Unconventional Oil and Gas Development: Key Environmental and Public Health Requirements
Released: 2012-10-09T00:00:00


Highlights: section_title: Why GAO Did This Study
paragraphs: 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.

section_title: What GAO Found
paragraphs: 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.

section_title: Letter
paragraphs: For decades, the United States has imported oil and natural gas to fuel  vehicles and to heat and power homes and businesses. However,  improvements in technology have allowed companies that develop  petroleum resources to extract oil and natural gas from onshore  unconventional reservoirs that were previously considered inaccessible  because traditional techniques did not yield sufficient amounts for  economically viable production. For purposes of this report,  unconventional reservoirs include shale, tight sandstone, and coalbed  methane formations. Specifically, advances in horizontal drilling  techniques combined with hydraulic fracturing have recently increased  domestic production of oil and natural gas from such onshore  unconventional reservoirs. These advances, which have taken place over  the last several decades, now allow operators—companies that extract oil  and natural gas—to accurately determine the location of a drill bit while  drilling thousands of feet horizontally. Hydraulic fracturing involves  pumping water, sand, and chemical additives into oil and gas wells at  high enough pressure to fracture underground rock formations and allow  oil or gas to flow. When combined with horizontal drilling, hydraulic  fracturing allows operators to fracture the rock formation along the entire  horizontal portion of a well, increasing the number of pathways through  which oil or gas can flow. According to the Energy Information  Administration, oil production from shale formations (shale oil) has  increased significantly in several areas of the country, including the  Bakken formation in North Dakota and Montana, where production  increased from just over 2,000 barrels per day in 2000 to approximately  500,000 barrels per day in 2012. The Energy Information Administration  also projects that natural gas production from shale (shale gas) will  account for almost half of domestic production by 2035. According to a  2011 report by the Department of Energy, the recent substantial growth in  domestic natural gas production from shale has already brought lower  natural gas prices, domestic jobs, and the prospect of enhanced national  security.

However, the increase in oil and gas development from unconventional  reservoirs has raised concerns about the potential environmental and  public health effects of such development. For example, several  environmental groups have expressed concerns that this development  releases hazardous air pollutants, such as benzene, and may  contaminate underground drinking water supplies and surface waters due  to spills or faulty well construction. These concerns have raised questions  about existing federal and state requirements governing oil and gas  development from unconventional reservoirs on both private and federal  lands. The Environmental Protection Agency (EPA) administers and  enforces key federal laws, such as the Safe Drinking Water Act, the  Clean Water Act, and others, that aim to protect human health and the  environment. Under these statutes, EPA and its Regional offices work  with states that implement aspects of some of these laws, as well as  additional state requirements. EPA is also conducting a study, as directed  by a congressional committee, to examine the potential effects of  hydraulic fracturing on drinking water resources. In addition, federal land  management agencies, including the Department of the Interior’s Bureau  of Land Management (BLM), National Park Service, Fish and Wildlife  Service (FWS) and the U.S. Department of Agriculture’s Forest Service  manage federal lands and have responsibilities for oil and gas  development.

You asked us to review environmental and public health requirements for  oil and gas development from onshore unconventional reservoirs. For  such development, this report (1) describes federal environmental and  public health requirements; (2) describes state requirements; (3)  describes additional requirements that apply on federal lands; and (4)  identifies challenges, if any, that federal and state agencies reported  facing in regulating oil and gas development from unconventional  reservoirs.

To identify federal environmental and public health requirements  governing onshore oil and gas development from unconventional  reservoirs, we identified and analyzed eight key federal environmental  and public health laws and corresponding regulations and guidance. The  eight federal environmental and public health laws are: the 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); and Federal Insecticide, Fungicide, and  Rodenticide Act (FIFRA). We focused our analysis on federal and state  requirements that apply to activities on the well site—the area of land  where drilling takes place—and wastes or emissions generated at the  well site rather than on downstream infrastructure such as pipelines or  refineries. We also analyzed state 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, as well as those states  with large reservoirs of unconventional oil or gas, a variety of types of  unconventional reservoirs, differing historical experiences with the oil and  gas industry, and significant development on federal lands. Because we  used a nonprobability sample, the information that we collected from  these states cannot be generalized to all states but can provide illustrative  examples. We also reviewed laws, regulations, and guidance governing  oil and gas development on federal lands. In addition, we reviewed  several reports issued by environmental and public health organizations,  industry, academic institutions, and government agencies that provided  perspectives on federal and state regulations.

To complement our analysis of laws and regulations, we interviewed  officials in EPA headquarters and the four Regional offices responsible for  overseeing implementation of federal programs in the six selected states;  oil and gas and environmental regulators for the six selected states;  officials in BLM headquarters and field offices in each of the three  selected states with significant amounts of federal land; and officials in  Park Service, Forest Service, and FWS headquarters to discuss how  federal and state requirements apply to the oil and gas industry and any  challenges faced by regulators in implementing these requirements. We  also contacted representatives from industry, environmental, and public  health organizations regarding federal and state regulatory requirements  for unconventional oil and gas development. In addition, we met with  company officials to discuss federal and state regulations and visited  drilling, hydraulic fracturing, and production sites in Pennsylvania and  North Dakota. Oil and gas development may also be subject to local laws  and requirements related to water use and withdrawals, but we did not  include an analysis of these issues in the scope of our review. We also  did not include an analysis of the extent to which federal or state laws and  regulations concerning oil and gas development apply on tribal lands, or  the extent to which tribal laws may apply. In describing federal and state  requirements for oil and gas development from unconventional reservoirs,  where it is helpful to further the understanding of the requirements, we  provide examples of how these requirements have been applied, but  these examples do not attempt to provide a comprehensive view of the  extent to which enforcement actions have been taken for any of the  requirements. A more detailed description of our objectives, scope, and  methodology is presented in appendix I.

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.
subsections: section_title: Background
paragraphs: 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.
subsections: section_title: Types and Locations of Oil and Gas Reservoirs
paragraphs: 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).

section_title: Federal Environmental and Public Health Laws Apply to Unconventional Oil and Gas Development but with Key Exemptions
paragraphs: 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.
subsections: section_title: Eight Federal Environmental and Public Health Laws Apply to Unconventional Oil and Gas Development
paragraphs: 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.

section_title: Exemptions Are Related to Preventive Programs
paragraphs: 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.

section_title: States in Our Review Implement Additional Requirements and Recently Updated Some Requirements
paragraphs: 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.
subsections: section_title: States in Our Review Implement Additional Requirements and Certain Federal Requirements
paragraphs: 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.

section_title: Regional Commission Implements Additional Requirements
paragraphs: 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.

section_title: States Have Recently Updated Some Requirements
paragraphs: 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.

section_title: Additional Requirements Apply on Federal Lands
paragraphs: 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.
subsections: section_title: Requirements for Federally Owned Mineral Rights
paragraphs: 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.

section_title: Requirements for Privately Owned Mineral Rights under Federal Surface Lands
paragraphs: 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.

section_title: Federal and State Agencies Reported Several Challenges Regulating Unconventional Oil and Gas Development
paragraphs: 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.
subsections: section_title: Conducting Inspection and Enforcement Activities
paragraphs: 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.

section_title: Limited Legal Authorities
paragraphs: 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.

section_title: Hiring and Retaining Staff
paragraphs: 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.

section_title: Public Education
paragraphs: 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.

section_title: Agency Comments and Our Evaluation
paragraphs: 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.

section_title: Appendix I: Objectives, Scope, and Methodology
paragraphs: 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.

section_title: Appendix II: Key Requirements and Authorities under the Safe Drinking Water Act
paragraphs: 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.
subsections: section_title: Underground Injection Control Program
paragraphs: 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.
subsections: section_title: Class II UIC Requirements
paragraphs: 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).

section_title: Class II UIC Programs and Hydraulic Fracturing
paragraphs: 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.

section_title: Enforcement
paragraphs: 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.

section_title: Imminent and Substantial Endangerment Authorities
paragraphs: 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.

section_title: Appendix III: Key Requirements and Authorities under the Clean Water Act
paragraphs: 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).
subsections: section_title: National Pollutant Discharge Elimination System Program
paragraphs: 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).
subsections: section_title: Existing Effluent Limitations Guidelines for Oil and Gas Extraction
paragraphs: 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.

section_title: Anticipated Rulemaking to Develop Effluent Limitations Guidelines for Oil and Gas Extraction from Coalbed Methane Formations
paragraphs: 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.

section_title: Generally Applicable Pretreatment Standards and POTW Obligations
paragraphs: 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.

section_title: Anticipated Rulemaking to Develop Pretreatment Standards for Gas Extraction from Shale Formations
paragraphs: 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.

section_title: NPDES for Stormwater Discharges
paragraphs: 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.

section_title: NPDES Enforcement
paragraphs: 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.

section_title: Imminent and Substantial Endangerment Authorities
paragraphs: 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.

section_title: Oil and Hazardous Substances Spill Prevention, Reporting, and Response
subsections: section_title: Spill Prevention and Response Plans
paragraphs: 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.

section_title: Spill Prohibition and Reporting
paragraphs: 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.

section_title: Spill Response Authority
paragraphs: 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.

section_title: Enforcement of SPCC and Spill Prohibition and Reporting Requirements
paragraphs: 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).

section_title: Imminent and Substantial Endangerment Authority for Spills
paragraphs: 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.

section_title: Appendix IV: Key Requirements and Authorities under the Clean Air Act
paragraphs: 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.
subsections: section_title: National Emission Standards for Hazardous Air Pollutants
subsections: section_title: Hazardous Air Pollutants
paragraphs: 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.

section_title: NESHAPs Overview and Statutory Provisions Restricting Aggregation of Oil and Gas Production Sources
paragraphs: 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.

section_title: NESHAPs for Oil and Natural Gas Production Facilities
paragraphs: 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.

section_title: Other NESHAPs
paragraphs: 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.

section_title: New Source Performance Standards
paragraphs: 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.
subsections: section_title: April 2012 Amendments to NSPS
paragraphs: 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.

section_title: Other NSPS
paragraphs: 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.

section_title: New Source Review
paragraphs: 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.

section_title: Title V Operating Permits
paragraphs: 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.

section_title: Source Determinations and Aggregation Issues for Title V and NSR
paragraphs: 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.

section_title: Greenhouse Gas Reporting Rule
paragraphs: 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_title: Accidental Releases
paragraphs: 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.
subsections: section_title: Accidental Release Prevention (Risk Management Program)
paragraphs: 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.

section_title: General Duty to Prevent Accidental Releases
paragraphs: 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_title: Imminent and Substantial Endangerment Authority Respecting Accidental Releases
paragraphs: 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.

section_title: Chemical Safety Board
paragraphs: 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.

section_title: EPA Enforcement Authorities
paragraphs: 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.

section_title: Imminent and Substantial Endangerment Authority
paragraphs: 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.

section_title: Appendix V: Key Requirements and Authorities under the Resource Conservation and Recovery Act
paragraphs: 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.
subsections: section_title: Subtitle C – Hazardous Waste
paragraphs: 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.
subsections: section_title: Exemption of Certain Oil and Gas Production Wastes from Regulation as Hazardous Waste under RCRA Subtitle C
paragraphs: 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).

section_title: Oil and Gas Exploration and Production Wastes That Are Not Exempt from Regulation
paragraphs: 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.

section_title: Subtitle D – Solid Waste
paragraphs: 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.)

section_title: Enforcement
paragraphs: 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.

section_title: Imminent and Substantial Endangerment Authority
paragraphs: 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.

section_title: Appendix VI: Key Requirements and Authorities under the Comprehensive Environmental Response, Compensation, and Liability Act
paragraphs: 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.
subsections: section_title: Relevant Exclusions and Definitions
paragraphs: 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.

section_title: CERCLA Hazardous Substance Release Reporting
paragraphs: 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.

section_title: Relevant EPA Authorities
paragraphs: 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.

section_title: Appendix VII: Key Requirements and Authorities under the Emergency Planning and Community Right-to-Know Act
paragraphs: 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.
subsections: section_title: Generally Applicable Chemical Information, Inventory, and Release Reporting
paragraphs: 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.

section_title: Requirements under EPCRA That May Be Triggered at Well Sites
paragraphs: 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.

section_title: Toxic Release Inventory
paragraphs: 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.

section_title: Enforcement
paragraphs: 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.

section_title: Appendix VIII: Key Requirements and Authorities under the Toxic Substances Control Act
paragraphs: 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.

section_title: Appendix IX: Selected State Requirements
paragraphs: 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.

section_title: Appendix X: Crosswalk between Selected Requirements from EPA, States, and Federal Lands
paragraphs: 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.

section_title: Appendix XI: Comments from the Department of Agriculture

section_title: Appendix XII: Comments from the Department of the Interior

section_title: Appendix XIII: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact

section_title: Staff Acknowledgments
paragraphs: 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.


Question-summary annotations: questions: question: How have the states in GAO's review changed?
answer: 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.
child_questions: question: What is the scope of these laws?
answer: 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.

questions: question: What regulations restrict oil and gas development on federal lands?
answer: Oil and gas development on federal lands must comply with applicable federal environmental and state laws, as well as additional requirements.
child_questions: question: Do these regulations apply to both conventional and unconventional development?
answer: These requirements are the same for conventional and unconventional oil and gas development.

question: What does the Bureau of Land Management do?
answer: The Bureau of Land Management (BLM) oversees oil and gas development on approximately 700 million subsurface acres.
child_questions: question: What kinds of regulation does BLM oversee?
answer: 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.

questions: question: How have agencies managed to regulate oil and gas development?
answer: Federal and state agencies reported several challenges in regulating oil and gas development from unconventional reservoirs.
child_questions: question: What challenges have these agencies faced?
answer: EPA officials reported that conducting inspection and enforcement activities and having limited legal authorities are challenges.
child_questions: question: What specific challenges relate to this?
answer: 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.
child_questions: question: How has hiring staff been a challenge for these agencies?
answer: 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.

questions: question: How have technological improvements affected oil and gas extraction?
answer: Technological improvements have allowed the extraction of oil and natural gas from onshore unconventional reservoirs such as shale, tight sandstone, and coalbed methane formations.
child_questions: question: What specific developments have occurred as a result?
answer: 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.

question: What are the results of these improvements in extraction of oil and gas?
answer: 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.