submit to the appropriate EPA Regional office a facility response plan. The regulation specifies criteria to be used in determining whether a facility could reasonably be expected to cause substantial harm and hence triggers such requirement, and it also provides that the EPA Administrator may at any time, on determination considering additional factors, require a facility to submit a facility response plan. A facility owner or operator also may maintain certification that it could not, because of location, reasonably be expected to cause substantial harm by discharging oil into or onto navigable waters or shorelines. Relevant to oil well sites, the initial criteria for requiring a facility response plan is that the facility has total oil storage of 1 million gallons or more. Where such facilities meet at least one of four other criteria—such as lacking secondary containment, or located at distances that could injure fish and wildlife—then a facility response plan is required. The plan is to provide, in essence, an emergency response action plan for the worst-case discharge and other relevant information. According to EPA officials, onshore oil well sites would typically not go over the threshold criteria triggering the requirement for a facility response plan. Officials said there may be a small number of sites where very large or centralized operations with a number of wells connected to central piping and/or storage might trigger a facility response plan. CWA established the policy of the United States that there should be no discharges of oil or hazardous substances into or upon U.S. navigable waters or onto adjoining shorelines, among other resources, and generally prohibited such discharges. Relevant provisions require reporting of certain discharges of oil or a hazardous substance to these waters. EPA has issued regulations designating those hazardous substances that present an imminent and substantial danger to the public health or welfare when discharged to U.S. navigable waters or onto adjoining shorelines in any quantity. EPA also has determined, in regulations, the quantities of oil and other hazardous substances of which the discharge to U.S. navigable waters or onto adjoining shorelines may be harmful to the public health or welfare or the environment. CWA in conjunction with these regulations require facilities to report to the National Response Center certain unpermitted releases of oil or hazardous substances to surface waters. The National Response Center subsequently sends reports to EPA Regions and headquarters. With respect to oil, discharges of oil must be reported if they “(c)ause a film or sheen upon or discoloration of the surface of the water or adjoining shorelines or cause a sludge or emulsion to be deposited beneath the surface of the water or upon adjoining shorelines,” or if they violate applicable water quality standards. With respect to hazardous substances, EPA has determined threshold quantities—those which may be harmful to the public health or welfare or the environment— known as reportable quantities. EPA, as well as other relevant federal agencies, has various response authorities to ensure effective and immediate removal of a discharge, and mitigation or prevention of a substantial threat of a discharge, of oil or a hazardous substance to U.S. navigable waters or onto adjoining shorelines. The National Oil and Hazardous Substances Pollution Contingency Plan, issued by EPA by regulation, provides a system to respond to discharges and to contain, disperse, and remove oil and hazardous substances, among other things.EPA Region 5, in conjunction with the state of Ohio, the Region has responded to several incidents in which orphan wells were found to be leaking or discharging crude oil into waterways. For example, according to Under CWA section 311, as required to carry out its purposes including spill prevention and response, EPA also has authority to require the owner or operator of a facility subject to the Oil Pollution Prevention Regulation, among other provisions, to establish and maintain such records; make such reports; install, use, and maintain such monitoring equipment and methods; provide such other information deemed necessary; and for entry and inspection of such facilities. For violations of the law, or applicable regulations or permits, EPA has authority to issue administrative orders requiring compliance, impose administrative penalties, as well as to bring suit, in conjunction with the Department of Justice, to impose civil penalties.EPA the authority to access records and inspect facilities, and the ability Section 311 also gives to require provision of information, with respect to persons and facilities subject to section 311, including SPCC program requirements. For example, in Region 8, EPA participated in an effort with the U.S. Fish and Wildlife Service (FWS), states, and tribes, after FWS expressed concerns about migratory birds landing on open pits that contained oil and water, which killed or harmed the birds. surveys to observe pits. Where apparent problems were identified, relevant federal or state agencies were notified and were to give oil and gas operators an opportunity to correct problems. Ground inspections were then conducted where deemed warranted and, if problematic conditions were found, further follow-up action was taken by EPA or the relevant state or other federal agency. As a result of this effort, 99 sites with violations of SPCC requirements were identified. EPA’s report stated that “on-compliance with SPCC requirements was more pervasive than anticipated. Although the SPCC program has been the focus of outreach and compliance assistance nationally for more than 25 years, there remains a strong need to communicate its requirements, inspect regulated facilities, and conduct appropriate technical assistance or enforcement to ensure improved compliance.” The report states that, for most SPCC violations, EPA issued a notice of violation and that many notice of violation recipients came into compliance without escalation to formal enforcement, but that some enforcement actions were taken. Region 8 reported identifying 22 sites with documented SPCC violations as a result of subsequent efforts in 2004-2005. Information on the nature or resolution of these violations was not readily available. EPA Region 8, Oil and Gas Environmental Assessment Effort 1996 – 2002, v (2003). CWA section 311 provides EPA authority to address certain releases of oil or hazardous substances to U.S. navigable waters and adjoining shorelines. Specifically, on determination that “there may be an imminent and substantial threat to the public health or welfare of the United States, including fish, shellfish, and wildlife, public and private property, shorelines, beaches, habitat, and other living and nonliving natural resources under the jurisdiction or control of the United States, because of an actual or threatened discharge of oil or a hazardous substance from a vessel or facility” in violation of the prohibition against discharges of oil or hazardous substances to U.S. navigable waters and adjoining shorelines, EPA may bring suit, or may, after notice to the affected state, take any other action under this section, including issuing administrative orders, that may be necessary to protect the public health and welfare. Production components may include, but are not limited to, wells and related casing head, tubing head and ‘‘Christmas tree’’ piping, as well as pumps, compressors, heater treaters, separators, storage vessels, pneumatic devices and dehydrators. Production operations also include the well drilling, completion and workover processes and includes all the portable non-self-propelled apparatus associated with those operations. In addition, EPA officials have noted that tanks, ponds, and pits are sources of emissions that may be present at well sites. Others have also identified condensate storage tanks and flaring as significant emission sources often associated with gas wells. The key criteria pollutant of concern for oil and gas production is VOCs, as an ozone precursor, and the primary HAP released by the oil and gas production industry are BTEX (benzene, toluene, ethylbenzene, and xylenes) and n-hexane. To address stationary sources under CAA, EPA is required to promulgate industry-specific emissions standards such as National Emission Standards for Hazardous Air Pollutants (NESHAP) and New Source Performance Standards (NSPS) for source categories that EPA has listed under the Act. CAA also provides for review of new and modified major sources of emissions under the Prevention of Significant Deterioration and Nonattainment New Source Review programs, typically implemented by states. CAA and EPA regulations require operating permits, known as Title V permits, for certain stationary sources, and establish minimum requirements for state operating permitting programs.programs is described below as it may apply to oil and gas well sites. Mobile sources associated with oil and gas production may include trucks bringing fuel, water, and supplies to the well site; construction vehicles; and truck-mounted pumps and engines. That is, oil and gas wells may be served by a variety of road and nonroad vehicles and engines. EPA regulates emissions from an array of mobile sources by imposing emission limits on such vehicles and engines; these generally applicable regulations are not specific to the oil and gas industry and are not discussed here. Finally, the Act includes provisions addressing accidental releases of dangerous pollutants to the air. Oil and gas wells are unlikely to trigger the planning aspects of these provisions, according to EPA; however, the well sites are subject to the general duty clause, a self-implementing provision of CAA under which operators are responsible for identifying hazards associated with accidental releases and designing and maintaining a safe facility, taking such steps as are necessary to prevent releases. Table 9 summarizes the applicability of key Clean Air Act programs to emission points at oil and gas well sites. These provisions will be discussed in greater detail in this appendix. The 1990 CAA amendments significantly expanded the hazardous air pollutants program; they identified 189 specific HAPs to be regulated, required EPA to list categories of sources to be regulated, and established implementation timelines. The list of HAPs includes several potentially found in oil and gas well emissions. In addition to these listed HAPs, EPA and others have identified hydrogen sulfide, which is found in oil and gas well emissions but is not a listed HAP, as hazardous and toxic to humans. EPA has the authority to add to the HAPs list pollutants which may present, through inhalation or other routes of exposure, a threat of adverse human health effects or adverse environmental effects, but not including releases subject to EPA’s regulation under section 112(r)—namely, the accidental release and risk management regulations. The prevention of accidental releases regulation includes accidental releases of hydrogen sulfide. In a 1993 report to Congress, EPA found that the limited data available did not evidence a significant threat to human health or the environment from “routine” emissions of hydrogen sulfide from oil and gas wells. CAA provides a process to petition EPA to modify the HAPs list. On March 30, 2009, the Sierra Club and 21 other environmental and public health organizations and individuals petitioned EPA to list hydrogen The petitioners asserted that sulfide as a HAP under section 112(b). low-level hydrogen sulfide emissions not addressed by the accidental release provisions in section 112(r) are harmful to human health.officials told us they are considering the petition but have no specific timeline for acting upon it. EPA is required to promulgate and periodically revise NESHAPs for source categories the agency has identified. NESHAPs may include standards for major sources and for area sources, which are any sources not major. Major source NESHAPs are based on the maximum achievable control technology (MACT), while EPA may use a different standard of generally available control technology for area sources. S under CAA section 112(b), especially since H2S’s routine exposure effects – on a daily basis – are not addressed whatsoever under the accidental release provisions in section 112(r) of CAA.” Id. at 1. combination of HAPs. Normally, the determination of a facility’s potential to emit HAPs is based on the total of all activities at a facility, known as aggregation. Under a unique provision of CAA, however, “emissions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units,” to determine whether such units or stations are major sources of air pollution, or for other purposes under section 112 (e.g., the HAPs section). Finally, facilities that do not contain a regulated unit (e.g., glycol dehydrator or covered storage vessel) are not subject to any requirement in the rule, even if they emit HAPs. Regarding the aggregation provisions, EPA officials explained that the agency has historically interpreted the statutory language to prohibit aggregation of HAP emissions from wells and associated equipment, meaning that each well and piece of associated equipment must be evaluated separately for purposes of determining major source status. EPA has defined “associated equipment” in the regulations. Officials said that EPA has not evaluated the significance of the aggregation prohibition and EPA’s interpretation of it, such as its effect on the numbers of facilities that are or are not regulated as major sources and hence subject to MACT controls. Officials also said that it is likely that the effect of the aggregation provisions on well sites is smaller than its impact on downstream oil and gas production facilities where equipment tends to be larger and would be more likely to trigger MACT requirements if aggregated. 64 Fed. Reg. at 32,619. EPA originally promulgated the NESHAPs for Oil and Natural Gas Production source subcategory in two parts: the standard for major sources was issued in 1999, and the NESHAP for area sources in 2007. In April 2012, EPA promulgated amendments to the NESHAPs for major sources. The NESHAPs for major sources apply to emission points of HAPs located at oil and natural gas production facilities (including wells, gathering stations, and processing plants) that are major sources. Under this rule, in determining whether a well site’s potential to emit HAPs equals or exceeds 10 tons per year (the major source threshold), only emissions from equipment other than wells or “associated equipment,” may be aggregated; associated equipment is a defined term, and excludes glycol dehydrators and storage vessels. In other words, emissions from wells are not aggregated; only emissions from glycol dehydrators and storage vessels at a site may be aggregated. Further, the rule exempts facilities exclusively handling and processing “black oil” and small oil and gas production facilities, including well sites, prior to the point of custody transfer.which these exemptions have the effect of cancelling MACT requirements that would otherwise apply to oil and gas wells from unconventional deposits. EPA documents do not indicate the extent to EPA headquarters officials did not know if any oil or gas wells were NESHAP major sources prior to the April 2012 amendments, and EPA officials in each of the four Regions we contacted were unaware of any examples of oil and natural gas wells being regulated as major sources. EPA officials noted that glycol dehydrators are more likely where there are high pressure gas wells, such as in the Jonah-Pinedale area of Wyoming. EPA officials said that a multiple pad well site in this area would very likely be major for HAPs, except that any federally enforceable standards are first applied to determine the potential emissions, and Wyoming’s presumptive best available control technology standards would likely limit the emissions such that the potential to emit would be reduced to area source levels. Analyses developed for the recent amendments also do not identify if any well sites triggered the major source NESHAPs prior to the amendments, but available data suggest few well sites do so. Large glycol dehydrators are those with an actual annual average natural gas flowrate equal to or greater than 85 thousand standard cubic meters per day and actual annual average benzene emissions equal to or greater than 0.90 Mg/yr. 77 Fed. Reg. 49,490 , 49,568-69 (Aug. 16, 2012) (revising 40 C.F.R. §§ 63.761, 63.760(b)). cover vented through a closed vent system to a control device that recovers or destroys HAPs emissions with an efficiency of 95 percent or greater, or for combustion devices, reduces HAPs emissions to a specified outlet concentration. However, these standards only apply at sites that are deemed major sources, and as outlined above, it appears likely that few well sites reach the key threshold emissions level. The April 2012 amendments added one more emission source to the These sources NESHAP major source rule: small glycol dehydrators. must meet a unit-specific limit for emissions of BTEX that is calculated using a formula in the rule based on the unit’s natural gas throughput and gas composition. Existing dehydrators have 3 years to comply, while new dehydrators must comply upon start-up. Id. at 49,503; see also EPA, Summary of Requirements for Processes and Equipment at Natural Gas Well Sites. these sources in order to analyze and establish MACT emission standards for this subcategory of storage vessels.” In addition, the April 2012 amendments changed a key definition in the NESHAPs for determining major source status. change (i.e., revision to the definition of “associated equipment”) is that emissions from all storage vessels and all glycol dehydrators now will be counted toward determining whether a facility is a major source under the NESHAP for Oil and Natural Gas Production. EPA documents do not indicate the extent to which the change in definition will result in additional oil and gas wells being subject to the MACT requirement. CAA prohibits EPA from listing oil and gas production wells (with its associated equipment) as a specific “area source” category, unless the area source category is for oil and gas production wells located in any metropolitan statistical area or consolidated metropolitan statistical area with a population in excess of 1 million, and the EPA Administrator determines that emissions of HAPs from such wells present more than a negligible risk of adverse effects to public health. Id. at 49,501, 49,569 (revising 40 C.F.R. § 63.761). EPA defines these control areas with reference to parameters used by the U.S. Census Bureau to identify densely settled areas. See 72 Fed. Reg. 26, 28 (2007). limit for benzene. For area sources outside of these control areas, an operational standard is required instead of an add-on control. Area sources are required to notify EPA that they are subject to the rule; additional information, including periodic reports, are required for area sources within a control area. The area source notifications are sent to a specific EPA e-mail box. EPA does not track whether the facilities providing notification are well sites or other components of the oil and natural gas production sector, so it is difficult to determine to what extent oil and gas well sites are subject to the area source NESHAP. Regarding EPA’s authority to establish an area source category for oil and gas wells in metropolitan statistical areas, if certain conditions are met, officials said that EPA has not considered doing so. They said that they have not analyzed well emissions in relation to location in or outside a metropolitan statistical area, and that if the agency were to consider developing an area source within metropolitan statistical areas, they would need to conduct a new data collection effort. In addition, EPA has promulgated other NESHAPs, the applicability of which to oil and gas well sites depends upon the particular equipment— and factors such as capacity or emission rate—used at a well site. Although some published materials suggest several NESHAPs may apply, based on discussions with EPA, the primary NESHAP that officials believe could apply at oil and gas well sites is the Boilers and Process Heaters NESHAP for major sources. The major source rule for boilers and process heaters has an unusual feature in that, to determine applicability of the rule, it references whether or not an oil and gas production facility falls within the major source definition under the NESHAPs for Oil and Gas Production Facilities (subpart HH). If an oil and gas well were a major source under the Oil and Gas NESHAP, then any boilers or process heaters with heat input of 10 million British thermal units (BTU) per hour are subject to emission limitations requirements, and any smaller heaters are subject to work standards, under the Boiler NESHAP. These requirements differ from those in the NESHAP for Oil and Gas Production Facilities by, among other things, imposing limits for other pollutants, such as particulate matter, hydrogen chloride, mercury, carbon monoxide, and dioxins/furans, depending on the type of unit. Officials stated that some glycol dehydrators at well sites could be over the trigger heat input and would be subject to the Boiler NESHAP requirements if the oil and gas site were a major source subject to the rule. As noted above, it is not known how many, if any, well sites are major sources. Where a gas well has a compressor, the compressor engine may be EPA did not have available subject to standards for stationary engines. information on the extent to which these engines are present at well sites and, if so, whether they fall under these rules, which are based on equipment and are not specific to the oil and gas industry. EPA promulgates NSPS, which are generally applicable to (1) new or reconstructed facilities and (2) facilities that have undergone modification—that is, any physical change in, or change in the method of operation of, a facility which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. These rules are implemented by EPA or by states through delegation.the NSPS primarily regulates VOCs (as an ozone precursor). For the oil and gas production industry, In 1985, EPA promulgated NSPS for the oil and gas industry focused on natural gas processing plants, but did not include any standards for emissions from preprocessing production activities. promulgated such standards for some production emissions, notably completion and recompletion of certain hydraulically fractured gas wells.In addition, some other generally applicable standards for certain equipment may apply at oil and gas well sites. In April 2012, EPA promulgated amendments to the NSPS for the Oil and Gas sector, including new standards applicable to the production source category. The new standards were issued pursuant to a 2010 consent decree that settled a challenge brought by environmental groups over EPA’s failure to conduct required reviews of the existing standards. Following publication of the new rules in August 2012, an industry group petitioned EPA to reconsider certain aspects of the new rules. 40 C.F.R. pt. 60, subparts KKK, LLL. completions and recompletions of natural gas wells, with variable implementation dates as described in table 10. These practices are designed to capture emissions from flowback from hydraulically fractured wells, and reduce VOC emissions. EPA’s regulatory impact analysis estimated that the rules will apply to about 9,700 new wells per year, and to about 1,200 existing wells being recompleted per year. Of these, EPA’s analysis estimates that nearly 9,400 wells will be required to use “green completion” techniques to capture and treat flowback emissions so that the captured natural gas can be sold or otherwise used, while the remainder will use completion combustion. Additionally, to reduce VOC emissions, the April 2012 rule establishes standards including those for, as relevant to gas well sites, gas-driven pneumatic controller devices and storage vessels, subject to thresholds. According to EPA documents, over 13,600 pneumatic controllers will be affected, but it is not clear the extent to which these are located at well sites. Similarly, EPA documents estimate that 304 storage vessels annually will trip the threshold of 6 tons per year of VOC and thus be subject to the rule, and EPA officials expect most of these storage vessels will be located at wells. When asked about the potential increased burden of the amended NSPS rules, officials said that it was not clear whether the rule would result in more or fewer CAA-related permits. For example, the applicability of NSPS may trigger a state requirement to get a construction permit or other type of permit. These permits may be triggered by, among other things, a facility’s “potential to emit” that is calculated assuming all federally enforceable controls are in place. Officials said that the NSPS, which are federally enforceable requirements, will reduce actual emissions and thus could reduce the number of facilities that trigger the requirement for these state permits. In the new rule, EPA generally exempted covered facilities from the obligation to obtain a Title V operating permit. EPA has issued equipment-focused NSPS for certain equipment that may be used at oil and gas well sites. These include NSPS for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels). These standards apply to such tanks with a capacity greater than or equal to 75 cubic meters that is used to store volatile organic liquids and that were built, reconstructed, or modified after July 23, 1984. Tanks attached to trucks and other mobile vehicles are excluded.while there are tanks at well sites, they are often smaller than the threshold in this rule. Specifically, while the standards apply to tanks greater than 75 cubic meters (about 475 barrels, according to EPA), an individual tank typically found at oil and gas sites is often between 250 – 400 barrels, hence avoiding coverage under this rule. Other NSPS that have been identified as potentially relevant include those for gas turbines and steam generators. EPA officials said, however, that typical activity at well sites is not enough to trigger thresholds for coverage under this rule, either. CAA New Source Review (NSR) provisions require a source to obtain a permit and undertake other obligations to control its emissions of air pollution prior to construction of a new source or modification of an existing stationary source. However, NSR only applies if the construction project results in actual emissions or the potential to emit regulated air contaminants at or above certain threshold levels established in the NSR regulations. For a new source, NSR is triggered only if the emissions would cause the source to qualify as major. For an existing major source making a modification, NSR is triggered only if the modification will result in a significant increase in emissions and a significant net emissions increase of that pollutant. Relevant to NSR, the emission profile for oil and gas wells would include hydrogen sulfide and VOCs, among others. In most areas, states implement the NSR permitting programs. The major NSR program is actually composed of the following two separate programs: Nonattainment NSR applies to emission of specific pollutants from sources located in areas designated as nonattainment for those pollutants because they do not meet the pollutant-specific national ambient air quality standards. Prevention of Significant Deterioration (PSD) applies to emissions of all other regulated pollutants from sources located in attainment areas where such standards are met or in areas unclassifiable for such standards. For PSD, the major source threshold is generally 250 tons per year of any regulated air pollutant. Determining whether a facility is a major source, together with identifying which emissions should be included in doing so is guided by the process as for Title V permits, discussed below. While a 1993 EPA report appeared to suggest that most oil and gas extraction wells would not likely be subject to PSD regulations based on the applicability criteria, the specific determination of which emission units, including wells, must be included in determining whether a source is major (source aggregation) involves a case-by-case, fact-specific analysis. For nonattainment NSR, the major source threshold ranges from 100 tons per year down to 10 tons per year depending on the severity of the air quality problem where the source is located and the specific pollutant at issue. To be a major source under nonattainment NSR, the source must emit or have a potential to emit above the major source level set for the specific regulated air pollutant (or its precursor) for which the area is designated nonattainment. With respect to nonattainment NSR, EPA officials stated that some large wells in nonattainment zones could be major sources standing alone because of low emission thresholds in certain areas; as noted above, such thresholds could be as low as 10 tons per year in the most severe nonattainment areas, versus 250 tons per year in attainment areas. Relevant to oil and gas production, CAA generally requires Title V permits for the operation of determined based on the facility’s actual emissions or “potential to emit;” any source, including a nonmajor source, subject to a NSPS; any source, including an area source, subject to a NESHAP, among any source required to obtain a PSD or NSR permit. Thus, whether a Title V permit is required depends on whether the source (1) is subject to one of these other requirements, unless EPA has exempted the particular area sources or nonmajor sources from the Title V permit requirement, or (2) meets the emissions thresholds for a major source. Title V permits for a major source must include all applicable requirements for all relevant emission units in the major source. Title V permits for nonmajor sources must include all applicable requirements applicable to emissions units that caused the source to be subject to the Title V permitting requirements. Title V permits may need to add monitoring, reporting, or other requirements but generally do not add new emissions control requirements (rather they consolidate requirements from throughout CAA programs and contain conditions to assure compliance with such requirements). According to EPA officials, the permits help operators and the public to understand what the requirements are for compliance with CAA and help assure compliance with such requirements. Title V permits are generally issued by states and, in some instances, EPA Regional offices. As of August 2012, EPA officials were unaware of any Title V permits issued solely on the basis of oil and gas well site emissions alone. EPA officials stated that some oil and gas well sites have adopted federally enforceable emissions limits such that the sites do not need a Title V permit, which they would otherwise have triggered. In addition, EPA identified a March 2012 case in which a state environmental agency alleged, among other things, that an oil and gas production site had VOC emissions of over 600 tpy, which would require a Title V permit. The operator disputed the violations but agreed to submit an application for a Title V permit. Applicable to both NSR and related determinations for Title V, EPA regulations specify three factors that must be met in source determinations—whether the emissions points are under common control, belong to the same major industrial grouping, and are located on contiguous or adjacent properties. Thus, in contrast to the NESHAPs, in determining whether significance thresholds for emissions are met for purposes of NSR or Title V, EPA and states must aggregate VOC emissions from oil and gas well sites that are both (1) contiguous or adjacent and (2) under common control. To determine whether a source meets the emissions thresholds for a Title V or NSR major source designation, EPA applies these regulatory criteria to evaluate whether to aggregate oil and gas production wells with other emission sources. Specifically, permitting authorities (EPA or authorized states or local authorities) have in particular matters, on a case-by-case basis, aggregated emissions from facilities to determine major sources, for purposes of Title V operating permits or NSR. Determining when emissions must be aggregated is a fact-based inquiry that is made by permitting authorities on a case-by-case basis. While authorized states are typically responsible for making source determinations, EPA headquarters has stated that Regional offices should continue to review and comment on source determinations to assure consistency with regulations and historical practice. In addition, EPA Regions may be responsible for source determinations in areas where they are responsible for permitting. Aggregation of emissions from the oil and gas industry generally, including production facilities, has received recent attention. For example, in 2007, EPA provided guidance on how to evaluate aggregation in source determinations for the oil and gas industry. EPA later withdrew this industry-specific guidance and emphasized that source determinations in this industry were governed by the existing regulations, the existing interpretations of them, and need for case-specific application of the regulations in each permitting action. See Summit Petroleum Corp. v. EPA, Nos. 09-4348, 10-4572, slip op. (6th Cir. August 7, 2012). oil and gas activities with the compressor station in determining the source. A citizen group appealed this decision to the Environmental Appeals Board. Both citizen group challenges were ultimately dismissed after the parties engaged in a dispute resolution process. EPA entered settlements with the citizen group and agreed to undertake a pilot program for the purpose of studying, improving, and streamlining source determinations in the oil and gas industry in new or renewal Title V permits for which EPA Region 8 is the initial Title V permitting authority. In sum, several recent disputes over aggregation of oil and gas facilities involve whether or not well emissions should be aggregated; however, whether or not well emissions are aggregated for Title V or PSD purposes generally would not affect other federal requirements for emission controls at well sites. In 2009, EPA promulgated the Greenhouse Gas Reporting Rule, providing a framework for the greenhouse gas reporting program and establishing requirements for some source categories. According to EPA, the goals of the program are to obtain data that are of sufficient quality that they can be used to support a range of future climate change policies and regulations; to balance the rule coverage to maximize the amount of emissions reported while minimizing reporting from small emitters; and to create reporting requirements that are consistent with existing programs by using existing estimation and reporting methodologies to reduce reporting burden, where feasible. EPA subsequently issued and amended a rule to implement the program for the category of Petroleum and Natural Gas Systems, including oil and gas wells. According to EPA, oil and gas well sites may contain sources of greenhouse gas emissions including: (1) combustion sources, such as engines used on-site and which typically burn natural gas or diesel fuel, and (2) process sources, such as equipment leaks and vented emissions. The process sources include pneumatic devices, dehydrators, and compressors. EPA has identified the onshore production subcategory as the largest segment for equipment leaks and vented and flared emissions in the petroleum and natural gas system source category. The rule requires petroleum and natural gas facilities—including oil and gas well sites—that emit 25,000 metric tons or more of carbon dioxide equivalent per year to report certain data to EPA. Specifically, oil and gas production facilities are to report annual emissions of carbon dioxide, methane, and nitrous oxide from equipment leaks and venting, gas flaring, and stationary and portable combustion. Reporting is to begin in September 2012, for calendar year 2011. 76 Fed. Reg. 73,886, 73,889, 73,899 (Nov. 29, 2011) (amending 40 C.F.R. § 98.3). For purposes of this rule, onshore petroleum and natural gas production is defined to include all equipment on a single well pad or associated with a single well pad (including but not limited to compressors, generators, dehydrators, storage vessels, and portable non-self-propelled equipment which includes well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary non-transportation- related equipment, and leased, rented or contracted equipment or storage facilities), used in the production, extraction, recovery, lifting, stabilization, separation, or treating of petroleum and/or natural gas (including condensate). Moreover, the rule defines an onshore oil and gas production facility as including all oil or gas equipment on or associated with a well pad and carbon dioxide enhanced oil recovery operations that are under common ownership or control and that are located in a single hydrocarbon basin; thus, for example, where multiple wells are owned or operated by the same person or entity in a single basin, the owner or operator is to report well data collectively for each hydrocarbon basin. EPA estimated that this facility definition for onshore petroleum and natural gas production will result in 85 percent GHG emissions coverage of this industry segment, and EPA documents estimate that emissions from approximately 467,000 onshore wells are covered under the rule. Section 112(r) of CAA establishes the chemical accidental release prevention program applicable to specifically listed “regulated substances,” as well as other extremely hazardous substances. This provision, among other things, required EPA to publish regulations and guidance for chemical accident prevention at facilities using substances that pose the greatest risk of harm from accidental releases; the resulting regulatory program is known as the Risk Management Program. In conjunction with the program, EPA was required to promulgate a list of at least 100 substances which, in the case of an accidental release, are known to cause or may reasonably be anticipated to cause death, injury, or serious adverse effects to human health or the environment, and to periodically review the list. Among others, hydrogen sulfide is included on the list of regulated substances. Section 112(r) also established the Chemical Safety Board; and the general duty for owners and operators of facilities to take steps to prevent accidental releases of the listed and other extremely hazardous substances, among other things. Whether and the extent to which a facility is subject to the Risk Management Program requirements depends on the regulated substances present and their quantities, the processes, and the presence of receptors. Generally, the regulation requires, for covered processes, a three-part program including (1) a hazard assessment; (2) a prevention program that includes safety procedures and maintenance, monitoring, and employee training measures; and (3) an emergency response program. 63 Fed. Reg. 640 (Jan. 6, 1998); 65 Fed. Reg. 13,243, 13,244 (Mar. 13, 2000). naturally occurring hydrocarbon mixtures, which include any combination of the following: condensate, crude oil, field gas, and produced water (defined as water extracted from the earth from an oil or natural gas production well, or that is separated from oil or natural gas after extraction), regulated substances in gasoline, when in distribution or related storage for use as fuel for internal combustion engines, and a flammable substance when the substance is used as a fuel. Regarding the exemption of naturally occurring hydrocarbon mixtures prior to entry into a processing plant or refinery, EPA explained at the time that the agency believed they do not warrant regulation, noting that the general duty clause would apply when site-specific factors make an In addition, EPA stated that, unlisted chemical extremely hazardous. for naturally occurring hydrocarbons and for regulated substances in gasoline, a key consideration was EPA’s original intent to exempt flammable mixtures that do not meet a preexisting standard—the National Fire Protection Association flammability hazard rating of 4. EPA has also explained that this rating reflects the potential to result in vapor cloud explosions and boiling liquid expanding vapor explosions, which it found pose the greatest potential hazard from flammable substances to the public and environment. 40 C.F.R § 68.126 (2012). Program rule. In this context, the Chemical Safety Information, Site Security and Fuels Regulatory Relief Act prohibited EPA from listing flammable substances used as fuel, solely because of their explosive potential. EPA then revised the regulation, adding the exemption to comply with the act. The regulated chemicals present at oil and gas well sites include components of natural gas (such as butane, propane, methane, and ethane), but these are exempt from the threshold determination of a facility subject to the Risk Management Program when present in “naturally occurring hydrocarbon mixtures.” If an oil or gas well site nonetheless uses or stores some of the regulated chemicals not encompassed by the exemptions, it could trigger the risk management requirements. The owners and operators of stationary sources producing, processing, handling or storing such substances have a general duty …to identify hazards which may result from such releases using appropriate hazard assessment techniques, to design and maintain a safe facility taking such steps as are necessary to prevent releases, and to minimize the consequences of accidental releases which do occur. Known as the “general duty clause,” the provision is analogous to a negligence standard, according to EPA officials. In other words, if there is a known risk and a way to mitigate it, then the operator should conduct risk mitigation. As explained in an EPA report, “responsibilities include the conduct of appropriate hazard assessments and the design, operations, and maintenance of a safe facility,” as well as release mitigation and community protection. EPA officials noted that industry standards (such as from the American National Standards Institute or the American Petroleum Institute) and fire codes are used in determining the duty of care. EPA has published Chemical Safety Alerts to advise the regulated community of its general duty clause obligations. The general duty clause applies to sources handling or storing substances listed by EPA in the Risk Management Program regulations or any other extremely hazardous substance, without a threshold. EPA headquarters officials said that, conceivably, the general duty clause would apply to every single well but stated that it would be in EPA Regions’ discretion where and when to use the general duty clause to conduct inspections. In some Regions, EPA has conducted inspections of gas well sites to enforce the general duty clause, including identifying noncompliance with certain safety standards. EPA Regional officials said that they use infrared video cameras to conduct inspections to identify leaks of methane from storage tanks or other equipment at well sites. For example, EPA Region 6 officials said they have conducted 45 inspections at well sites since July 2010 and issued 10 administrative orders related to violations of CAA general duty clause. EPA officials said that all well sites are required to comply with the general duty clause but that EPA prioritizes and selects sites for inspections based on risk. Section 112(r) also provides EPA with the authority to issue orders as may be necessary to protect the public health when the EPA Administrator determines that there may be an imminent and substantial endangerment to human health or welfare or the environment because of an actual or threatened accidental release of a regulated substance. The Chemical Safety Board, established by section 112(r), is charged with investigating and publicly reporting on accidental releases resulting in a fatality, serious injury, or substantial property damages. The board is authorized, among other things, to make recommendations to EPA. In September 2011, the Chemical Safety Board released a report investigating three incidents involving fatality and injuries at oil and gas storage tanks located at well sites and surveyed an additional 23 such incidents that occurred between 1983 and 2010. The report found that these accidents occurred when the victims—all young adults—gathered at rural unmanned oil and gas storage sites lacking fencing and warning signs. This report concluded such sites pose a public safety risk. The report also reviewed federal, state, and local regulations, inherently safer designs of tanks, and industry standards. Noting that exploration and production storage tanks are exempt from the security requirements of CWA and from the risk management requirements of CAA, the Chemical Safety Board recommended that EPA encourage owners and operators to reduce these risks. Specifically, the Chemical Safety Board recommended EPA “publish a safety alert directed to owners and operators of exploration and production facilities with flammable storage tanks, advising them of their general duty clause responsibilities for accident prevention under CAA.” The letter requests that EPA provide within 180 days a response stating how EPA will address the recommendation. On June 27, 2012, EPA responded to the Chemical Safety Board and stated that EPA agrees to develop and publish a safety alert and anticipates the agency will be able to publish a final safety alert by June 2013. The Chemical Safety Board also made related recommendations to several states and industry associations. Even where a state implements key CAA provisions, EPA retains oversight and enforcement authority. For example, EPA may initiate an enforcement action via an administrative order or a civil action for a violation of any requirement or prohibition of an applicable SIP, permit, or certain other requirement or prohibition after notification to the state and the party. CAA also gives EPA authorities regarding access to records and the ability to require provision of information, as to any person who owns or operates any emission source, among others. Where EPA receives evidence that a source or a combination of sources present an imminent and substantial endangerment to public health or welfare, or the environment, EPA may bring suit or, where prompt action is needed, issue orders to stop the emission of air pollutant or take other necessary action.and attempt to confirm the accuracy of information before taking such actions. In 1976, Congress passed the Resource Conservation and Recovery Act (RCRA), generally establishing EPA authority to regulate the generation, transportation, treatment, storage, and disposal of hazardous waste, and also including some provisions respecting solid waste. As to solid waste, RCRA provided a more limited federal role and included incentives for states to implement programs to manage nonhazardous solid waste disposal, a prohibition on open dumping of wastes, and a requirement for EPA to promulgate technical criteria for classifying solid waste disposal facilities, among other things. a solid waste, or combination of solid wastes, which because of its quantity, concentration, or physical, chemical, or infectious characteristics may (A) cause, or significantly contribute to an increase in mortality or an increase in serious irreversible, or incapacitating reversible, illness; or (B) pose a substantial present or potential hazard to human health or the environment when improperly treated, stored, transported, or disposed of, or otherwise managed. RCRA Subtitle D, 42 U.S.C. ch. 82, subch. IV (§§ 6941-6949a) (2012). ignitability, corrosivity, or reactivity. The generation, transport, and disposal of wastes meeting the RCRA regulatory hazardous definition are generally subject to RCRA Subtitle C requirements, such as reporting, using a manifest, and disposing of the waste in approved ways, such as through hazardous waste landfill. Notwithstanding the provisions for identifying hazardous wastes, the Solid Waste Disposal Act Amendments of 1980 created a separate process for certain oil and gas exploration and production wastes. Under the statute, these wastes would not be subject to regulation as hazardous waste under RCRA Subtitle C unless specific actions were taken. The amendments required EPA to conduct and publish “a detailed and comprehensive study…on the adverse effects, if any, of drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil or natural gas or geothermal energy on human health and the environment.” The study report was to “include appropriate findings and recommendations for Federal and non-Federal actions concerning such effects.” he Administrator shall, after public hearings and opportunity for comment, determine either to promulgate regulations under this subchapter for drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil or natural gas or geothermal energy or that such regulations are unwarranted. The Administrator shall transmit his decision, along with any regulations, if necessary, to both Houses of Congress. Such regulations shall take effect only when authorized by Act of Congress. In considering the first factor, EPA found that a wide variety of management practices are utilized for these wastes, and that many alternatives to these current practices are not feasible or applicable at individual sites…As to the second factor, EPA found that existing State and Federal regulations are generally adequate to control the management of oil and gas wastes. Certain regulatory gaps do exist, however, and enforcement of existing regulations in some States is inadequate. EPA’s review of the third factor found that imposition of Subtitle C regulations for all oil and gas wastes could subject billions of barrels of waste to regulation under Subtitle C as hazardous wastes and would cause a severe economic impact on the industry and on oil and gas production in the U.S…and could cause severe short-term strains on the capacity of Subtitle C Treatment, Storage, and Disposal Facilities..and a significant increase in the Subtitle C permitting burden for State and Federal hazardous waste programs. Id. at 25,446. EPA stated that regulation of these wastes as hazardous waste under Subtitle C posed significant problems, including the lack of flexibility in the statute to take into account the varying geological, climatological, geographic, and other differences characteristic of oil and gas production sites, and to consider cost in applying the requirements—such that EPA would be unable to craft a program to avoid severe economic impacts and to fill only the gaps in existing programs. In lieu of regulating these wastes as hazardous waste under Subtitle C, EPA announced “a three-pronged approach toward filling the gaps in existing State and Federal regulatory programs,” comprised of (1) improving existing programs under RCRA, the Safe Drinking Water Act, and the Clean Water Act; (2) working with states to improve their programs; and (3) working with Congress on any additional legislation EPA further stated that it planned to revise its that might be needed. existing standards under Subtitle D of RCRA, “tailoring these standards to address the special problems posed by oil, gas, and geothermal wastes and filling the regulatory gaps,” and “in developing these tailored Subtitle D standards for crude oil and natural gas wastes, EPA will focus on gaps in existing State and Federal regulations and develop appropriate standards that are protective of human health and the environment. Gaps in existing programs include adequate controls specific to associated wastes and certain management practices and facilities for large-volume wastes, including roadspreading, landspreading, and impoundments.” EPA, Exploration & Production Waste and RCRA, presented at ASTSWMO Annual Meeting (Oct. 26, 2011). Environmental Regulations (STRONGER) program. EPA also worked with industry representatives to develop best management practices for exploration and production wastes, but these efforts did not culminate in any document or guidance. On September 8, 2010, the Natural Resources Defense Council submitted a petition requesting regulation of waste associated with the exploration, development, or production of oil, natural gas, and geothermal energy. the determination not to regulate these wastes because, among other things, the underlying assumptions—concerning the availability of alternative disposal practices, the adequacy of state regulations, and economic harm to the oil and gas industry—are no longer valid. The petition requests that EPA promulgate regulations applying to wastes from the exploration, development and production of oil and natural gas under Subtitle C of RCRA. Letter, NRDC to EPA, Petition for Rulemaking Pursuant to Section 6974(a) of the Resource Conservation and Recovery Act Concerning the Regulation of Wastes Associated with the Exploration, Development, or Production of Crude Oil or Natural Gas or Geothermal Energy (Sept. 8, 2010); see also RCRA § 7004(a), 42 U.S.C. § 6974(a) (2012). issue, the agency intends to issue a proposed response to the petition. The proposed response will be printed in the Federal Register, and EPA will establish an electronic docket and provide an opportunity for public comment. Although EPA has not yet sought public comment on the petition, the agency has received several unsolicited comment letters, including from two industry associations, the STRONGER program, and two states. If EPA revises the regulatory determination for some or all exploration and production wastes, the agency would conduct a full regulatory process to propose the regulations. Under the key RCRA provision, the regulations would not become effective until authorized by congressional action. Should the exemption be lifted, not all exploration and production wastes would necessarily be hazardous. Rather, whether particular exploration and production wastes would be hazardous and subject to regulation would depend on whether those particular wastes meet the regulatory definition of hazardous (i.e., are a listed waste or exhibit a characteristic of hazardous waste). While well sites wastes originating within the well or generated by field operations such as water separation, demulsifying, degassing, and storage are exempt, RCRA Subtitle C regulations generally apply to other wastes that may be generated at oil and gas wells, such as discarded unused products, solvents used to clean surface machinery, and others, if they are actually hazardous. In 2002, EPA published a guide titled “Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations” that identifies, among other things, a list of nonexempt wastes. The guide identified nonexempt wastes including the following wastes that may be generated by activities at oil and gas well sites: unused fracturing fluids or acids; oil and gas service company wastes such as empty drums, drum rinsate, sandblast media, painting wastes, spent solvents, spilled chemicals, and waste acids; vacuum truck and drum rinsate from trucks and drums transporting or containing nonexempt waste; used equipment lubricating oils; waste compressor oil, filters, and blowdown; used hydraulic fluids; caustic or acid cleaners; radioactive tracer wastes; and drums, insulation, and miscellaneous solids. According to EPA’s guidance document, this list represents some types of wastes that, if hazardous, are not exempt from Subtitle C regulation; however, these wastes may or may not be hazardous in a particular situation. These wastes are hazardous if they are a listed hazardous waste or exhibit a hazardous characteristic, such as ignitability or toxicity. If hazardous, then the facility is subject to waste management requirements that vary depending upon the amount of hazardous waste generated per calendar month. RCRA regulations establish several categories for facilities generating hazardous waste, with differing reporting obligations. Among these, the lowest level category is conditionally exempt small quantity generators, composed of facilities generating no more than 100 kilograms (220 pounds) per month of hazardous waste. These facilities are subject to limits on the amount of hazardous waste they accumulate, as well as general requirements to determine which wastes are hazardous and to ensure that any hazardous wastes sent for off-site disposal are sent to state-approved facilities, RCRA-permitted or interim status, or for certain wastes, universal waste facilities, facilities beneficially using, recycling, or reclaiming the waste. Generally, conditionally exempt small quantity generators would not be required to have an EPA ID number. Small quantity generators are those facilities generating more than 100 kilograms (220 pounds) but less than 1,000 kilograms (2,220 pounds) per month of hazardous waste. These facilities are subject to limits on the amount of hazardous waste they accumulate, as well as storage requirements, and general requirements to determine which wastes are hazardous and to ensure that any hazardous wastes sent for off-site disposal are sent to RCRA-permitted or interim status facilities. In addition, the small quantity generators are required to have an EPA ID number and use manifests, by which hazardous waste may be tracked. Id. at § 262.12(a) (a generator, other than a conditionally exempt small quantity generator, is essentially required to obtain an identification number before storing the waste or offering it to a transporter.). and inspection purposes. Generally, EPA (or the authorized state’s) involvement at generator-only sites includes receiving notifications and issuing identification numbers, receiving biennial reports, conducting compliance assurance activities such as inspections, and investigating alleged problems. EPA has not undertaken a specific assessment of the extent to which oil and gas well sites are generating small amounts of regulated hazardous wastes and consequently are regulated as small quantity generators or conditionally exempt small quantity generators. EPA officials were unaware of the extent to which oil and gas well sites generate nonexempt hazardous waste (e.g., hazardous wastes other than exempt exploration and production wastes) in quantities significant enough to require an EPA ID number. EPA Region 8 officials were unaware of any instances in which a well site requested an EPA ID number. A challenge in understanding the extent to which oil and gas well sites are regulated stems in part from the use of North American Industry Classification System (NAICS) codes. While there is a code at the six-digit level that generally corresponds with oil and gas production, it appears that, for some facilities with this code, the facility entry includes associated downstream facilities such as a compressor station or gas processing plant, making it impossible to use RCRAInfo – a publicly available EPA database that contains information on RCRA generators -- alone to identify well sites triggering the particular requirement of interest. For example, this database shows that some facilities with the oil and gas production NAICS code are listed as conditionally exempt small quantity generators. GAO’s review of a small sample of these listings suggests some may include downstream facilities, while others appear to be well sites. Oil and gas exploration and production wastes may be RCRA statutory solid wastes even if they are exempt from hazardous waste requirements or are nonhazardous wastes. As compared with hazardous waste, RCRA provided EPA a different and largely nonregulatory role for solid waste. EPA’s role in solid waste management is focused on assisting states in developing solid waste management programs. For example, EPA developed guidelines for certain aspects of solid waste management. A key part of EPA’s limited regulatory role for solid waste was to establish criteria defining which solid waste disposal facilities and practices are “sanitary landfills” and those which constitute “open dumps,” where RCRA prohibited open dumping of solid waste. Consistent with the scheme established by RCRA Subtitle D, states have primary responsibility for managing disposal of solid waste, including that resulting from oil and gas exploration and production. State solid waste programs regulate treatment (which may include incineration) and land disposal of these wastes, among other things. In addition, states may have specific programs to address oil and gas production wastes, and some states put such wastes in a special category of solid waste, such as industrial wastes, with more stringent requirements than the federal minimum requirements. (See report and app. IX for discussion of selected aspects of state waste management.) EPA has certain enforcement authorities to address hazardous wastes. RCRA sections 3007, 3008, and 3013 collectively provide EPA with authorities to monitor compliance, conduct investigations, and enforce Subtitle C (the hazardous waste subtitle) and its implementing regulations. Each of these key authorities depends, among other things, on the existence or presence of a hazardous waste in a given situation. EPA’s authority under sections 3007 and 3013 extends beyond waste that is regulated as hazardous under Subtitle C (e.g., wastes meeting the regulatory definition of hazardous waste), and includes waste that meets the statutory definition of hazardous waste in RCRA section 1004(5). For example, section 3008(a) authorizes EPA to issue administrative compliance orders “whenever on the basis of any information” the EPA Administrator determines that any person has violated or is in violation of any requirement of Subtitle C. These orders may require the person ,to come into compliance immediately or by a specific time frame and/or pay a civil penalty for any past or current violation and may include suspension or revocation of a facility’s RCRA permit. Alternatively, EPA, through the Department of Justice, may file a civil action in federal court for violations of RCRA and its implementing regulations and permits. EPA must give notice to the state, if it has an EPA-authorized hazardous waste program, prior to issuing an order or filing a civil judicial action. Section 3007(a) gives EPA authority to inspect and copy records and to obtain samples from any person who generates, stores, treats, transports, disposes of, or otherwise handles or has handled hazardous wastes, and to enter sites where hazardous wastes are or have been generated, stored, treated, disposed of, or transported from. Section 3007 also establishes mandatory compliance inspections. EPA has interpreted its section 3007 authority, discussed above, to include the authority to access records and sites related to solid waste “that the Agency reasonably believes may pose a hazard when improperly managed.” EPA officials did not provide any examples of EPA using its section 3007 authority at oil or gas well sites. Section 3013 authorizes EPA to issue an order requiring monitoring, testing, analysis, and reporting if the EPA Administrator determines, upon receipt of any information, that the presence or release of any hazardous waste at a facility or site at which hazardous waste is, or has been, stored, treated, or disposed of may present a substantial hazard to human health or the environment. Furthermore, in certain circumstances, EPA may use its authority under section 3013 to conduct its own investigation into the nature and extent of a potential hazard. EPA officials did not provide any examples of EPA using these hazardous waste enforcement provisions for incidents arising at oil or gas well sites. EPA has fewer enforcement responsibilities and authorities for nonhazardous waste facilities under RCRA Subtitle D, than it does for hazardous waste activities regulated under RCRA Subtitle C. In particular, state solid waste programs are based in state law and generally are not subject to enforcement or overfiling by EPA. RCRA’s prohibition on open dumping of solid and hazardous waste is enforceable by citizen suit. EPA has imminent and substantial endangerment authority to address both hazardous and solid wastes. Section 7003 authorizes EPA to issue administrative orders and to file suit in federal district court. In addition, “upon receipt of evidence that the past or present handling, storage, treatment, transportation or disposal of any solid waste or hazardous waste may present an imminent and substantial endangerment to health or the environment,” EPA has authority to restrain any person who has contributed or who is contributing to such handling, storage, treatment, transportation or disposal, from such activity, to order them to take such other action as may be necessary, or both. Such orders can be issued to a person who contributed in the past or is currently contributing to the imminent and substantial endangerment to health or the environment. Section 7003 orders are enforceable; if a nonfederal recipient fails to comply, EPA can enforce the order, including fines, by requesting that Department of Justice file suit in federal court. EPA’s imminent and substantial endangerment authority is not limited to Subtitle C regulated hazardous wastes but also includes statutory solid wastes and hazardous wastes. EPA has interpreted the authority broadly, to allow a range of actions to be taken, including addressing the threat of endangerment. Nonetheless, EPA officials noted that a section 7003 action is distinct from, for example, the agency’s Subtitle C enforcement authorities because the objective of such an action is to abate the imminent and substantial endangerment, rather than to enforce specific RCRA requirements. Whether RCRA section 7003 authority is applicable to a given situation requires a fact-based determination that the facts establish the statutory elements, including the existence of conditions that may present an imminent and substantial endangerment. EPA has issued section 7003 orders at several facilities handling wastes from oil and gas well sites. For example, as previously discussed, EPA Region 8 participated in an effort with the FWS, states, and tribes, after the FWS expressed concerns about migratory birds landing on open pits that contained oil and water, which killed or harmed the birds. The effort involved aerial surveys to observe pits. Where apparent problems were identified, relevant federal or state agencies were notified and were to give oil and gas operators an opportunity to correct problems. Ground inspections were then conducted where deemed warranted and, if problematic conditions were found, further follow up action was taken by EPA or the relevant state or other federal agency. As a result of this effort, EPA issued nine orders pursuant to RCRA section 7003 authority. According to the report, the orders required operators “to remove oil from pits, install effective exclusionary devices, and/or clean up sites.” EPA Region 8 has issued section 7003 orders to several commercial oilfield waste disposal facility operators in Wyoming, finding each site endangered the environment including having caused bird mortalities due to inadequate pit management. As another example, in 2005, EPA Region 6 entered into an agreement with an exploration company and property owners at a site in Oklahoma where the contents of a well drilling waste pit had been relocated onto residential property; the agreement required the waste to be removed, among other things. In 1980, Congress passed the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), often referred to as “Superfund,” to address the cleanup of releases of hazardous substances, pollutants, and contaminants nationwide and, in so doing, protect human health and the environment from their effects. The enactment of CERCLA gave the federal government the authority to respond to actual and threatened releases of hazardous substances, pollutants, and contaminants that may endanger public health or welfare or the environment, as well as requiring reporting of hazardous substances releases above threshold quantities. CERCLA also established a liability scheme, whereby potentially responsible parties such as owners and operators may be liable for cleanup and other costs stemming from the release (or threatened release) of hazardous substances into the environment from a facility. CERCLA is primarily a remedial statute; it is preventive in that it authorizes responses to threatened releases of hazardous substances, pollutants, and contaminants, and to the extent that the liability scheme provides incentives for owners and operators to take care to avoid releases to the environment. Under a provision known as the petroleum exclusion, CERCLA’s provisions do not apply to releases to the environment that are purely petroleum, including crude oil and natural gas, and fractions of crude oil including the hazardous substances, such as benzene, that are indigenous in those petroleum substances. EPA can respond to releases of hazardous substances, however, even if there are colocated petroleum releases. any injection of fluids or other materials authorized under applicable State law (i) for the purpose of stimulating or treating wells for the production of crude oil, natural gas, or water, (ii) for the purpose of secondary, tertiary, or other enhanced recovery of crude oil or natural gas, or (iii) which are brought to the surface in conjunction with the production of crude oil or natural gas and which are reinjected. However, EPA has explained, “he National Response Center must be notified in any situation involving the use of injection fluids or materials that are not authorized specifically by State law for purposes of the development of crude oil or natural gas supplies and resulting in a release of a hazardous substance” at or above the threshold reporting quantity. Where there has been a release of a hazardous substance, CERCLA section 103 requires a person in charge of a facility to report such releases above reportable quantities as soon as he/she has knowledge of such release to the National Response Center. EPA regulations establish CERCLA hazardous substances and their reportable quantities. While releases of pure petroleum (e.g., petroleum in which hazardous substances have not increased such as by addition or processing) are excluded, releases of CERCLA hazardous substances that are commingled with petroleum are subject to the reporting requirement. Oil and gas well operators would be required to report any releases to the environment of other hazardous substances, for example, if a stored hazardous substance was accidentally spilled onto the ground, or if hazardous substances above the reportable quantity were injected but not authorized by state law. The National Response Center—managed by the U.S. Coast Guard— receives release reports and forwards them to EPA Regions. When receiving a report, according to EPA Regional staff will screen the report for such factors as what was spilled and in what quantity and whether the spill threatens surface waters, to determine if EPA needs to respond and, if appropriate, will obtain additional information on the event, and/or send an on-scene coordinator to the site. EPA officials also noted they use the release reports to refer sites to program enforcement offices, such as the Clean Water Act’s SPCC program, for follow-up. Although release reports are publicly available, the available search terms do not readily differentiate oil and gas well sites from other types of oil and gas facilities. EPA officials noted that there had been approximately 200 reports of oil spills from oil facilities in the last 5 years. EPA Region 5 officials stated that oil spills are more often related to pipelines, tank sites, or trucking accidents, with few occurring at well sites. EPA established the Superfund program to carry out its responsibilities and authorities under CERCLA. Under the Superfund program, EPA implements its authorities to compel parties responsible for contaminating sites—via releases of hazardous substances—to clean them up, as well as to enter into agreements with such parties for them to conduct the cleanup. In addition, EPA can itself conduct response actions, which may include investigations and cleanup activities, and then seek reimbursement from the responsible parties. The Superfund cleanup process involves a series of steps during which specific activities—such as investigations and cleanups—take place or decisions are made. The CERCLA program has two basic types of cleanup: (1) cleanups under the removal process, which generally address short-term threats, and (2) cleanups under the remedial action process, which are generally longer-term cleanup actions. In determining whether to use removal or remedial authority to take a response action, EPA considers the time-sensitivity, complexity, comprehensiveness, and cost of the response action. Several EPA Superfund authorities are particularly relevant to oil and gas well operations, including the following: Investigations, monitoring, coordination. Under section 104(b), EPA generally may conduct investigation activities with appropriated program funds whenever a hazardous substance is released or there is a substantial threat of such a release, or there is reason to believe a release has occurred or is about to occur. These activities may include monitoring, surveys, testing, and other information gathering, as well as planning, legal, fiscal, economic, engineering, architectural, and other studies or investigations, as deemed appropriate. Information gathering and access. Under section 104(e), EPA has authority to obtain information as well as authorities to enter property Specifically, EPA may and to conduct inspections and take samples. require a person to furnish information about the identification, nature, and quantity of materials that have been or are generated, treated, stored, or disposed of at a facility or transported thereto, or the nature or extent of a release or threatened release of a hazardous substance or pollutant or contaminant, or the ability of a person to pay for or to perform a cleanup, including related documents and records, among other things. Where there is a reasonable basis to believe there may be a release or threat of release of a hazardous substance or pollutant or contaminant, EPA is authorized to enter a facility or property where such release is or may be threatened, among other things, and may inspect and obtain samples. EPA may obtain access by agreement, warrant, or administrative order. If consent is not granted, EPA may issue administrative orders or, through the Department of Justice, file civil actions, to compel compliance with requests made under these provisions. Removals. Under section 104(a), EPA generally has authority to act whenever there has been a release or substantial threat of release into the environment of any hazardous substance. EPA generally may conduct removal actions, among other things. Removal actions are broadly defined and include actions to monitor, assess, and evaluate the release; the disposal of removed material; and other actions to prevent, minimize, or mitigate damage to the public health or welfare or to the environment such as provision of alternative drinking water supplies. Imminent and substantial endangerment authority related to releases of a pollutant or contaminant. Under section 104(a), EPA has authority to act whenever a release or substantial threat of release into the environment of any pollutant or contaminant may present an imminent and substantial danger to the public health or welfare. This provides EPA with authority over releases of substances that are not CERCLA however, as hazardous but that may harm public health or welfare; noted above, releases that are purely petroleum are excluded. Under this authority, EPA may conduct removals, provide for remedial action, or take any other response measure consistent with the National Contingency Plan. Authorities to pursue potentially responsible parties. In addition, under section 106(a), EPA, through the Department of Justice, can pursue injunctive relief in court, where an actual or threatened release of a hazardous substance from a facility may pose an imminent and substantial endangerment to the public health or welfare or the environment. EPA also can issue an administrative order requiring a potentially responsible party to take response actions as may be necessary to protect public health and welfare and the environment. CERCLA also provides authorities for EPA to pursue cleanup and related costs from potentially responsible parties, and to enter settlements, as well as providing for liability of potentially responsible parties for damages to federal, state, and tribal natural resources. EPA has utilized its CERCLA authorities at several locations where it has been alleged that hazardous substance releases from oil and gas well sites have contaminated land or groundwater. In an example at a conventional oil well, in the 1990s, EPA, as represented by the Department of Justice, reached an agreement in which an oil exploration and production company pled guilty to a criminal felony count related to CERCLA violations when operators disposed of waste oil and hazardous substances by injecting them down the annuli (the space between the well casing and the surrounding rock) of the oil wells, over a 2-year period. According to the Department of Justice, the company agreed to spend $22 million to resolve the criminal case and related civil claims, which included claims brought under RCRA, SDWA, and EPCRA, as well as CERCLA. See Richard M. Fetzer, On-Scene Coordinator EPA, Action Memorandum to Dennis Carney, Associate Division Director, Hazardous Site Cleanup Division, EPA, re: Request for Funding for a Removal Action at the Dimock Residential Groundwater Site, Jan. 19, 2012. contamination investigations at Pavillion, Wyoming.referenced CERCLA section 104(e) authority in requesting information from operators of wells proximate to the Pavillion site. EPA has used CERCLA section 104(e) in conjunction with other authorities in several “multimedia” information requests, where EPA seeks information under multiple statutes and for multiple media—air, land, water—that may be affected. In 2011, for example, EPA used CERCLA and other authorities to request information concerning a blowout at a Marcellus shale natural gas well in Bradford, Pennsylvania. In this instance, a well blowout during hydraulic fracturing resulted in the release of flowback fluids to a tributary of the Susquehanna River, as well as combustible gases to the atmosphere. The Emergency Planning and Community Right-to-Know Act of 1986 (EPCRA) provides a mechanism to help communities plan for emergencies involving extremely hazardous substances, and to provide individuals and communities with access to information regarding the storage and releases of certain toxic chemicals, extremely hazardous substances, and hazardous chemicals in their communities. EPCRA imposes a set of generally applicable requirements to report information on the uses, inventories, and releases into the environment of hazardous and toxic chemicals above threshold quantities. Regarding releases, EPCRA section 304 requires owners or operators of facilities where a chemical is produced, used, or stored to notify state and local emergency planning authorities of certain releases. The releases for which EPCRA requires reporting partially overlap with those for which the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) requires reporting. Where there is overlap, EPCRA’s procedures ensure state and local authorities receive this information, and CERCLA’s procedures ensure federal authorities receive notification. Regarding reporting of chemical information and inventories, EPCRA sections 311 and 312 requirements apply only to those facilities storing or using (1) more than 500 pounds or the threshold planning quantity, whichever is lower, of extremely hazardous substances, or (2) more than 10,000 pounds of other hazardous chemicals. These facilities are required to provide chemical information (e.g., Material Safety Data Sheet or other detailed list) and submit an annual inventory report to state and local emergency planning authorities and to the local fire department with jurisdiction over the facilities. Well sites are subject to EPCRA sections 304, 311, and 312, among others, and may be subject to reporting requirements to the extent that the chemicals used, stored, or produced at well sites meet the respective reporting thresholds. Under EPCRA section 304, any facility, such as a well site, that produces, uses, or stores any hazardous chemical and has a release above the reportable quantity of a CERCLA hazardous substance or an extremely hazardous substance, must provide notification to state and local emergency planning authorities, as well as the National Response Center. Under EPCRA sections 311 and 312, any facility, such as a well site, at which an extremely hazardous chemical or any other hazardous chemical is present at the relevant threshold quantity, must meet inventory reporting requirements. For extremely hazardous chemicals, the threshold is 500 pounds or its threshold planning quantity, whichever is less. For all other hazardous chemicals, the reporting threshold is 10,000 pounds. For example, if the aggregate amount of hydrofluoric acid, an extremely hazardous chemical with a threshold planning quantity of 100 pounds, at a well site exceeds that threshold then the facility must report under sections 311 and 312. As another example, if a well stores or uses more than 10,000 pounds of drip gas or natural gas condensate at any one time, then the facility must report under sections 311 and 312. The extent to which these requirements are triggered at oil and gas well sites depends on the presence and quantities of listed chemicals at such sites, among other things. We did not locate any publicly available data on the quantity of chemicals stored at actual or typical well sites, but FracFocus provides self-reported data on the types of chemicals used in hydraulic fracturing, meaning that these chemicals are present and used at well sites. According to data in FracFocus, some hydraulic fracturing operations may use various hazardous chemicals, including some that are also CERCLA hazardous substances, such as hydrochloric acid, formaldehyde, formic acid, acetaldehyde, ethylene glycol, methanol, acetic acid, sodium hydroxide, potassium hydroxide, acrylamide, and naphthalene; of these, one is also considered “extremely hazardous.” According to EPA, its Regional offices have several cases in development where the facility triggered the reporting requirements under 311 and 312 during all phases of operation, including drilling, hydraulic fracturing, and production. EPA stated that, based on the Regions’ experience, section 311 and 312 requirements could be triggered at every well site. EPA provided an example of section 312 information for a well site, which according to EPA officials, indicates that some hazardous chemicals may be present at the particular well site in quantities that would trigger section 311 and 312 requirements. The information provided by EPA suggests that the types of chemicals with maximum on-site quantities of 10,000 to 99,999 pounds are the following: cement and associated additives; drilling mud and associated additives; lubricants, drilling mud additives; and alkalinity and pH control material. The information provided by EPA also suggests that the types of chemicals with maximum on-site quantities of 100,000 to 999,999 pounds are the following: weight materials, and fuels. EPCRA also requires some facilities in listed industries to report to EPA their releases of listed toxic chemicals to the environment; at present, these requirements do not apply to oil and gas well operations. Section 313 of EPCRA generally requires certain facilities that manufacture, process, or otherwise use any of more than 600 listed individual chemicals and chemical categories, to report annually to EPA and their respective state, for those chemicals used above threshold quantities. Facilities need to report the amounts that they released to the environment and whether they were released into the air, water, or soil. Id. at (i). Full-time employee is defined as 2,000 hours per year of full-time equivalent employment. A facility would calculate the number of full-time employees by totaling the hours worked during the calendar year by all employees, including contract employees, and dividing that total by 2,000 hours. 40 C.F.R.§ 372.3 (2012). American Industry Classification System (NAICS) codes, and subsequently to update as needed to reflect changes to the NAICS codes. EPCRA section 313(b)(1)(B) provides EPA with authority to add or delete industrial codes. 1988. In the initial regulations, EPA discussed its approach to evaluating additional industrial codes under its discretionary authority but did not add any at that time. Oil and gas extraction industries were not included on the statutory list of Standard Industrial Classification codes and hence were not subject to the rule. EPCRA § 313(b)(1)(B), 42 U.S.C. § 11023(b)(1)(B) (2012). EPA can also add individual facilities. EPCRA § 313(b)(2), 42 U.S.C. § 11023(b)(2) (2012). One industry group, oil and gas extraction classified in [Standard Industrial Classification] code 13, is believed to conduct significant management activities that involve EPCRA section 313 chemicals. EPA is deferring action to add this industry group at this time because of questions regarding how particular facilities should be identified. This industry group is unique in that it may have related activities located over significantly large geographic areas. While together these activities may involve the management of significant quantities of EPCRA section 313 chemicals in addition to requiring significant employee involvement, taken at the smallest unit (individual well), neither the employee nor the chemical thresholds are likely to be met. EPA will be addressing these issues in the future. The preamble of the final rule stated in part, “ number of commenters support EPA’s decision not to include oil and gas exploration and production in its proposal, and urge EPA not to propose adding this industry in the future. EPA considered the inclusion of this industry group prior to its proposal, and indicated in the proposal that one consideration for not including it was concern over how a ‘facility’ would be defined for purposes of reporting in EPCRA section 313 …This issue, in addition to other questions, led EPA to not include this industry group. EPA will continue its dialogue with the oil and gas exploration and production industry and other interested parties, and may consider action on this industry group in the future.” In fall 2011, EPA conducted a discussion forum on regulations.gov. The background information provided in the forum stated that EPA was considering a rule to add or expand coverage to the following industry sectors: Iron Ore Mining, Phosphate Mining, Solid Waste Combustors and Incinerators, Large Dry Cleaners, Petroleum Bulk Storage, and Steam Generation from Coal and/or Oil. EPA officials told us that, for the current possible rulemaking, the initial screening process for sectors to consider adding to the TRI included review of those sectors, such as oil and gas production, that were considered but ultimately not added in the 1997 rule. In addition, EPA officials said the initial screening process also included sectors covered by analogous registries of other countries. According to EPA, the oil and gas sector falls into both categories and was considered in the initial screening. As of July 2012, EPA officials stated that EPA does not anticipate adding oil and gas exploration and production sites as part of the possible rule currently under consideration to add industry sectors to the scope of TRI. EPA officials explained that the agency has not changed its assessment of the oil and gas sector as it pertains to TRI reporting since the 1996 proposed rule and stated that adding oil and gas well sites would likely provide a substantially incomplete picture of the chemical uses and releases at these sites, and would therefore be of limited utility in providing information to communities. EPA officials noted that Canada’s National Pollutant Release Inventory (NPRI) has data on Canadian oil and gas wells for some TRI chemicals. Specifically, EPA identified several TRI chemicals that were also reported to the Canadian NPRI by oil and gas facilities as being released, disposed of, and/or transferred in large quantities in reporting year 2010 in Canada including ammonia, arsenic, cadmium, copper, hexavalent chromium, hydrogen sulfide, lead, manganese, mercury, phenanthrene, phosphorus, sulfuric acid aerosols, and zinc compounds. If oil and gas exploration and production were added to the industries required to report to the TRI, such facilities meeting relevant thresholds would have to report releases of hydrogen sulfide, which is among the chemicals of particular concern some have cited. In October 2011, EPA lifted its administrative stay of the EPCRA section 313 reporting requirements for hydrogen sulfide, which had been in effect since 1994, shortly after the chemical was added to the list of toxic chemicals. EPA conducted a technical evaluation of hydrogen sulfide and found no basis for continuing the administrative stay of the reporting requirements. The first reports under EPCRA section 313 for hydrogen sulfide will be due on July 1, 2013, for reporting year 2012. EPCRA provides EPA with various authorities to enforce the act’s requirements. For example, for violations of EPCRA section 311 or section 312 requirements, such as provision of annual inventory reports to state and local authorities, EPA may assess administrative penalties, or initiate court actions to assess civil penalties. In cases of violations of section 304 release reporting requirements, EPA may assess administrative penalties, among other things. To help protect human health and the environment, the Toxic Substances Control Act (TSCA) authorizes EPA to regulate the manufacture, processing, use, distribution in commerce, and disposal of chemical substances and mixtures. EPA has authorities by which it may assess and manage chemical risks, including (1) to collect information about chemical substances and mixtures; (2) upon making certain findings, to require companies to conduct testing on chemical substances and mixtures; and (3) upon making certain findings, to take action to protect adequately against unreasonable risks such as by either prohibiting or limiting manufacture, processing, or distribution in commerce of chemical substances or by placing restrictions on chemical uses. EPA maintains the TSCA Chemical Substance Inventory that currently lists over 84,000 chemicals that are or have been manufactured or processed in the United States; about 62,000 were already in commerce when EPA began reviewing chemicals in 1979. Generally, TSCA’s reporting requirements fall on the manufacturers (including importers), processors, and distributors of chemicals, rather than users of the chemicals. According to EPA, some of the chemicals on the TSCA Chemical Substance Inventory are used in oil and gas exploration and production. For example, in response to our request, EPA identified several chemicals on the FracFocus list of “chemicals used most often” which are on the TSCA inventory.representative of different product function categories, are as follows: These examples, which EPA chose as Hydrochloric acid – Acid; Peroxydisulfuric acid, ammonium salt – Breaker; Ethanaminium, 2-hydroxy-N,N,N-trimethyl-, chloride (1:1) – Clay Methanol – Corrosion Inhibitor; and 2-Propenamide, homopolymer – Friction Reducer. As part of EPA’s Study on the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, EPA is currently analyzing information provided by nine hydraulic fracturing service companies, including a list of chemicals the companies identify as used in hydraulic fracturing operations. EPA officials said that they expect most of these chemicals disclosed by the service companies to appear on the TSCA inventory list, provided that chemicals are not classified solely as pesticides. EPA does not expect to be able to compare the list of chemicals provided by the nine hydraulic fracturing service companies to the TSCA inventory until the release of a draft report of the Study on the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources for peer review, expected in late 2014. For those chemicals that are listed, some hydraulic fracturing service companies may be manufacturers, processors, or distributors, and could be subject to certain TSCA reporting provisions. On August 4, 2011, Earthjustice and 114 others filed a petition with EPA asking the agency to exercise TSCA authorities and issue rules to require manufacturers, processors, and distributors of chemicals used in oil and gas exploration or production to develop and/or provide certain information. The petition asserts that more than 10,000 gallons of such chemicals may be used to fracture a single well. EPA denied the portion of the petition requesting that EPA issue a TSCA section 4 rule to require identification and toxicity testing of chemicals used in oil and gas exploration or production, stating that the petition did not set forth facts sufficient to support the findings required for such test rules. The petition also requested that EPA issue new rule(s) under TSCA section 8 to require, for these chemicals, maintenance and submission of various records, call-in of records of allegations of significant adverse reactions, and submission of all existing not previously reported health EPA granted the section 8(a) and 8(d) portions of and safety studies. the petition in part, stating that the agency believes “there is value in initiating a proposed rulemaking process under TSCA authorities to obtain data on chemical substances and mixtures used in hydraulic fracturing,” but denying them so far as they concern other chemical substances used in oil and gas exploration and production but not in hydraulic fracturing. EPA is drafting an Advance Notice of Proposed Rulemaking for the section 8(a) and (d) rules. As of August 31, 2012, EPA has not released a publication date for this proposed rulemaking. EPA also intends to convene a stakeholder process to gather additional information for use in developing a proposed rule, and “to develop an overall approach that would minimize reporting burdens and costs, take advantage of existing information, and avoid duplication of efforts.” EPA officials said that the agency will consider, among other things, how to address confidential business information as it develops the proposal. A TSCA section 8(a) rule, once issued, may require reporting, insofar as known or reasonably ascertainable, of such chemical information as chemical names, molecular structure, category of use, volume, byproducts, existing environmental and health effects data, disposal practices, and worker exposure. Regulations promulgated under TSCA section 8(d) are to require submission to EPA of reasonably ascertainable health and safety studies. TSCA provides EPA with certain enforcement authorities. For example, EPA may impose a civil penalty for certain violations of TSCA, such as failing to comply with requirements to notify and provide certain information to EPA before manufacturing a new chemical, or by using for commercial purposes a chemical substance that the user had reason to know was manufactured, processed, or distributed in violation of such requirements, among other things. All six states we reviewed have state agencies responsible for implementing and enforcing environmental and public health requirements, which include overseeing oil and gas development (see table 11). In five of the six states we reviewed, this responsibility is split primarily between two different agencies. In general, one of these agencies has primary responsibility for regulating oil and gas development activities such as drilling that occur on the well pad and for managing and disposing of certain wastes generated on-site, while the other agency has a broader mandate for implementing and enforcing environmental or public health requirements, some aspects of which may affect oil and gas development. For example, the Colorado Oil and Gas Conservation Commission regulates activities such as drilling, hydraulic fracturing, and disposal of produced water in Class II UIC wells, while the Colorado Department of Public Health and Environment regulates discharges to surface waters, commercial solid waste facilities, and certain air emissions. In contrast, oil and gas development in Pennsylvania is primarily governed by one agency—the Pennsylvania Department of Environmental Protection. This appendix presents information about state statutory and regulatory requirements in the areas of siting and site preparation (see table 12); drilling, casing, and cementing (see table 13); hydraulic fracturing (see table 14); well plugging (see table 15); site reclamation (see table 16); waste management in pits (see table 17); waste management through underground injection (see table 18); and managing air emissions (see table 19). Requirements presented in the following tables have been summarized mainly from state regulations, though references to state statutes are included in certain circumstances. Table 20 is intended to show representative areas of regulation, focused on substantive requirements specific to oil and gas wells. The table includes EPA’s environmental and public health requirements, requirements from the six states included in our review, and additional requirements that apply for the development of federally-owned mineral resources. Other activities at oil and gas well sites may also be subject to federal or state regulation. In addition to the individual named above, Barbara Patterson, Assistant Director; Elizabeth Beardsley; David Bieler; Antoinette Capaccio; Cindy Gilbert; Armetha Liles; Alison O’Neill; and Janice Poling made key contributions to this report.

Summary: Technological improvements have allowed the extraction of oil and natural gas from onshore unconventional reservoirs such as shale, tight sandstone, and coalbed methane formations. Specifically, advances in horizontal drilling techniques combined with hydraulic fracturing (pumping water, sand, and chemicals into wells to fracture underground rock formations and allow oil or gas to flow) have increased domestic development of oil and natural gas from these unconventional reservoirs. The increase in such development has raised concerns about potential environmental and public health effects and whether existing federal and state environmental and public health requirements are adequate. GAO was asked to review environmental and public health requirements for unconventional oil and gas development and (1) describe federal requirements; (2) describe state requirements; (3) describe additional requirements that apply on federal lands; and (4) identify challenges, if any, that federal and state agencies reported facing in regulating oil and gas development from unconventional reservoirs. GAO identified and analyzed federal laws, state laws in six selected states (Colorado, North Dakota, Ohio, Pennsylvania, Texas, and Wyoming), and interviewed federal and state officials and representatives from industry, environmental, and public health organizations. GAO is not making recommendations. In commenting on the report, agencies provided information on recent regulatory activities and technical comments. As with conventional oil and gas development, requirements from eight federal environmental and public health laws apply to unconventional oil and gas development. For example, the Clean Water Act (CWA) regulates discharges of pollutants into surface waters. Among other things, CWA requires oil and gas well site operators to obtain permits for discharges of produced waterwhich includes fluids used for hydraulic fracturing, as well as water that occurs naturally in oil- or gas-bearing formationsto surface waters. In addition, the Resource Conservation and Recovery Act (RCRA) governs the management and disposal of hazardous wastes, among other things. However, key exemptions or limitations in regulatory coverage affect the applicability of six of these environmental and public health laws. For example, CWA also generally regulates stormwater discharges by requiring that facilities associated with industrial and construction activities get permits, but the law and its regulations largely exempt oil and gas well sites. In addition, oil and gas exploration and production wastes are exempt from RCRA hazardous waste requirements based on a regulatory determination made by the Environmental Protection Agency (EPA) in 1988. EPA generally retains its authorities under federal environmental and public health laws to respond to environmental contamination. All six states in GAOs review implement additional requirements governing activities associated with oil and gas development and have updated some aspects of their requirements in recent years. For example, all six states have requirements related to how wells are to be drilled and how casingsteel pipe within the wellis to be installed and cemented in place, though the specifics of their requirements vary. The states also have requirements related to well site selection and preparation, which may include baseline testing of water wells before drilling or stormwater management. Oil and gas development on federal lands must comply with applicable federal environmental and state laws, as well as additional requirements. These requirements are the same for conventional and unconventional oil and gas development. The Bureau of Land Management (BLM) oversees oil and gas development on approximately 700 million subsurface acres. BLM regulations for leases and permits govern similar types of activities as state requirements, such as requirements for how operators drill the well and install casing. BLM recently proposed new regulations for hydraulic fracturing of wells on public lands. Federal and state agencies reported several challenges in regulating oil and gas development from unconventional reservoirs. EPA officials reported that conducting inspection and enforcement activities and having limited legal authorities are challenges. For example, conducting inspection and enforcement activities is challenging due to limited information, such as data on groundwater quality prior to drilling. EPA officials also said that the exclusion of exploration and production waste from hazardous waste regulations under RCRA significantly limits EPAs role in regulating these wastes. In addition, BLM and state officials reported that hiring and retaining staff and educating the public are challenges. For example, officials from several states and BLM said that retaining employees is difficult because qualified staff are frequently offered more money for private sector positions within the oil and gas industry.