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United States Government Accountability Office: 
GAO: 

Report to Congressional Requesters: 

September 2012: 

Unconventional Oil and Gas Development: 

Key Environmental and Public Health Requirements: 

GAO-12-874: 

GAO Highlights: 

Highlights of GAO-12-874, a report to congressional requesters. 

Why GAO Did This Study: 

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. 

What GAO Found: 

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. 

What GAO Recommends: 

GAO is not making recommendations. In commenting on the report, 
agencies provided information on recent regulatory activities and 
technical comments. 

View [hyperlink, http://www.gao.gov/products/GAO-12-874]. For more 
information, contact David C. Trimble at (202) 512-3841 or 
trimbled@gao.gov. 

[End of section] 

Contents: 

Letter: 

Background: 

Federal Environmental and Public Health Laws Apply to Unconventional 
Oil and Gas Development but with Key Exemptions: 

States in Our Review Implement Additional Requirements and Recently 
Updated Some Requirements: 

Additional Requirements Apply on Federal Lands: 

Federal and State Agencies Reported Several Challenges Regulating 
Unconventional Oil and Gas Development: 

Agency Comments and Our Evaluation: 

Appendix I: Objectives, Scope, and Methodology: 

Appendix II: Key Requirements and Authorities under the Safe Drinking 
Water Act: 

Underground Injection Control Program: 

Imminent and Substantial Endangerment Authorities: 

Appendix III: Key Requirements and Authorities under the Clean Water 
Act: 

National Pollutant Discharge Elimination System Program: 

Oil and Hazardous Substances Spill Prevention, Reporting, and Response: 

Appendix IV: Key Requirements and Authorities under the Clean Air Act: 

National Emission Standards for Hazardous Air Pollutants: 

New Source Performance Standards: 

New Source Review: 

Title V Operating Permits: 

Source Determinations and Aggregation Issues for Title V and NSR: 

Greenhouse Gas Reporting Rule: 

Accidental Releases: 

EPA Enforcement Authorities: 

Imminent and Substantial Endangerment Authority: 

Appendix V: Key Requirements and Authorities under the Resource 
Conservation and Recovery Act: 

Subtitle C - Hazardous Waste: 

Subtitle D - Solid Waste: 

Enforcement: 

Imminent and Substantial Endangerment Authority: 

Appendix VI: Key Requirements and Authorities under the Comprehensive 
Environmental Response, Compensation, and Liability Act: 

Appendix VII: Key Requirements and Authorities under the Emergency 
Planning and Community Right-to-Know Act: 

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

Appendix IX: Selected State Requirements: 

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

Appendix XI: Comments from the Department of Agriculture: 

Appendix XII: Comments from the Department of the Interior: 

Appendix XIII: GAO Contact and Staff Acknowledgments: 

Tables: 

Table 1: Potential Waste Management and Disposal Options: 

Table 2: Exemptions or Limitations in Regulatory Coverage for the Oil 
and Gas Exploration and Production Industry in Six Environmental Laws: 

Table 3: Key EPA Response Authorities Relevant to Oil and Gas Well 
Sites: 

Table 4: Key Federal Environmental and Public Health Requirements and 
State Requirements for Oil and Gas Production Wells: 

Table 5: Chemical Disclosure Requirements in Six Selected States: 

Table 6: Surface Agency Roles in Leasing and Permitting Federal 
Minerals: 

Table 7: Agencies and Organizations Contacted: 

Table 8: Summary of Effluent Limitations Guidelines for Wastewater 
Discharges from Selected Subcategories of Oil and Gas Wells Located on 
Land: 

Table 9: Summary of CAA Programs That May Apply to Emissions from Oil 
and Gas Well Sites: 

Table 10: NSPS for Natural Gas Wells, by Well Subcategory: 

Table 11: Primary State Agencies Responsible for Regulating Oil and 
Gas Development in Six States: 

Table 12: Selected State Requirements--Siting and Site Preparation: 

Table 13: Selected State Requirements--Drilling, Casing, and Cementing: 

Table 14: Selected State Requirements--Hydraulic Fracturing: 

Table 15: Selected State Requirements--Well Plugging: 

Table 16: Selected State Requirements--Site Reclamation: 

Table 17: Selected State Requirements--Waste Management in Pits: 

Table 18: Selected State Requirements--Waste Management through 
Underground Injection: 

Table 19: Selected State Requirements--Managing Air Emissions: 

Table 20: Crosswalk between Selected Requirements from EPA, Six 
States, and Federal Minerals: 

Figures: 

Figure 1: Conventional and Unconventional Oil and Gas Reservoirs: 

Figure 2: Locations of Unconventional Reservoirs in the United States: 

Figure 3: Well Pad and Freshwater Storage Tanks: 

Figure 4: Horizontal Drilling and Hydraulic Fracturing in an 
Unconventional Shale Formation: 

Figure 5: Hydraulic Fracturing in a Coalbed Methane Formation: 

Figure 6: Potential Sources and Types of Air Emissions from Oil and 
Gas Development: 

Figure 7: Enhanced Recovery and Disposal Wells: 

Abbreviations: 

APD: application for permit to drill: 

BLM: Bureau of Land Management: 

BTEX: benzene, toluene, ethylbenzene, xylenes: 

CAA: Clean Air Act: 

CAS: Chemical Abstracts Service: 

CERCLA: Comprehensive Environmental Response, Compensation, and 
Liability Act: 

CWA: Clean Water Act: 

EPA: Environmental Protection Agency: 

EPCRA: Emergency Planning and Community Right-to-Know Act: 

FIFRA: Federal Insecticide, Fungicide, and Rodenticide Act: 

FWS: Fish and Wildlife Service: 

H2S: hydrogen sulfide: 

HAP: hazardous air pollutant: 

MACT: maximum achievable control technology: 

NAICS: North American Industry Classification System: 

NEPA: National Environmental Policy Act: 

NESHAP: National Emissions Standards for Hazardous Air Pollutants: 

NORM: naturally-occurring radioactive material: 

NPDES: National Pollutant Discharge Elimination System: 

NSPS: New Source Performance Standards: 

NSR: New Source Review: 

OEPA: Ohio Environmental Protection Agency: 

POTW: publicly-owned treatment works: 

PSD: Prevention of Significant Deterioration: 

psi: pounds per square inch: 

RCRA: Resource Conservation and Recovery Act: 

SDWA: Safe Drinking Water Act: 

SIP: state implementation plan: 

SPCC: Spill Prevention, Control, and Countermeasure: 

STRONGER: State Review of Oil and Natural Gas Environmental 
Regulations: 

TRI: Toxics Release Inventory: 

TSCA: Toxic Substances Control Act: 

UIC: Underground Injection Control: 

VOC: volatile organic compound: 

[End of section] 

United States Government Accountability Office: 
Washington, DC 20548: 

September 5, 2012: 

Congressional Requesters: 

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,[Footnote 1] 
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,[Footnote 2] oil production from 
shale formations (shale oil)[Footnote 3] 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.[Footnote 4] 

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.[Footnote 5] 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.[Footnote 
6] 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.[Footnote 7] 

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. 

Background: 

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. 

Types and Locations of Oil and Gas Reservoirs: 

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. 

Figure 1: Conventional and Unconventional Oil and Gas Reservoirs: 

[Refer to PDF for image: illustration] 

depicted in the illustration: 

Land surface; 
Coalbed methane; 
Sandstone; 
Conventional gas; 
Conventional oil; 
Tight sand; 
Gas; 
Oil- or gas-rich shale. 

Source: U.S. Energy Information Administration and U.S. Geological 
Survey. 

[End of figure] 

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 figure 
2).[Footnote 8] 

Figure 2: Locations of Unconventional Reservoirs in the United States: 

[Refer to PDF for image: 3 illustrated U.S. maps] 

Maps depict locations of unconventional reservoirs of: 
Shale basins; 
Tight sandstone basins; 
Coalbed methane basins. 

Source: U.S. Energy Information Administration. 

Note: The map for tight sandstone basins is based off Energy 
Information Administration data for "tight gas," which includes both 
tight sandstone and tight carbonate formations. 

[End of figure] 

Activities Associated With Oil and Gas Development: 

Developing unconventional reservoirs involves a variety of activities, 
many of which are also conducted in conventional oil and gas drilling. 
[Footnote 9] 

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 figure 3). In some cases, multiple 
wells will be located on a single well pad. 

Figure 3: Well Pad and Freshwater Storage Tanks: 

[Refer to PDF for image: 2 photographs] 

Well Pad; 
Tanks storing freshwater for hydraulic fracturing. 

Source: GAO. 

[End of figure] 

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.[Footnote 10] 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.[Footnote 11] 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),[Footnote 12] 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 figure 
4). Some coalbed methane wells are hydraulically fractured (see figure 
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. 

Figure 4: Horizontal Drilling and Hydraulic Fracturing in an 
Unconventional Shale Formation: 

[Refer to PDF for image: illustration] 

Depicted in the illustration: 

Residential home: 
residential water well; 
Aquifer. 

Wellhead: 
Soil: 
* Cement; 
* Conductor casing; 
Aquifer: 
* Cement; 
* Surface casing; 
* Cement; 
* Intermediate casing. 

At 6,000 feet: 
Target formation. 

Source: "Groundwater Protection through Proper WEll Construction," 
July 16, 2012, reproduced courtesy of the American Petroleum Institute. 

Note: Shale formations can occur at varying depths, including 
thousands of feet beneath the surface, and according to the American 
Petroleum Institute, are separated by multiple layers of impervious 
rock. This figure, which is not to scale, provides a generalized 
depiction of subsurface geology and well construction; wells may be 
constructed in a variety of different ways. 

[End of figure] 

Figure 5: Hydraulic Fracturing in a Coalbed Methane Formation: 

[Refer to PDF for image: illustration] 

Depicted in the illustration: 

Ground level: 
Residential water well; 
Well pad; 
Produced water tank; 
Aboveground gas pipeline. 

Underground: 
Sandstone aquifer (500 feet); 
1,500 feet: Coal; 
Perforations through casing and cement into porous rock; 
Submersible pump inside casing. 

Source: Ecova, Inc. 

Note: The water pressure within coalbed methane formations forces 
natural gas to adhere to the coal. Capturing the gas requires 
operators to pump water out of the coal formation to reduce the 
pressure, allowing the natural gas to release (desorb) from the 
surface of the coal, diffuse through micropores, and then flow through 
coal cleats (natural fracture systems) into the well. This figure 
depicts one possible configuration of a coalbed methane well, but 
other configurations, including aboveground pumps, horizontal 
drilling, different types of casing and cementing, and deeper or 
shallower coalbed methane formations are also possible. 

[End of figure] 

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.[Footnote 13] 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 designated for such 
purposes.[Footnote 14] Operators also generate solid wastes 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. 

Table 1: Potential Waste Management and Disposal Options[A]: 

Primary types of waste: 
Liquid waste[B]: 
* Produced water; 
* Drilling mud; 
Solid waste: 
* Drill cuttings; 
* Trash; 
Hazardous waste: 
* Unused hydraulic fracturing chemicals being discarded; 
* Certain other chemical and oily wastes. 

Options for temporary storage: 
Liquid waste[B]: 
* Tanks or pits; 
Solid waste: 
* Tanks or pits; 
Hazardous waste: 
* Tanks. 

Options for reuse: 
Liquid waste[B]: 
* Recycle for use in future hydraulic fracturing; 
* Irrigation; 
* Roadspreading (used for dust or ice suppression); 
* Reuse of drilling mud; 
Solid waste: 
* Roadspreading of drill cuttings; 
Hazardous waste: N/A. 

Options for permanent disposal: 
Liquid waste[B]: 
* Underground injection well; 
* Discharge to surface water; 
* Commercial treatment facilities; 
* Publicly-owned treatment works; 
Solid waste: 
* Solid waste landfill; 
* Bury drill cuttings on or near well pad; 
Hazardous waste: 
* Hazardous waste disposal facility. 

Source: GAO. 

[A] This table identifies a range of temporary storage and permanent 
disposal options but may not include all available options. Depending 
on the region or state, some practices may not be technically feasible 
or legally permissible. The table lists potential disposal options; in 
some cases, treatment may be required before disposal. 

[B] Liquid wastes may be considered solid or hazardous wastes under 
applicable law. Liquid wastes are listed separately here because 
liquid wastes may be managed differently from wastes that are more 
solid in form. 

[End of table] 

Managing air emissions. Throughout the drilling, hydraulic fracturing, 
and production activities, operators also are to manage air emissions. 
There are four key types of air emissions that may occur at oil and 
gas well sites as follows: 

* Criteria pollutants are a set of common air pollutants that include 
ground level ozone, nitrogen oxides, particulate matter, sulfur 
dioxide, and carbon monoxide.[Footnote 15] Ground level ozone is 
created by chemical reactions between nitrogen oxides and volatile 
organic compounds and is associated with a wide range of adverse 
health effects that range from decreased lung function to hospital 
admissions for respiratory causes.[Footnote 16] Particulate matter is 
a complex mixture of small particles and liquid droplets, which are 
linked to a variety of health problems such as cardiovascular and 
respiratory problems. Nitrogen oxides have been linked to respiratory 
illness. Short-term exposure to sulfur dioxide is linked to a number 
of adverse respiratory effects, including the narrowing of airways and 
increased asthma symptoms. Carbon monoxide can cause harmful health 
effects by reducing oxygen delivery to the body's organs (like the 
heart and brain). 

* Hazardous air pollutants, such as benzene, are pollutants known or 
suspected to cause cancer or other serious health effects, such as 
birth defects, or adverse environmental effects. 

* Hydrogen sulfide is a toxic and flammable gas that poses safety and 
health hazards to workers at the well site. 

* Methane is a greenhouse gas that, according to some estimates, is 
over 20 times more efficient in trapping heat in the atmosphere than 
carbon dioxide--another greenhouse gas--over a 100-year period. 

Emissions related to oil and gas production are from both stationary 
sources and mobile sources (see figure 6). Stationary sources include 
wells, pumps, storage vessels, pneumatic controllers, dehydrators, 
pits, and flaring.[Footnote 17] Mobile sources include trucks bringing 
fuel, water, or supplies to the well site; construction vehicles; and 
some truck-mounted pumps or engines used for drilling or hydraulic 
fracturing. 

Figure 6: Potential Sources and Types of Air Emissions from Oil and 
Gas Development: 

[Refer to PDF for image: 9 photographs and associated information] 

Stationary sources: 

Well: 
Description: An oil or gas well may be an emissions source, 
particularly after hydraulic fracturing as fluids and gases flow back 
to the surface; 
Potential emissions: Methane, volatile organic compounds, hydrogen 
sulfide, and hazardous air pollutants. 

Storage vessels: 
Description: Storage vessels are used to hold a variety of liquids, 
including crude oil, condensate, and produced water; 
Potential emissions: Methane, volatile organic compounds, and 
hazardous air pollutants. 

Pneumatic controllers: 
Description: Automated instruments are used for maintaining 
conditions, such as liquid level, pressure, and temperature; 
Potential emissions: Methane, volatile organic compounds, and 
hazardous air pollutants.   

Heater treater: 
Description: Heater treaters are used to remove water from oil; 
Potential emissions: Nitrogen oxides and carbon monoxide. 

Dehydrator: 
Description: Dehydration removes water that is entrained in the 
natural gas stream; 
Potential emissions: Methane, volatile organic compounds, and 
hazardous air pollutants. 

Pits: 
Description: Pits are used to store freshwater and/or produced water; 
Potential emissions: Volatile organic compounds, methane, and 
hazardous air pollutants. 

Flaring: 
Description: Flaring may be used for safety reasons or, in areas where 
the primary purpose of drilling is to produce oil, gas may be flared 
because no local market exists for the gas (pictured here); 
Potential emissions: Nitrogen oxides, particulate matter, carbon 
monoxide, carbon dioxide, and sulfur dioxide. 

Mobile sources: 

On-road diesel engines: 
Description: Trucks transport materials to and from the well site; 
Potential emissions: Nitrogen oxides, particulate matter, carbon 
monoxide, and hazardous air pollutants. 

Off-road diesel engines: 
Description: Compressors and engines are used to drill and 
hydraulically fracture the well; 
Potential emissions: Nitrogen oxides, particulate matter, carbon 
monoxide, and hazardous air pollutants     

Sources: GAO; photos from GAO except the pneumatic controllers and 
dehydrator are from BLM, and the pit is courtesy of [hyperlink, 
http://www.marcellus-shale.us]. 

[End of figure] 

Federal Environmental and Public Health Laws Apply to Unconventional 
Oil and Gas Development but with Key Exemptions: 

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. 

Eight Federal Environmental and Public Health Laws Apply to 
Unconventional Oil and Gas Development: 

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;[Footnote 18] for more 
details about seven of these laws, please see appendixes II through 
VIII. 

Safe Drinking Water Act: 

SDWA is the main federal law that ensures the quality of drinking 
water.[Footnote 19] 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. 

UIC Program: 

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. 
[Footnote 20] 

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 figure 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.[Footnote 21] 

Figure 7: Enhanced Recovery and Disposal Wells: 

[Refer to PDF for image: illustration] 

Depicted in the illustration: 

Base of underground sources of drinking water; 
Injection well for disposal; 
Injection well for enhanced recovery; 
Production well; 
Confining formation; 
Enhanced recovery (oil into production well). 

Source: EPA. 

[End of figure] 

UIC regulations include minimum federal requirements for most Class II 
UIC wells; these requirements are generally applicable only where EPA 
implements the program.[Footnote 22] For example, for most new Class 
II UIC wells, an operator[Footnote 23] 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.[Footnote 24] 

In 2005, the Energy Policy Act amended SDWA to specifically exempt 
hydraulic fracturing from the UIC program, except if diesel fuel is 
injected as part of hydraulic fracturing. Thus, SDWA as amended 
continues to authorize regulation of hydraulic fracturing using diesel 
fuel.[Footnote 25] EPA officials told us that they do not have data 
about how frequently companies currently use diesel in hydraulic 
fracturing.[Footnote 26] According to EPA officials, EPA recently 
identified wells for which publicly available data suggest diesel was 
used in hydraulic fracturing.[Footnote 27] Since 2005, however, EPA 
officials said that the agency has not received any permit 
applications or issued any permits authorizing diesel to be used in 
hydraulic fracturing. EPA officials also said that they were not aware 
of any state UIC programs that had issued such permits. EPA 
headquarters officials said that EPA requires operators conducting 
hydraulic fracturing operations with diesel fuel to apply for a Class 
II UIC permit. In May 2012, EPA published draft guidance on how its 
UIC permit writers should address hydraulic fracturing with diesel in 
the context of the Class II UIC 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. 

Imminent and Substantial Endangerment Authority: 

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. 

Clean Water Act: 

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.[Footnote 28] 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).[Footnote 29] Second, spill reporting and 
spill prevention and response planning requirements pertain to certain 
threats to U.S. navigable waters and adjoining shorelines.[Footnote 
30] 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. 

NPDES: 

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.[Footnote 31] 

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 west 
[Footnote 32] in which the 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 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. 
[Footnote 33] 

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. 
[Footnote 34] As a result of this 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. 
[Footnote 35] 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. 

Spill Reporting and Spill Prevention and Response Planning: 

CWA prohibits discharges of oil or hazardous substances into U.S. 
navigable waters or on adjoining shorelines. Specifically, CWA 
requires facilities--including oil and gas well sites--to report any 
unpermitted releases of oil or hazardous substances above threshold 
quantities to the 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.[Footnote 36] 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.[Footnote 37] 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. 

Imminent and Substantial Endangerment and Release Response Authorities: 

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,[Footnote 38] EPA requested information 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. 

Clean Air Act: 

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.[Footnote 39] 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. 

Mobile Sources-Criteria Air Pollutants: 

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.[Footnote 40] 
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. 

Stationary Sources-Criteria Air Pollutants: 

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.[Footnote 41] 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[Footnote 42] 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.[Footnote 43] 
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.[Footnote 44] 

* 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. 

Stationary Sources-Hazardous Air Pollutants: 

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.[Footnote 45] 

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.[Footnote 46] EPA headquarters 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. 

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.[Footnote 47] 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.[Footnote 48] 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.[Footnote 49] 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. 

Stationary Sources-Greenhouse Gas Reporting: 

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.[Footnote 50] The 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. 

Resource Conservation and Recovery Act: 

RCRA, passed in 1976, established EPA's authority to regulate the 
generation, transportation, treatment, storage, and disposal of 
hazardous wastes.[Footnote 51] 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.[Footnote 52] 
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.[Footnote 53] 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.[Footnote 54] 
Facilities generating smaller quantities of hazardous waste are not 
subject to these requirements.[Footnote 55] 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. 

Comprehensive Environmental Response, Compensation, and Liability Act: 

Congress passed CERCLA in 1980 to protect public health and the 
environment by addressing the cleanup of hazardous substance releases. 
[Footnote 56] 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. 

Emergency Planning and Community Right-to-Know Act: 

Among other things, EPCRA provides individuals and their communities 
with access to information regarding storage or release of certain 
chemicals in their communities.[Footnote 57] 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.[Footnote 58] 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.[Footnote 59] 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.[Footnote 60] 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.[Footnote 
61] 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.[Footnote 62] 
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.[Footnote 63] 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. 

Toxic Substances Control Act: 

TSCA authorizes EPA to regulate the manufacture, processing, use, 
distribution in commerce, and disposal of chemical substances and 
mixtures.[Footnote 64] 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.[Footnote 
65] 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.[Footnote 66] 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. 

Federal Insecticide, Fungicide, and Rodenticide Act: 

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.[Footnote 67] 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,[Footnote 68] 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.[Footnote 69] 

Exemptions Are Related to Preventive Programs: 

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. 

Table 2: Exemptions or Limitations in Regulatory Coverage for the Oil 
and Gas Exploration and Production Industry in Six Environmental Laws: 

Law: SDWA; 
Description of exemption or limitation in regulatory coverage: 
Hydraulic fracturing with fluids other than diesel fuel does not 
require a UIC permit; 
Source: Statutory (2005); 
Type of program related to exemption or limitation in regulatory 
coverage: Preventive. 

Law: CWA; 
Description of exemption or limitation in regulatory coverage: Federal 
stormwater permits are not required for uncontaminated stormwater at 
oil and gas construction sites or at oil and gas well sites; 
Source: Statutory (1987, 2005); 
Type of program related to exemption or limitation in regulatory 
coverage: Preventive. 

Law: CAA; 
Description of exemption or limitation in regulatory coverage: 
Emissions of hazardous air pollutants from oil and gas wells and their 
associated equipment may not be aggregated together or with those of 
pipeline compressors or pump stations to determine whether they are a 
major source; 
Source: Statutory (1990); 
Type of program related to exemption or limitation in regulatory 
coverage: Preventive. 

Law: CAA; 
Description of exemption or limitation in regulatory coverage: In the 
Risk Management Program, many naturally-occurring hydrocarbons in oil 
and gas are not included in the threshold determination of whether a 
facility should be regulated; 
Source: Regulatory/EPA decision (1988); 
Type of program related to exemption or limitation in regulatory 
coverage: Preventive. 

Law: RCRA; 
Description of exemption or limitation in regulatory coverage: Oil and 
gas exploration and production wastes are not regulated as hazardous 
waste; 
Source: Regulatory/EPA decision (1988); 
Type of program related to exemption or limitation in regulatory 
coverage: Preventive. 

Law: CERCLA; 
Description of exemption or limitation in regulatory coverage: 
Liability and reporting provisions do not apply to injections of 
fluids authorized by state law for production, enhanced recovery, or 
produced water; 
Source: Statutory (1980); 
Type of program related to exemption or limitation in regulatory 
coverage: Preventive. 

Law: EPCRA; 
Description of exemption or limitation in regulatory coverage: Oil and 
gas well operations are not required to report releases of listed 
chemicals to the TRI; 
Source: Regulatory/EPA decision (1997); 
Type of program related to exemption or limitation in regulatory 
coverage: Preventive. 

Source: GAO. 

Note: In some cases, states may have requirements in these areas. 
State requirements are discussed in the next section of this report. 

[End of table] 

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.[Footnote 70] See appendixes II through VI for a 
more detailed discussion of these authorities. 

Table 3: Key EPA Response Authorities Relevant to Oil and Gas Well 
Sites[A]: 

Imminent and substantial endangerment and general response authorities: 

Law: SDWA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Imminent and substantial endangerment (§ 
1431); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Contaminant present in 
or likely to enter a public water system or an underground source of 
drinking water. 

Law: CWA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Imminent and substantial endangerment (§ 
504); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Source(s) of pollution, 
including discharge of pollutant to surface waters. 

Law: CWA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Response authority; imminent and 
substantial threat (§ 311); 
Situation to which authority may apply: Actual or threatened discharge 
of oil or hazardous substances into U.S navigable waters or on 
adjoining shorelines. 

Law: CAA[B]; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Imminent and substantial endangerment (§ 
112(r)(9)); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Accidental release to 
the air of regulated substance. 

Law: RCRA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Imminent and substantial endangerment (§ 
7003); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Past or present 
handling, storage, treatment, transportation, or disposal of any solid 
waste or hazardous waste. 

Law: CERCLA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Response authority (§ 104(a)); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Actual or threatened 
release of any hazardous substance. 

Law: CERCLA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Law: Imminent and substantial 
endangerment (§ 104(a)); 
Situation to which authority may apply: Actual or threatened release 
of any hazardous substance or pollutant or contaminant (other than 
petroleum). 

Law: CERCLA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Imminent and substantial endangerment (§ 
106(a)); 
Situation to which authority may apply: Actual or threatened release 
of a hazardous substance from a facility[C]. 

Access, information, and inspection authorities: 

Law: SDWA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Access to records and to inspect 
facilities (§ 1445(b)); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Persons and facilities 
subject to UIC program requirements. 

Law: CWA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Access to records and to inspect 
facilities; 
require reports (§ 308(a)); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Location of effluent 
source. 

Law: CWA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Access to records and to inspect 
facilities; ability to require provision of information (§ 311(m)(2)); 
Situation to which authority may apply: Persons and facilities subject 
to section 311, such as SPCC program requirements. 

Law: CAA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Access to records; 
ability to require provision of information (§ 114(a)); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Person who owns or 
operates any emission source, among others. 

Law: RCRA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Access to records and to inspect 
facilities (§ 3007); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Persons that have 
generated, stored, treated, transported, disposed of, or otherwise 
handled hazardous wastes[D]. 

Law: CERCLA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Access to records and to inspect 
facilities; 
ability to require provision of information (§ 104(e)); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: Location of actual or 
threatened release, generation, storage, treatment, or disposal of any 
hazardous substance or pollutant or contaminant (other than petroleum). 

Law: TSCA; 
Key response authorities: Imminent and substantial endangerment and 
general response authorities: Access to inspect facilities and onsite 
records (§ 11); 
Situation to which authority may apply: Imminent and substantial 
endangerment and general response authorities: In relevant part, 
facilities where chemical substances are manufactured, processed, 
stored, or held before or after their distribution or sale. 

Source: GAO. 

[A] The table lists selected EPA authorities that may be applicable 
when conditions or events at a well site present particular risk to 
the environment or human health. Whether a particular authority is 
applicable depends upon the facts of the situation meeting all 
prerequisite conditions. EPA has other authorities not listed in the 
table, including the ability to require certain persons to provide 
information, such as information to aid in developing plans or 
standards, and the ability to sample emissions or effluent. EPA also 
has authorities by which it may enforce requirements and address 
violations of the programs it administers. 

[B] In addition, CAA section 303 provides EPA a general imminent and 
substantial endangerment authority to address emission of air 
pollutants, where conditions are met. 

[C] Generally, CERCLA section 104 authorizes EPA to take various 
actions to respond to a release, whereas section 106 authorizes EPA to 
require potentially responsible parties to do so. 

[D] EPA interprets this provision of RCRA to include solid waste that 
EPA reasonably believes may pose a hazard when improperly managed. 

[End of table] 

States in Our Review Implement Additional Requirements and Recently 
Updated Some Requirements: 

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. 

States in Our Review Implement Additional Requirements and Certain 
Federal Requirements: 

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.[Footnote 71] We did not assess whether all requirements are 
appropriate for all states as part of this review. 

Table 4: Key Federal Environmental and Public Health Requirements and 
State Requirements for Oil and Gas Production Wells: 

Siting and site preparation: 

Area of regulation: Identification or testing of water wells prior to 
drilling of production wells; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 1 of 6 (Wyoming) [identification 
alone]; 
2 of 6 (Colorado, Ohio) [identification and testing][A]. 

Area of regulation: Required setbacks from water sources; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 5 of 6 (Colorado, North Dakota, 
Pennsylvania, Ohio, Wyoming). 

Area of regulation: Stormwater permitting; 
EPA environmental and public health requirements: Effectively no[B]; 
Requirements of six states reviewed: 4 of 6 (Colorado, North Dakota, 
Pennsylvania, Wyoming). 

Drilling, casing, and cementing: 

Area of regulation: Requirements relating to cementing/casing plans; 
EPA environmental and public health requirements: No[C]; 
Requirements of six states reviewed: 6 of 6. 

Area of regulation: Prescribed placement of surface casing relative to 
groundwater zones; 
EPA environmental and public health requirements: No[C]; 
Requirements of six states reviewed: 6 of 6. 

Hydraulic fracturing: 

Area of regulation: Requirements to disclose information on fracturing 
fluids; 
EPA environmental and public health requirements: No[D]; 
Requirements of six states reviewed: 6 of 6. 

Well plugging: 

Area of regulation: Requirements for notification, plugging plan or 
method, witnessing, and reporting; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 6 of 6. 

Area of regulation: Programs to plug wells that are not properly 
plugged and have been abandoned; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 6 of 6. 

Site reclamation: 

Area of regulation: Requirements for backfilling, regrading, 
recontouring, and alleviating compaction of soil; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 6 of 6. 

Area of regulation: Revegetation requirements; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 5 of 6 (Colorado, North Dakota, 
Ohio, Pennsylvania, Wyoming). 

Waste management: 

Area of regulation: Pit lining requirements; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 5 of 6 (Colorado, North Dakota, 
Pennsylvania, Texas, Wyoming). 

Area of regulation: Options for waste disposal: Underground injection; 
EPA environmental and public health requirements: Yes (SDWA); 
Requirements of six states reviewed: 5 states have their own 
requirements (Colorado, North Dakota, Ohio, Texas, Wyoming); 
EPA implements the program in Pennsylvania. 

Area of regulation: Options for waste disposal: Direct discharge to 
surface water; 
EPA environmental and public health requirements: Yes (CWA - certain 
discharges prohibited, others subject to conditions and permit); 
Requirements of six states reviewed: Surface discharges are allowed in 
certain cases in 3 western states (Colorado, Texas, and Wyoming). 

Area of regulation: Options for waste disposal: Requirements for 
discharge to POTWs or Centralized Waste Treatment (CWT) facilities; 
EPA environmental and public health requirements: Pretreatment 
standards for shale gas wastewater under development (CWA); 
Requirements of six states reviewed: Disposal at POTWs is an option in 
two states (Ohio, Pennsylvania)[E]; 
Disposal at CWT facilities is an option in 3 states (Colorado, 
Pennsylvania, Wyoming). 

Area of regulation: Options for waste disposal: Recycling or other 
reuse; 
EPA environmental and public health requirements: Yes (CWA - certain 
produced water discharges); 
Requirements of six states reviewed: 6 of 6 states allow recycling or 
other reuse. 

Area of regulation: Options for waste disposal: Solid waste disposal; 
EPA environmental and public health requirements: Effectively no[F]; 
Requirements of six states reviewed: Yes. 

Area of regulation: Options for waste disposal: Hazardous waste 
disposal; 
EPA environmental and public health requirements: Effectively no[G]; 
Requirements of six states reviewed: No. 

Managing air emissions: 

Area of regulation: Requirements for criteria pollutants; 
EPA environmental and public health requirements: Certain CAA 
provisions apply; 
Requirements of six states reviewed: 5 of 6 states have permitting or 
registration programs (Colorado, North Dakota, Ohio, Texas, Wyoming). 

Area of regulation: Requirements for hazardous air pollutants; 
EPA environmental and public health requirements: Certain CAA 
provisions apply; 
Requirements of six states reviewed: State permitting or registration 
programs may address hazardous air pollutants. 

Area of regulation: Requirements related to hydrogen sulfide gas; 
EPA environmental and public health requirements: No specific 
requirements but CAA general duty clause requires prevention of 
accidental releases; 
Requirements of six states reviewed: 6 of 6. 

Area of regulation: Requirements related to flaring; 
EPA environmental and public health requirements: Under new NSPS 
regulation, most hydraulically fractured gas wells must do green 
completions; 
Requirements of six states reviewed: 6 of 6. 

Sources: GAO analysis of federal and state laws and regulations. 

[A] Testing requirement applies only to certain wells--certain wells 
near proposed coalbed methane wells in Colorado and wells proposed for 
urbanized areas or in the vicinity of horizontal wells in Ohio. 
Pennsylvania does not require operators to identify or test nearby 
water wells, but state law incentivizes operators to do so by 
establishing a rebuttable presumption that operators are liable for 
changes in water quality of certain wells after drilling. 

[B] Oil and gas well sites are only required to get 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, 
rather than prior to commencing construction or causing discharges. 

[C] Generally, federal environmental laws do not have drilling, 
cementing, or casing requirements related to drilling production 
wells. However, according to EPA officials, if the well is to be 
hydraulically fractured with diesel fuel, it is subject to regulation 
as a Class II well under the SDWA UIC program and may be subject to 
cementing and casing, as well as plugging, requirements. In May 2012, 
EPA published draft guidance on how its UIC permit writers should 
address hydraulic fracturing with diesel in the context of the Class 
II UIC program. To date, however, EPA officials are unaware of any 
wells that were regulated in this way. 

[D] Under TSCA, to the extent a hydraulic fracturing fluid is a 
chemical substance or mixture, manufacturers (including importers), 
processors, and distributors of such fluids generally would be subject 
to applicable reporting requirements. Generally, well site operators 
would not be subject to any such applicable TSCA reporting 
requirements. 

[E] Disposal at a POTW is currently available in Pennsylvania and 
Ohio, as will be discussed later in this report. We are also aware 
that the city of Forth Worth, Texas had a pilot program within the 
last several years under which it accepted flowback for disposal 
through its POTW, but current information suggests that the city is no 
longer accepting flowback water. 

[F] The existing federal regulations under RCRA solid waste provisions 
apply to nonhazardous waste disposal facilities and practices, 
including those involving oil and gas wastes, and prohibit open 
dumping of solid waste. However, EPA has a limited role in the 
enforcement of RCRA solid waste provisions. 

[G] Per EPA's 1988 regulatory determination, oil and gas exploration 
and production wastes--including certain field operations--are not 
regulated as hazardous. Small amounts of hazardous waste may be at 
well sites (such as discarded, unused hydraulic fracturing fluids) but 
we could not identify any instances where these wastes were available 
in high enough quantities to trigger RCRA requirements. 

[End of table] 

Siting and Site Preparation: 

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.[Footnote 72] 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.[Footnote 73] 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.[Footnote 74] 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.[Footnote 75] 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. 

Drilling, Casing, and Cementing: 

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.[Footnote 76] 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. 

Hydraulic Fracturing: 

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.[Footnote 77] 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. 

Table 5: Chemical Disclosure Requirements in Six Selected States: 

Requirements: Reporting mechanism; 
Colorado: FracFocus website; 
North Dakota: FracFocus website; 
Ohio: State website, FracFocus website, or other state approved method; 
Pennsylvania: FracFocus website; 
Texas: FracFocus website; state website if FracFocus is unavailable; 
Wyoming: State agency. 

Requirements: Timing of disclosure requirement; 
Colorado: Information must be disclosed within 60 days following 
completion of hydraulic fracturing and not later than 120 days after 
the commencement of hydraulic fracturing; 
North Dakota: No timing requirement specified; 
Ohio: Information must be disclosed within 60 days after the 
completion of drilling or after a determination that a well is a dry 
or lost hole; 
Pennsylvania: Information must be disclosed within 60 days following 
the conclusion of hydraulic fracturing; 
Texas: Information must be disclosed within 30 days after completion 
of the well or within 90 days after drilling is completed, whichever 
is earlier; 
Wyoming: Information must be disclosed before hydraulic fracturing and 
within 30 days of completion. 

Requirements: Protections for confidential information or trade 
secrets; 
Colorado: Yes; 
North Dakota: None identified[A]; 
Ohio: Yes; 
Pennsylvania: Yes; 
Texas: Yes; 
Wyoming: Yes. 

Requirements: Provisions to challenge trade secrets; 
Colorado: None identified[A]; 
North Dakota: None identified[A]; 
Ohio: Yes; 
Pennsylvania: None identified[A]; 
Texas: Yes; 
Wyoming: Yes. 

Requirements: Provisions for disclosure to health professionals; 
Colorado: Yes; 
North Dakota: None identified[A]; 
Ohio: Yes; 
Pennsylvania: Yes; 
Texas: Yes; 
Wyoming: None identified[A]. 

Requirements: Provisions for disclosure to emergency responders; 
Colorado: Yes; 
North Dakota: None identified[A]; 
Ohio: Yes; 
Pennsylvania: Yes; 
Texas: Yes; 
Wyoming: None identified[A]. 

Sources: GAO analysis of state requirements. 

[A] We reviewed only those requirements specifically related to 
hydraulic fracturing disclosures. General state requirements related 
to the protection of confidential business information and protection 
of trade secrets may apply. 

[End of table] 

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.[Footnote 78] 

For more details about state hydraulic fracturing requirements, see 
appendix IX. 

Well Plugging: 

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. 

Site Reclamation: 

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;[Footnote 79] 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. 

Waste Management and Disposal: 

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.[Footnote 80] 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. 

[Side bar: Underground Injection and Earthquakes: 

From March 2011 to January 2012, 12 earthquakes ranging in magnitude 
from 2.1 to 4.0 occurred near Youngstown, Ohio. In March 2012, the 
Ohio Department of Natural Resources reported that "there is a 
compelling argument" that injection of produced water into nearby 
Class II UIC wells was the cause of the earthquakes. The Ohio 
Department of Natural Resources then placed a moratorium on injection 
into five Youngstown area UIC wells and began examining its Class II 
UIC well permitting process and developing a series of rule changes to 
help address seismic activity concerns. In July 2012, the Governor of 
Ohio signed an executive order determining that an emergency exists 
requiring the immediate adoption of the rule changes The National 
Academy of Sciences released a study in June 2012 that concluded 
underground injection does pose some risk for induced seismicity, but 
that very few events have been documented over the past several 
decades relative to the large number of disposal wells in operation. 
The study noted that the injected fluid volume, rate, pressure, and 
proximity to existing faults and fractures are factors that determine 
the probability to create a seismic event, but effective and economic 
tools are not currently available to accurately predict induced 
seismicity prior to injection. The study made research 
recommendations, proposed actions to address induced seismicity, and 
suggested that the agency that issues UIC well permits is the most 
appropriate agency to oversee decisions made with respect to induced 
seismic events. End of side bar] 

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;[Footnote 81] 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.[Footnote 82] 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.[Footnote 83] 
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. 
[Footnote 84] 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.[Footnote 85] 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.[Footnote 86] 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. 
[Footnote 87] 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.[Footnote 88] 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. 

Managing Air Emissions: 

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. 

Regional Commission Implements Additional Requirements: 

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. 
[Footnote 89] 

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. 

States Have Recently Updated Some Requirements: 

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.[Footnote 90] 
State regulators are also considering additional regulatory changes in 
response to the remaining recommendations of the Governor's Marcellus 
Shale Advisory Board. 

Additional Requirements Apply on Federal Lands: 

Federal land management agencies, including the Bureau of Land 
Management (BLM), Forest Service, National Park Service, and Fish and 
Wildlife Service (FWS) manage federal lands for a variety of purposes. 
Specifically, both the Forest Service and BLM manage their lands for 
multiple uses, including oil and gas development; recreation; and 
provision of a sustained yield of renewable resources, such as timber, 
fish and wildlife, and forage for livestock. By contrast, the Park 
Service manages its lands to conserve the scenery, natural and 
historical objects, and wildlife so they remain unimpaired for the 
enjoyment of present and future generations. Similarly, FWS manages 
national wildlife refuges for the benefit of current and future 
generations, seeking to conserve and, where appropriate, restore fish, 
wildlife, plant resources, and their habitats. 

Each of these agencies imposes additional requirements for oil and gas 
development on its lands to meet its obligations with respect to its 
mission. These additional federal requirements are the same for 
conventional and unconventional oil and gas development. In some 
cases, the surface rights to a piece of land and the right to extract 
oil and gas--called mineral rights--are owned by different parties. 
For example, private mineral rights might underlie lands where the 
surface is managed by a federal agency. Requirements for developing 
mineral rights vary based on whether the mineral rights are owned by 
the federal government or by a private entity. 

Requirements for Federally Owned Mineral Rights: 

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. 

Planning and Leasing Processes: 

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.[Footnote 91] Altogether, BLM oversees oil and gas 
development on approximately 700 million subsurface acres. 

A first step in developing federal oil and gas resources is a planning 
phase, involving BLM and (for lands managed by the Forest Service) the 
Forest Service, to identify areas for potential leasing. Under the 
National Environmental Policy Act (NEPA), federal agencies are 
required to prepare a detailed statement on the environmental impacts 
of any "major federal action," if it would significantly affect the 
environment.[Footnote 92] Regulations implementing NEPA generally 
require an agency to prepare either an environmental assessment or 
environmental impact statement.[Footnote 93] 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. 

Table 6: Surface Agency Roles in Leasing and Permitting Federal 
Minerals: 

Surface land management agency: BLM; 
Availability for oil and gas development: Generally available[A]; 
Role in approving leases: BLM is primary authority for approving 
leases; 
Role in approving drilling permits: BLM is primary authority for 
approving drilling permits. 

Surface land management agency: Forest Service; 
Availability for oil and gas development: Generally available[B]; 
Role in approving leases: Coordinates with BLM regarding surface 
issues and must authorize the lease; 
Role in approving drilling permits: Forest Service must approve all 
surface disturbing activities before BLM approves the drilling permit. 

Surface land management agency: Private Landowner; 
Availability for oil and gas development: Generally available; 
Role in approving leases: No specific role; 
may participate in public comment process; 
Role in approving drilling permits: Operator generally must reach 
agreement with surface landowner regarding surface disturbances. 

Source: GAO. 

[A] Some lands managed by BLM are unavailable for leasing because they 
have been withdrawn from leasing through congressional action or by 
agency regulation or, according to BLM officials, because they are 
being managed for other uses. 

[B] Some lands managed by the Forest Service are unavailable for 
leasing because they have been withdrawn through congressional action 
or by agency regulation. For example, the Wyoming Range (1.2 million 
acres) in western Wyoming and the Valle Vidal (100,000 acres) in New 
Mexico are both unavailable for leasing. In addition, 58.5 million 
acres of Inventoried Roadless Areas are indirectly unavailable in that 
construction or reconstruction of roads is not allowed, essentially 
making these areas inaccessible, according to Forest Service officials. 

[End of table] 

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. 

Requirements Related to Oil and Gas Development Activities: 

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 usable 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.[Footnote 94] 

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. 

Requirements for Privately Owned Mineral Rights under Federal Surface 
Lands: 

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.[Footnote 95] 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.[Footnote 96] 

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.[Footnote 97] 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. 

Regarding lands managed by FWS, we reported in August 2003 that 
oversight and management of oil and gas activities varies widely among 
wildlife refuges.[Footnote 98] We noted that some refuges issue 
permits that establish operating conditions for oil and gas 
activities, which give these refuges greater control over oil and gas 
activities and protect refuge resources; other refuges exercise little 
control or enforcement over oil and gas activities. According to FWS 
officials, this situation persists today, 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.[Footnote 99] For example, FWS worked with EPA to 
respond to a spill of produced water into a stream on a National 
Wildlife Refuge in Louisiana in 2005, in violation of CWA. EPA, the 
Coast Guard, and the Department of Justice worked together on the 
case, and the operator ultimately paid $425,000 to FWS for the two 
affected wildlife refuges. According to agency officials, however, 
without specific regulations, FWS faces challenges conducting daily 
management and oversight of oil and gas activities on FWS lands. 

The Park Service's 9B regulations govern potential impacts to all park 
system resources and values resulting from exercise of private oil and 
gas rights within Park Service administered lands. These regulations 
require an operator to submit a proposed plan of operations to the 
Park Service, which outlines the activities that are proposed for Park 
Service lands, including drilling, production, transportation, and 
reclamation. The regulations also outline certain requirements for 
operators, including that operations be located at least 500 feet from 
surface waters, that fences be used to protect people and wildlife, 
and that during reclamation the operator reestablish native 
vegetation. The Park Service analyzes the operator's proposed plan of 
operations to ensure that the proposed plan complies with the 9B 
regulations. Also, in determining whether it can approve an operation, 
the Park Service undertakes an environmental analysis under NEPA. Once 
the Park Service approves the proposed plan of operations, the 
operator can begin drilling. The Park Service continues to have access 
to the site for monitoring and enforcement purposes. In November 2009, 
the Park Service issued an Advance Notice of Proposed Rulemaking to 
update its 9B regulations; a proposed rule is expected in September 
2013, according to agency officials. 

Federal and State Agencies Reported Several Challenges Regulating 
Unconventional Oil and Gas Development: 

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. 

Conducting Inspection and Enforcement Activities: 

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.[Footnote 100] 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. 

In addition, EPA officials said that they do not always have 
information on the types of activities taking place or equipment being 
used at oil and gas well sites, making it difficult to know where to 
conduct inspections related to SDWA, CWA, and CAA. For example, 
regarding SDWA, EPA headquarters officials said that, though EPA's 
guidance document on this topic is not yet finalized, EPA requires 
operators conducting hydraulic fracturing operations with diesel fuel 
to apply for a Class II UIC permit.[Footnote 101] However, it is 
difficult for EPA to assess operators' compliance because 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.[Footnote 102] 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. 

Limited Legal Authorities: 

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.[Footnote 103] 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.[Footnote 104] 

Hiring and Retaining Staff: 

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.[Footnote 105] 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. 
[Footnote 106] 

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. 

Public Education: 

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. 

Agency Comments and Our Evaluation: 

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 
[hyperlink, 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. 

Signed by: 

David C. Trimble: 
Director: 
Natural Resources and Environment: 

List of Requesters: 

The Honorable Barbara Boxer:
Chairman:
Committee on Environment and Public Works:
United States Senate: 

The Honorable Sheldon Whitehouse:
Chairman:
Subcommittee on Oversight:
Committee on Environment and Public Works:
United States Senate: 

The Honorable Benjamin L. Cardin:
Chairman:
Subcommittee on Water and Wildlife:
Committee on Environment and Public Works:
United States Senate: 

The Honorable Henry A. Waxman:
Ranking Member:
Committee on Energy and Commerce:
House of Representatives: 

The Honorable Edward J. Markey:
Ranking Member:
Committee on Natural Resources:
House of Representatives: 

The Honorable Diana DeGette:
Ranking Member:
Subcommittee on Oversight and Investigations:
Committee on Energy and Commerce:
House of Representatives: 

The Honorable Robert P. Casey, Jr.
United States Senate: 

[End of section] 

Appendix I: Objectives, Scope, and Methodology: 

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. 

Table 7: Agencies and Organizations Contacted: 

Federal agencies: 

* EPA Office of Air and Radiation; 
* EPA Office of Chemical Safety and Pollution Prevention; 
* EPA Office of Enforcement and Compliance Assurance; 
* EPA Office of General Counsel; 
* EPA Office of the Inspector General; 
* EPA Office of Solid Waste and Emergency Response; 
* EPA Office of Research and Development; 
* EPA Office of Water; 
* EPA Region 3 (includes Pennsylvania); 
* EPA Region 5 (includes Ohio); 
* EPA Region 6 (includes Texas); 
* EPA Region 8 (includes Colorado, North Dakota, and Wyoming); 
* Bureau of Land Management (BLM) headquarters; 
* BLM Colorado State Office; 
* BLM Dickinson, North Dakota Field Office; 
* BLM Wyoming State Office; 
* Fish and Wildlife Service; 
* Forest Service; 
* National Park Service. 

State and regional agencies: 

* Colorado Oil and Gas Conservation Commission; 
* Colorado Department of Public Health and Environment; 
* Air Pollution Control Division; 
* Hazardous Materials and Waste Management Division; 
* Water Quality Control Division; 
* Delaware River Basin Commission; 
* Ground Water Protection Council; 
* North Dakota Industrial Commission, Oil and Gas Division; 
* North Dakota Department of Health, Environmental Health Section; 
* Air Quality Division; 
* Waste Management Division; 
* Municipal Facilities Division; 
* Ohio Department of Natural Resources, Division of Oil and Gas 
Resources Management; 
* Ohio Environmental Protection Agency; 
* Division of Air Pollution Control; 
* Division of Drinking and Ground Waters; 
* Division of Materials and Waste Management; 
* Division of Surface Water; 
* Pennsylvania Department of Environmental Protection, Office of Oil 
and Gas Management; 
* Railroad Commission of Texas, Oil and Gas Division; 
* Texas Commission on Environmental Quality; 
* Office of Air; 
* Office of Compliance and Enforcement; 
* Office of Legal Services; 
* Office of the Executive Director; 
* Wyoming Oil and Gas Conservation Commission; 
* Wyoming Department of Environmental Quality; 
* Air Quality Division; 
* Water Quality Division; 
* Solid and Hazardous Waste Division. 

Environmental organizations: 

* Dakota Resource Council; 
* Earthjustice; 
* Earthworks, Oil and Gas Accountability Project; 
* Pennsylvania Environmental Council. 

Public Health organizations: 

* American Lung Association; 
* Association of State and Territorial Health Officials; 
* Council of State and Territorial Epidemiologists; 
* National Association of County and City Health Officials; 
* Southwest Pennsylvania Environmental Health Project; 
* Trust for America's Health. 

Companies and industry organizations: 

* American Petroleum Institute; 
* Chesapeake Energy Corporation; 
* EOG Resources, Inc.; 
* Independent Petroleum Association of America; 
* North Dakota Petroleum Council. 

Source: GAO. 

[End of table] 

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.[Footnote 107] 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. 

[End of section] 

Appendix II: Key Requirements and Authorities under the Safe Drinking 
Water Act: 

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.[Footnote 108] 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. 

Underground Injection Control Program: 

SDWA also regulates the placement of wastewater and other fluids 
underground through the Underground Injection Control (UIC) 
program.[Footnote 109] 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.[Footnote 110] 

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.[Footnote 
111] In particular, the regulations establish that the criterion that 
an aquifer "cannot now and 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.[Footnote 112] 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.[Footnote 113] 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.[Footnote 114] 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.[Footnote 115] 

The EPA Administrator may approve by rule a state to have primary 
enforcement responsibility for the UIC program.[Footnote 116] A state 
with an approved program assumes responsibility for implementing the 
program, including 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. 
[Footnote 117] 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.[Footnote 118] The Environmental Appeals Board denied 
all other claims against EPA.[Footnote 119] 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. 

Class II UIC Requirements: 

Under SDWA, UIC programs are to prohibit underground injection, other 
than into a well that is authorized by rule or permitted.[Footnote 
120] Class II UIC wells must meet requirements contained in either EPA 
regulations,[Footnote 121] or relevant state regulations. Federal 
regulations for Class II wells include construction, operating, 
monitoring and testing, reporting, and closure requirements.[Footnote 
122] 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.[Footnote 123] 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.[Footnote 124] 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. 
[Footnote 125] 

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.[Footnote 126] In addition 
there is a general 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.[Footnote 127] 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.[Footnote 128] 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.[Footnote 129] Officials said that if a 
seismic event occurs along a fault 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. 

For additional information on the Class II UIC requirements applicable 
under EPA's program in Pennsylvania, see appendix IX. 

Class II UIC Programs and Hydraulic Fracturing: 

Historically, UIC programs did not include hydraulic fracturing 
injections as among those subject to their requirements.[Footnote 130] 
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.[Footnote 131] 
Subsequently, Alabama revised its program to include injection of 
hydraulic fracturing fluids,[Footnote 132] and EPA approved it 
pursuant to SDWA section 1425 in 2000.[Footnote 133] 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.[Footnote 134] Alabama amended its 
regulations in 2001 and 2003.[Footnote 135] 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.[Footnote 136] 

EPA initiated a study in 2000 to further examine the issue of 
fracturing in coalbed methane in areas of underground sources of 
drinking water.[Footnote 137] 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. 
[Footnote 138] 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.[Footnote 139] 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.[Footnote 140] 

The Eleventh Circuit court decision on the Alabama program generated 
significant controversy regarding whether hydraulic fracturing would 
be included in UIC programs nationwide. In this context, the Energy 
Policy Act of 2005[Footnote 141] amended SDWA to include a provision 
exempting certain hydraulic fracturing injections from the UIC 
program. Specifically, the Energy Policy Act provided that "[t]he 
underground injection of fluids or propping agents (other than diesel 
fuels) pursuant to hydraulic fracturing operations related to oil, 
gas, or geothermal production activities" is excluded from the 
definition of "underground injection." Hence, injection of 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. 
[Footnote 142] 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. 
[Footnote 143] 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. 

Enforcement: 

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.[Footnote 144] 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.[Footnote 145] 

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.[Footnote 146] 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. 
[Footnote 147] 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.[Footnote 148] 

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.[Footnote 
149] 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.[Footnote 150] 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. 

Imminent and Substantial Endangerment Authorities: 

While SDWA generally does not directly regulate land use activities 
that may pose risk to drinking water supplies,[Footnote 151] 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, [where] appropriate State and local authorities 
have not acted to protect the health of such persons."[Footnote 152] 
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.[Footnote 153] 

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 facilities.[Footnote 154] EPA subsequently filed a 
complaint in U.S. District Court seeking injunctive relief to enforce 
the order's requirements and civil penalties for the operator's 
noncompliance with the order.[Footnote 155] 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.[Footnote 156] On March 29, 
2012, EPA withdrew its administrative order, and the parties moved for 
voluntary dismissal of both cases.[Footnote 157] In a letter to EPA, 
the operator agreed to conduct sampling of 20 private water wells for 
1 year.[Footnote 158] 

[End of section] 

Appendix III: Key Requirements and Authorities under the Clean Water 
Act: 

Under the Clean Water Act (CWA),[Footnote 159] 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.[Footnote 160] 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.[Footnote 161] 

Under CWA section 311 and the Oil Pollution Act,[Footnote 162] EPA 
regulations 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.[Footnote 163] These 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. 

National Pollutant Discharge Elimination System Program: 

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[Footnote 164] 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.[Footnote 165] 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.[Footnote 166] 
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,[Footnote 167] and some produced water is discharged to 
surface water in certain geographical areas.[Footnote 168] 

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. 
[Footnote 169] 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).[Footnote 170] 

Existing Effluent Limitations Guidelines for Oil and Gas Extraction: 

EPA has developed effluent limitations guidelines for several 
subcategories of the oil and gas extraction industry.[Footnote 171] 
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.[Footnote 172] 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. 
[Footnote 173] The guidelines for these subcategories were finalized 
in 1979.[Footnote 174] 

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.[Footnote 175] 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.[Footnote 176] 

Existing effluent limitations guidelines do not apply to wastewater 
discharges from coalbed methane extraction.[Footnote 177] 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.[Footnote 178] 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 
judgment[Footnote 179] and any applicable 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. 

Table 8: Summary of Effluent Limitations Guidelines for Wastewater 
Discharges from Selected Subcategories of Oil and Gas Wells Located on 
Land: 

Wells included in an existing segment subcategory: 

Subcategory of oil or gas well: Onshore wells that do not fit into any 
of the other subcategories; 
Covered by existing effluent limitations guideline: Wells included in 
an existing segment subcategory: Yes - direct dischargers; 
No - indirect dischargers (no pretreatment requirements established); 
Permit requirement: No discharge. 

Subcategory of oil or gas well: Agricultural and Wildlife Water Use 
subcategory; 
Covered by existing effluent limitations guideline: Wells included in 
an existing segment subcategory: Yes; 
Permit requirement: Discharge of produced water allowed where 
conditions met, and subject to max daily limit for oil and grease. 

Subcategory of oil or gas well: Stripper wells; 
Covered by existing effluent limitations guideline: Wells included in 
an existing segment subcategory: Subcategory created, but no effluent 
limitations or pretreatment requirements established; 
Permit requirement: Case-by-case. 

Wells that are not included in any existing segment subcategory: 

Subcategory of oil or gas well: Coalbed methane extraction wells; 
Covered by existing effluent limitations guideline: Wells included in 
an existing segment subcategory: No; 
Permit requirement: Case-by-case. 

Source: GAO analysis of federal regulations. 

Note: EPA proposed pretreatment standards for oil and grease for new 
sources in the four subcategories in 1979, but did not issue them. 
Compare 41 Fed. Reg. 44,949, 44,952 (Oct. 13, 1976), 44 Fed. Reg. 
22,069 (Apr. 13, 1979) and 76 Fed. Reg. 66,286, 66,295 (Oct. 26, 2011). 

[End of table] 

Onshore Subcategory: 

The effluent limitations guideline for the Oil and Gas Extraction 
point source category, onshore subcategory establishes the best 
practicable control technology currently available as: 

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).[Footnote 180] 

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.[Footnote 
181] 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. 

Agricultural and Wildlife Water Use Subcategory: 

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 "it 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."[Footnote 182] 

For this subcategory, the guideline establishes the best practicable 
control technology currently available as: 

"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.[Footnote 183] 

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 "good enough" for this use,[Footnote 184] and must not 
exceed the daily maximum for 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.[Footnote 185] 
EPA is responsible for oversight and has not issued guidance on this 
topic. 

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. 

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

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.[Footnote 186] 

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.[Footnote 
187] EPA's 2010 coalbed methane study 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.[Footnote 188] 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.[Footnote 189] 
According to EPA officials, most coalbed methane wastewater discharges 
have NPDES permits. 

Following the study, EPA concluded that some of the waters discharged 
to surface waters have high total dissolved solids, and that there are 
readily available technologies to treat this produced water and 
decided to initiate rulemaking.[Footnote 190] EPA is in the 
preproposal stage of rulemaking for the coalbed methane effluent 
guidelines and standards.[Footnote 191] EPA's website indicates the 
projected date for publication of the proposed rule is June 2013. 

Generally Applicable Pretreatment Standards and POTW Obligations: 

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. 

General standards: 

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.[Footnote 
192] Notably, such discharges are subject to a general requirement 
that the pollutants do not cause pass through or interference with the 
POTW.[Footnote 193] 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.[Footnote 194] 

Other standard provisions for indirect discharges involve a 
prohibition on corrosive discharges.[Footnote 195] 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.[Footnote 196] 

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 life.[Footnote 197] Specifically, if a POTW did not include 
information in its NPDES 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.[Footnote 198] 

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.[Footnote 199] 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. 

POTW Obligations: 

Generally, local governments operating POTWs are responsible for 
ensuring that indirect dischargers comply with any applicable national 
pretreatment standards.[Footnote 200] 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.[Footnote 201] 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.[Footnote 202] 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.[Footnote 203] 

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. 
[Footnote 204] The 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.[Footnote 205] 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.[Footnote 206] Specifically, 
EPA plans to issue two guidance documents, one for permit writers and 
another for POTWs. 

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

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.[Footnote 207] 

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.[Footnote 208] Further, EPA 
stated that resulting discharges have 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.[Footnote 209] EPA intends to conduct a survey, among other 
things, to collect information on management of produced water to 
support the rulemaking.[Footnote 210] 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.[Footnote 211] For example, the state of 
Pennsylvania requested that 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. 

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. 

NPDES for Stormwater Discharges: 

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.[Footnote 212] 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. 
[Footnote 213] EPA subsequently issued regulations that address 
stormwater discharges from several source categories, including 
certain industrial activities and construction activities.[Footnote 
214] 

Stormwater from Industrial Activities: 

Generally, industrial sites obtain coverage for stormwater through a 
general permit, such as the multisector general permit or construction 
general permit.[Footnote 215] To do so, the facility operator submits 
a notice of intent, and 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.[Footnote 216] 

In providing EPA authority to regulate stormwater discharges, the 
Water Quality Act also prohibited EPA from requiring a NPDES permit 
for discharges of stormwater from: 

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, 
[Footnote 217] raw material, intermediate products, finished product, 
byproduct, or waste products located on the site of such operations. 
[Footnote 218] 

Interpreting the provision exempting oil and gas facilities, EPA 
issued regulations requiring permits for contaminated stormwater from 
oil and gas facilities.[Footnote 219] 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.[Footnote 220] 

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,[Footnote 221] including 
Texas, and identified some stormwater general permit notifications for 
facilities that could be well sites.[Footnote 222] 

Stormwater from Construction Activity: 

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.[Footnote 223] 
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.[Footnote 
224] 

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,"[Footnote 225] 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."[Footnote 226] 

In response to these amendments, in 2006, EPA revised a key provision 
of the regulations concerning oil and gas stormwater discharges. 
[Footnote 227] 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.[Footnote 228] 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.[Footnote 229] EPA officials said the agency intends to 
revise its regulations to address the court's vacatur in an upcoming 
stormwater rulemaking,[Footnote 230] 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. 

NPDES Enforcement: 

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. 
[Footnote 231] Among other things, EPA can take such actions if a well 
operator violates the CWA prohibition on unauthorized discharges of 
pollutants to surface waters.[Footnote 232] 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.[Footnote 233] For example, EPA has authority to inspect 
facilities where an effluent source is located.[Footnote 234] 

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.[Footnote 235] 
In another case, EPA 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.[Footnote 236] The produced 
water traveled 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. 

Imminent and Substantial Endangerment Authorities: 

CWA section 504 provides EPA an imminent and substantial endangerment 
authority, authorizing EPA to bring suit to restrain a person to stop 
the discharge of pollutants causing or contributing to pollution, or 
to 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.[Footnote 237] Unlike the 
analogous provisions of several other major environmental laws, 
however, CWA section 504 does not expressly mention administrative 
orders. 

Oil and Hazardous Substances Spill Prevention, Reporting, and Response: 

Spill Prevention and Response Plans: 

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.[Footnote 238] 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.[Footnote 239] 
Onshore oil and gas 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 quantities of oil into or upon 
U.S. navigable waters or adjoining shorelines.[Footnote 240] 

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.[Footnote 241] 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.[Footnote 242] Oil production 
facilities are exempt from the SPCC security provisions.[Footnote 243] 

EPA has amended the SPCC regulations from time to time. In 2008, EPA 
amended the regulations to streamline certain requirements, to be 
effective in January 2010.[Footnote 244] These amendments included 
several provisions easing requirements for oil production sites, such 
as excluding them from loading/unloading rack requirements, providing 
alternative qualified facility eligibility criteria (for streamlined 
compliance with self-certification of SPCC plans), and exempting 
certain produced water containers.[Footnote 245] In November 2009, EPA 
revised the amendments, eliminating these three provisions before they 
became effective.[Footnote 246] EPA explained that, in consideration 
of relevant facts and public comments, there was either no basis for 
the exclusion or the exclusion will not effectively protect the 
environment from discharges. For example, with respect to the 
alternative qualified facility criteria provision, EPA stated that the 
agency: 

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 
[is] 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.[Footnote 
247] 

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. 

EPA has developed guidance related to SPCC applicability and 
compliance for oil production, drilling, and workovers.[Footnote 248] 
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.[Footnote 249] EPA's 
regulations do not 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.[Footnote 250] 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.[Footnote 251] 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). 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.[Footnote 252] 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,[Footnote 253] 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. 
[Footnote 254] 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.[Footnote 255] 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. 
[Footnote 256] The plan is to provide, in essence, an emergency 
response action plan for the worst-case discharge and other relevant 
information.[Footnote 257] 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. 

Spill Prohibition and Reporting: 

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.[Footnote 258] Relevant 
provisions require reporting of certain discharges of oil or a 
hazardous substance to these waters.[Footnote 259] 

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.[Footnote 260] 

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.[Footnote 261] 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.[Footnote 262] The National Response 
Center subsequently sends reports to EPA Regions and headquarters. 
With respect to oil, discharges of oil must be reported if they "cause 
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. [Footnote 263] 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.[Footnote 264] 

Spill Response Authority: 

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.[Footnote 265] 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.[Footnote 
266] For example, according to 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. 

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. 
[Footnote 267] 

Enforcement of SPCC and Spill Prohibition and Reporting Requirements: 

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. 
[Footnote 268] Section 311 also gives EPA the authority to access 
records and inspect facilities, and the ability to require provision 
of information, with respect to persons and facilities subject to 
section 311, including SPCC program requirements.[Footnote 269] 

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.[Footnote 
270] This 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, 99 sites with violations of SPCC 
requirements were identified.[Footnote 271] EPA's report stated that 
"non-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."[Footnote 272] 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.[Footnote 273] Region 8 reported 
identifying 22 sites with documented SPCC violations as a result of 
subsequent efforts in 2004-2005.[Footnote 274] Information on the 
nature or resolution of these violations was not readily available. 

Imminent and Substantial Endangerment Authority for Spills: 

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.[Footnote 275] 

[End of section] 

Appendix IV: Key Requirements and Authorities under the Clean Air Act: 

The Clean Air Act (CAA or the Act) is the primary law with the purpose 
to protect and enhance the nation's air quality.[Footnote 276] Under 
CAA, EPA regulates two primary types of air pollutants: criteria 
pollutants and hazardous air pollutants (HAPs). EPA sets, and 
periodically may revise, National Ambient Air Quality Standards for 
six criteria pollutants--carbon monoxide, sulfur dioxide, lead, 
nitrogen dioxide, particulate matter, and ozone.[Footnote 277] States 
then develop state implementation plans (SIP) and seek EPA approval; 
if a SIP is not acceptable, EPA may assume primary responsibility for 
implementing and enforcing CAA in that state.[Footnote 278] In 
addition, EPA retains CAA implementation and enforcement oversight 
authority in states with approved SIPs. The SIPs generally establish 
how the state will attain air quality standards, through regulation, 
permits, policies, and other means. SIPs also must demonstrate that 
the state program satisfies certain minimum federal statutory and 
regulatory requirements. EPA also establishes various federal air 
emission regulations addressing criteria pollutants or HAPs, and which 
generally fall into two categories of emission sources: stationary 
sources and mobile sources. Stationary sources of air pollution are 
generally any building, structure, facility, or installation that may 
emit any air pollutant.[Footnote 279] With respect to oil and gas 
production as a stationary source, EPA has identified various 
components of oil and gas production that may be relevant to emissions: 

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.[Footnote 280] 

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.[Footnote 281] 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.[Footnote 282] 

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.[Footnote 283] 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.[Footnote 284] 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.[Footnote 285] Each of these key 
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.[Footnote 286] 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. 

Table 9: Summary of CAA Programs That May Apply to Emissions from Oil 
and Gas Well Sites: 

CAA program: National Emission Standards for Hazardous Air Pollutants 
(NESHAP); 
Specific rule for oil and gas production sector, applicable to well 
sites? Yes, addressing glycol dehydrators and storage vessels with 
potential for flash emissions at major sources and only triethylene 
glycol dehydrators at area sources[A]; 
Likely applicability to emissions at oil and gas well sites: Data not 
available regarding the extent to which well sites comprise major or 
area sources subject to the NESHAP, but the NESHAPs may apply at few 
well sites. 

CAA program: New Source Performance Standards (NSPS); 
Specific rule for oil and gas production sector, applicable to well 
sites? Yes, addressing gas well completions, pneumatic controllers, 
and some storage vessels; 
Likely applicability to emissions at oil and gas well sites: Gas wells 
that are fractured are subject to flaring and phased-in green 
completion requirements, focused on VOC reductions, under April 2012 
rule. (Oil wells that are fractured are not subject to NSPS); 
Data not available on how many pneumatic controllers are at wells (in 
total, 13,500 subject to rule). Data not available on how many storage 
vessels over threshold of 6 tons per year of VOC are at wells. In 
total, EPA estimates that 304 new source storage vessels will be 
subject to the rule annually and that most of these storage vessels 
are expected to be at wells. 

CAA program: New Source Review (NSR); 
Specific rule for oil and gas production sector, applicable to well 
sites? No (generally applicable); 
Likely applicability to emissions at oil and gas well sites: Unknown; 
most likely is nonattainment NSR in severe areas, which have lowest 
threshold potential to emit. Programs are generally implemented by 
states and features vary. 

CAA program: Title V Operating Permits; 
Specific rule for oil and gas production sector, applicable to well 
sites? No. The oil and gas NESHAP and NSPS specifically exempt area or 
nonmajor sources subject to these rules from Title V permitting 
requirements if they are not otherwise required by law to obtain such 
permits; 
Likely applicability to emissions at oil and gas well sites: Unknown. 

CAA program: Accidental Releases: Risk Management Program; 
Specific rule for oil and gas production sector, applicable to well 
sites? No (generally applicable); 
Likely applicability to emissions at oil and gas well sites: Unlikely; 
regulated substances in oil and gas that meet the definition of 
"naturally occurring hydrocarbon mixture" are not counted toward 
threshold quantities of regulated substances; extent to which other 
regulated substances are present in threshold quantities at well sites 
not known. 

CAA program: Accidental Releases: General Duty Clause; 
Specific rule for oil and gas production sector, applicable to well 
sites? No (generally applicable); 
Likely applicability to emissions at oil and gas well sites: Applies; 
no threshold; EPA has used provision to conduct inspections and 
require control of leaks. 

CAA program: Greenhouse Gas Reporting; 
Specific rule for oil and gas production sector, applicable to well 
sites?: Yes; 
Likely applicability to emissions at oil and gas well sites: Applies 
with threshold at the basin-level, EPA estimates that certain 
emissions from approximately 467,000 onshore wells will be covered. 

Source: GAO. 

[A] With respect to dehydrators, the major source standards apply to 
large glycol dehydrators--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 per year. The area source standards apply to 
triethylene glycol dehydration units with natural gas flow rate at or 
above 3 million standard cubic feet per day and benzene emission at or 
above 1 ton per year. 

[End of table] 

National Emission Standards for Hazardous Air Pollutants: 

Hazardous Air Pollutants: 

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.[Footnote 287] The list of HAPs 
includes several potentially found in oil and gas well emissions. 
[Footnote 288] 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. 
[Footnote 289] 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.[Footnote 290] The prevention of 
accidental releases regulation includes accidental releases of 
hydrogen sulfide.[Footnote 291] 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.[Footnote 292] 

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 
sulfide as a HAP under section 112(b).[Footnote 293] The petitioners 
asserted that low-level hydrogen sulfide emissions not addressed by 
the accidental release provisions in section 112(r) are harmful to 
human health.[Footnote 294] EPA officials told us they are considering 
the petition but have no specific timeline for acting upon it. 

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

EPA is required to promulgate and periodically revise NESHAPs for 
source categories the agency has identified.[Footnote 295] NESHAPs may 
include standards for major sources and for area sources, which are 
any sources not major.[Footnote 296] 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.[Footnote 297] 

Major sources for NESHAPs are those that emit or have the potential to 
emit considering controls, in the aggregate, 10 tons per year or more 
of a single hazardous air pollutant or 25 tons per year or more of any 
combination of HAPs.[Footnote 298] 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.[Footnote 299] 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). 
[Footnote 300] 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. 
[Footnote 301] 

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. 
[Footnote 302] EPA has defined "associated equipment" in the 
regulations.[Footnote 303] 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. 

NESHAPs for Oil and Natural Gas Production Facilities: 

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.[Footnote 304] In April 2012, EPA promulgated amendments to the 
NESHAPs for major sources.[Footnote 305] 

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. 
[Footnote 306] 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. 
[Footnote 307] 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.[Footnote 308] EPA documents do not indicate the 
extent to which these exemptions have the effect of canceling MACT 
requirements that would otherwise apply to oil and gas wells from 
unconventional deposits. 

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.[Footnote 309] 

The 1999 NESHAP for major sources has included the following emission 
points that may be present at oil and gas wells: process vents on 
large glycol dehydration units and storage vessels with potential for 
flash emissions.[Footnote 310] The standard requires reduction in HAPs 
emissions from large glycol dehydration units and storage vessels with 
potential for flash emissions through the application of air emission 
control equipment or pollution prevention measures, or a combination 
of both.[Footnote 311] The standards require that all process vents on 
new and existing large glycol dehydration units that are located at 
major HAPs sources be controlled.[Footnote 312] Glycol dehydration 
units subject to control must reduce emissions by 95 percent or more 
of HAPs, or to a benzene emission level less than 0.9 megagram (1 ton) 
per year.[Footnote 313] For existing and new storage vessels with the 
potential for flash emissions, the standard is to be equipped with a 
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.[Footnote 314] 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 NESHAP 
major source rule: small glycol dehydrators.[Footnote 315] These 
sources 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.[Footnote 316] Existing dehydrators 
have 3 years to comply, while new dehydrators must comply upon start-
up.[Footnote 317] 

EPA had proposed another source to add to the NESHAPs: storage vessels 
without the potential for flash emissions, which are not regulated 
under the current rule. EPA did not include these sources in its final 
rule, stating that "the agency determined that it needs additional 
data in order to establish emission standards for this type of storage 
vessel."[Footnote 318] In the proposed rule, EPA relied upon its 
original analysis of storage vessels that was used to determine the 
MACT standard in 1999, based on 1997 data.[Footnote 319] Commenters 
criticized EPA's use of the 1999 analysis as outdated and not 
reflecting current technology in use for the vessels without potential 
for flash emissions and asserted that reliance on the old analysis 
failed to meet EPA's statutory obligations.[Footnote 320] EPA stated 
"in response to such comments, we have re-evaluated the proposed MACT 
standards and concluded that we need (and intend to gather) additional 
data on these sources in order to analyze and establish MACT emission 
standards for this subcategory of storage vessels."[Footnote 321] 

In addition, the April 2012 amendments changed a key definition in the 
NESHAPs for determining major source status.[Footnote 322] The effect 
of this 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. 

Area Sources: 

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.[Footnote 323] 

In 2007, EPA issued a NESHAP for oil and gas production facilities--
which may include wells--that are area sources.[Footnote 324] The area 
source rule regulations address emissions from one type of emission 
source at oil and gas production facilities: triethylene glycol 
dehydration units above specified throughput and benzene emission 
thresholds, which are the same thresholds as those used to define 
large dehydration units in the major source rule.[Footnote 325] For 
area sources within defined control areas (areas of higher population 
density),[Footnote 326] add-on controls or equivalent pollution 
prevention measures are required to achieve reduction of HAPs 
emissions by 95 percent, or alternately, to below the specified 
emission limit for benzene.[Footnote 327] For area sources outside of 
these control areas, an operational standard is required instead of an 
add-on control.[Footnote 328] 

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.[Footnote 329] 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.[Footnote 330] 

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. 

Other NESHAPs: 

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.[Footnote 331] 

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).[Footnote 332] 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.[Footnote 333] 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 
subject to standards for stationary engines.[Footnote 334] EPA did not 
have available 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. 

New Source Performance Standards: 

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.[Footnote 335] These rules 
are implemented by EPA or by states through delegation.[Footnote 336] 
For the oil and gas production industry, the NSPS primarily regulates 
VOCs (as an ozone precursor). 

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.[Footnote 337] EPA 
has recently promulgated such standards for some production emissions, 
notably completion and recompletion of certain hydraulically fractured 
gas wells.[Footnote 338] In addition, some other generally applicable 
standards for certain equipment may apply at oil and gas well sites. 

April 2012 Amendments to NSPS: 

In April 2012, EPA promulgated amendments to the NSPS for the Oil and 
Gas sector, including new standards applicable to the production 
source category.[Footnote 339] 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.[Footnote 340] Following publication of the new 
rules in August 2012, an industry group petitioned EPA to reconsider 
certain aspects of the new rules.[Footnote 341] 

The new standards include, for the first time, standards to reduce 
emissions from certain activities at natural gas wells.[Footnote 342] 
In particular, the new standards establish operational standards 
applicable to selected 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.[Footnote 343] 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. 

Table 10: NSPS for Natural Gas Wells, by Well Subcategory: 

Natural gas well subcategory: Provisions[B]; 
Completion date: [Empty]; 
Green completions (routing gas to the flow line): 40 C.F.R. § 
60.5375(a)(1)-(2); 
Combustion of flowback emissions: 40 C.F.R. § 60.5375(a)(3); 
Duty to minimize releases to the air (flowback and recovery): 40 
C.F.R. § 60.5375(a)(4); 
Well logs, compliance demonstration, records and reporting: 40 C.F.R. 
§ 60.5375(b)-(e). 

Natural gas well subcategory: New wells constructed after Aug. 23, 
2011; 
Completion date: Completions with hydraulic fracturing before Jan. 1, 
2015; 
Green completions (routing gas to the flow line): [Empty]; 
Combustion of flowback emissions: [Check]; 
Duty to minimize releases to the air (flowback and recovery): [Check]; 
Well logs, compliance demonstration, records and reporting: [Check]. 

Natural gas well subcategory: Completions with hydraulic fracturing 
after Jan. 1, 2015; 
Green completions (routing gas to the flow line): [Check]; 
Combustion of flowback emissions: [Check] (only for emissions that 
cannot be directed to the flow line); 
Duty to minimize releases to the air (flowback and recovery): [Check]; 
Well logs, compliance demonstration, records and reporting: [Check]. 

Natural gas well subcategory: Wells existing as of Aug. 23, 2011; 
Completion date: Completions with hydraulic fracturing before Jan. 1, 
2015; 
Green completions (routing gas to the flow line): [Check]; 
Combustion of flowback emissions: [Check]; 
Duty to minimize releases to the air (flowback and recovery): [Check]; 
Well logs, compliance demonstration, records and reporting: [Check]. 

Natural gas well subcategory: Wells existing as of Aug. 23, 2011; 
Completion date: Completions with hydraulic fracturing after Jan. 1, 
2015; 
Green completions (routing gas to the flow line): [Check]; 
Combustion of flowback emissions: Natural gas well subcategory: 
[Check] (only for emissions that cannot be directed to the flow line); 
Duty to minimize releases to the air (flowback and recovery): [Check]; 
Well logs, compliance demonstration, records and reporting: [Check]. 

Natural gas well subcategory: Wells existing as of Aug. 23, 2011; 
Completion date: Alternative to avoid new source status before Jan. 1, 
2015[A]; 
Green completions (routing gas to the flow line): [Check]; 
Combustion of flowback emissions: [Check](only for emissions that 
cannot be directed to the flow line); 
Duty to minimize releases to the air (flowback and recovery): [Check]; 
Well logs, compliance demonstration, records and reporting: [Check]. 

Natural gas well subcategory: Wildcat and delineation wells; 
Completion date: [Empty]; 
Green completions (routing gas to the flow line): [Empty]; 
Combustion of flowback emissions: [Check]; 
Duty to minimize releases to the air (flowback and recovery): [Check]; 
Well logs, compliance demonstration, records and reporting: [Check]. 

Natural gas well subcategory: Other low pressure wells; 
Completion date: [Empty]; 
Green completions (routing gas to the flow line): [Empty]; 
Combustion of flowback emissions: [Check]; 
Duty to minimize releases to the air (flowback and recovery): [Check]; 
Well logs, compliance demonstration, records and reporting: [Check]. 

Source: GAO analysis of EPA documents. 

[A] Existing wells (constructed before Aug. 23, 2011) that are 
completed after fracturing can avoid being within the definition of a 
"modified" source by voluntarily implementing the green completion 
provisions. According to EPA, this would allow the owners/operators to 
avoid state permit requirements in some states. See EPA, Summary of 
Requirements for Processes and Equipment at Natural Gas Well Sites 
(April 2012). 

[B] Provisions listed are to code sections; see 77 Fed. Reg. at 49,543-
54. 

[End of table] 

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.[Footnote 344] 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.[Footnote 345] 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.[Footnote 346] 

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.[Footnote 347] 

Other NSPS: 

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).[Footnote 348] 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.[Footnote 349] EPA officials said that, 
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.[Footnote 350] EPA 
officials said, however, that typical activity at well sites is not 
enough to trigger thresholds for coverage under this rule, either. 

New Source Review: 

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.[Footnote 351] However, NSR only applies if 
the construction project results in actual emissions or the potential 
to emit regulated air contaminants[Footnote 352] 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.[Footnote 353] 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.[Footnote 354] 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,[Footnote 355] 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.[Footnote 356] 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.[Footnote 357] 
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.[Footnote 358] 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. 

Title V Operating Permits: 

Relevant to oil and gas production, CAA generally requires Title V 
permits for the operation of: 

* any major source[Footnote 359] 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 
others; and: 

* any source required to obtain a PSD or NSR permit.[Footnote 360] 

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,[Footnote 361] 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.[Footnote 362] 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.[Footnote 363] 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. 

Source Determinations and Aggregation Issues for Title V and NSR: 

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,[Footnote 364] and are 
located on contiguous or adjacent properties.[Footnote 365] 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.[Footnote 366] 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.[Footnote 367] 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. 
[Footnote 368] For example, in 2007, EPA provided guidance on how to 
evaluate aggregation in source determinations for the oil and gas 
industry.[Footnote 369] 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.[Footnote 370] 

Aggregation of oil and gas facilities--including wells--has also been 
the subject of litigation. For example, a gas production company 
challenged EPA's determination that its gas wells, sweetening plant, 
and associated flares constitute a single source for purposes of Title 
V permitting, in the United States Court of Appeals for the Sixth 
Circuit.[Footnote 371] In a recently issued decision, the court 
vacated and remanded EPA's determination, finding that EPA improperly 
considered the functional interrelatedness of the sweetening plant and 
the wells in determining that those points were adjacent under the 
regulations. Another example of a challenge relates to a citizen 
petition filed in EPA Region 8.[Footnote 372] The state of Colorado 
issued a Title V permit renewal to Anadarko's Frederick Compressor 
Station for a natural gas processing station but did not aggregate the 
station with natural gas wells for purposes of Title V and also did 
not include a requirement of PSD because the emission threshold was 
not met without aggregation. A citizen group subsequently filed a 
Title V petition with EPA, seeking an objection to the permit because 
natural gas wells were not aggregated with the processing station. 
After EPA issued a Title V order finding that the petition had not 
demonstrated that aggregation was required, the citizen group 
challenged the EPA decision in the United States Court of Appeals for 
the Tenth Circuit.[Footnote 373] In another matter, EPA Region 8 
issued a Title V permit to BP America Production Company's Florida 
River Compression Station Facility and decided not to aggregate oil 
and gas activities with the compressor station in determining the 
source. A citizen group appealed this decision to the Environmental 
Appeals Board.[Footnote 374] 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.[Footnote 375] 

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. 

Greenhouse Gas Reporting Rule: 

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.[Footnote 376] 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.[Footnote 377] 

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.[Footnote 378] 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.[Footnote 379] 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.[Footnote 380] 

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[Footnote 381] 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.[Footnote 382] 

Reporting is to begin in September 2012, for calendar year 2011. 
[Footnote 383] 

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). 
[Footnote 384] 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.[Footnote 385] 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,[Footnote 386] and EPA documents estimate that 
emissions from approximately 467,000 onshore wells are covered under 
the rule.[Footnote 387] 

Accidental Releases: 

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;[Footnote 388] 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. 
[Footnote 389] Among others, hydrogen sulfide is included on the list 
of regulated substances.[Footnote 390] Section 112(r) also established 
the Chemical Safety Board;[Footnote 391] 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.[Footnote 392] 

Accidental Release Prevention (Risk Management Program): 

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.[Footnote 393] 

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.[Footnote 394] As amended, the following 
chemicals that may be found at oil and gas sites are excluded from 
threshold determinations: 

* 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),[Footnote 395] 

* regulated substances in gasoline, when in distribution or related 
storage for use as fuel for internal combustion engines,[Footnote 396] 
and: 

* a flammable substance when the substance is used as a fuel.[Footnote 
397] 

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 unlisted chemical extremely hazardous.[Footnote 398] 
In addition, EPA stated that, 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.[Footnote 399] 

Regarding flammable substances used as fuel, EPA had originally 
included chemicals on the flammable substances list based on the 
National Fire Protection Association flammability hazard rating, 
regardless of their use. After promulgating Risk Management Program 
regulations, EPA became aware that certain small commercial sources 
were subject to the requirements because they used propane or other 
fuels, so it initiated a rulemaking to create an exemption. In 
addition, a propane gas industry association had challenged the Risk 
Management 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.[Footnote 400] EPA then revised the 
regulation, adding the exemption to comply with the act.[Footnote 401] 

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."[Footnote 402] 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. 

General Duty to Prevent Accidental Releases: 

Section 112(r) also provides, in relevant part: 

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.[Footnote 403] 

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. 
[Footnote 404] 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.[Footnote 
405] 

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. 

Imminent and Substantial Endangerment Authority Respecting Accidental 
Releases: 

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. 
[Footnote 406] 

Chemical Safety Board: 

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.[Footnote 407] 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[Footnote 408] and from the risk management requirements of CAA, 
[Footnote 409] the Chemical Safety Board recommended that EPA 
encourage owners and operators to reduce these risks.[Footnote 410] 
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.[Footnote 
411] 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.[Footnote 412] The Chemical Safety Board also made related 
recommendations to several states and industry associations.[Footnote 
413] 

EPA Enforcement Authorities: 

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.[Footnote 414] 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.[Footnote 415] 

Imminent and Substantial Endangerment Authority: 

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.[Footnote 416] EPA must first consult 
with state and local authorities and attempt to confirm the accuracy 
of information before taking such actions. 

[End of section] 

Appendix V: Key Requirements and Authorities under the Resource 
Conservation and Recovery Act: 

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,[Footnote 417] and also including some provisions 
respecting solid waste.[Footnote 418] As to hazardous waste, EPA may 
authorize states to administer their own permitting programs in lieu 
of the federal program, as long as these state programs are equivalent 
to and consistent with the federal program and provide for adequate 
enforcement.[Footnote 419] 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.[Footnote 420] 

Subtitle C - Hazardous Waste: 

RCRA established federal requirements and EPA regulatory authority for 
"cradle-to-grave" management of hazardous wastes. RCRA defines 
hazardous waste as: 

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. 
[Footnote 421] 

EPA regulations implementing RCRA establish several means by which 
solid waste may be deemed hazardous for purposes of the Subtitle C 
regulations, including specifically being listed by EPA as a hazardous 
waste or by exhibiting one of the following four characteristics: 
toxicity, ignitability, corrosivity, or reactivity.[Footnote 422] 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. 
[Footnote 423] 

Exemption of Certain Oil and Gas Production Wastes from Regulation as 
Hazardous Waste under RCRA Subtitle C: 

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. 
[Footnote 424] 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."[Footnote 425] 
The study report was to "include appropriate findings and 
recommendations for Federal and non-Federal actions concerning such 
effects."[Footnote 426] 

The law further required EPA to either propose regulations for such 
wastes or determine that regulation was not warranted. Any such 
regulations would require congressional action to become effective: 

The 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. 
[Footnote 427] 

Pursuant to these provisions, EPA conducted the study and found that 
organic pollutants at levels of potential concern (levels that exceed 
100 times EPA's health-based standards) included the hydrocarbons 
benzene and phenanthrene. Inorganic constituents at levels of 
potential concern included lead, arsenic, barium, antimony, fluoride, 
and uranium. EPA then issued a determination that regulation of oil 
and gas exploration and production wastes under RCRA Subtitle C was 
not warranted.[Footnote 428] EPA focused on three key factors 
pertaining to these wastes: (1) the characteristics, management 
practices, and resulting impacts of these wastes on human health and 
the environment; (2) the adequacy of existing state and federal 
regulatory programs; and (3) the economic impacts of any additional 
regulatory controls on industry:[Footnote 429] 

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.[Footnote 430] 

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.[Footnote 431] 

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 
that might be needed.[Footnote 432] EPA further stated that it planned 
to revise its 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,"[Footnote 433] 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."[Footnote 
434] 

As far as implementing the three-pronged approach, according to a 2011 
EPA presentation, the agency developed Clean Water Act effluent 
guidelines for offshore and coastal oil and gas production, but EPA 
did not augment its RCRA Subtitle D regulations as planned, stating 
that it decided to work with the states instead.[Footnote 435] EPA's 
work with states featured audits that ultimately led to the State 
Review of Oil and Natural Gas Environmental Regulations (STRONGER) 
program.[Footnote 436] 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.[Footnote 437] The petition asserts that EPA can and 
should revisit 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. 

EPA officials told us the petition is currently under consideration 
and that the agency has not established a time frame for its decision. 
[Footnote 438] According to an EPA presentation, OSWER's Office of 
Resource Conservation and Recovery is currently (1) reviewing alleged 
incidents cited in the Natural Resources Defense Council petition; (2) 
compiling and reviewing state regulations in states with natural gas 
activities; and (3) reviewing best management practices for oil and 
gas exploration and production wastes developed by industry, federal, 
and state associations.[Footnote 439] EPA does not anticipate 
releasing any studies, surveys, or other documents in the interim 
period. EPA officials said that when EPA is finished examining the 
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). 

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

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; 

* painting wastes; 

* waste solvents; 

* 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; 

* laboratory wastes; 

* sanitary wastes; 

* pesticide wastes; 

* 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. 
[Footnote 440] 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. 
[Footnote 441] These facilities are subject to limits on the amount of 
hazardous waste they accumulate,[Footnote 442] as well as general 
requirements to determine which wastes are hazardous[Footnote 443] 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.[Footnote 444] 
Generally, conditionally exempt small quantity generators would not be 
required to have an EPA ID number.[Footnote 445] 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,[Footnote 446] and general requirements to determine 
which wastes are hazardous[Footnote 447] and to ensure that any 
hazardous wastes sent for off-site disposal are sent to RCRA-permitted 
or interim status facilities.[Footnote 448] In addition, the small 
quantity generators are required to have an EPA ID number and use 
manifests, by which hazardous waste may be tracked.[Footnote 449] 

For facilities, like oil and gas well sites, that may generate 
hazardous wastes but do not store, treat, or dispose of these wastes, 
no specific actions by EPA (or the authorized state) are required, 
beyond issuance of an EPA ID number to those facilities notifying EPA 
that it has generated hazardous waste in amounts making it a small or 
large quantity generator.[Footnote 450] EPA uses the notification 
information and EPA ID number to identify the universe of regulated 
waste generators and their specific regulated waste activities, for 
tracking, and for a variety of enforcement and inspection purposes. 
[Footnote 451] Generally, EPA (or the authorized state's) involvement 
at generator-only sites includes receiving notifications and issuing 
identification numbers, receiving biennial reports,[Footnote 452] 
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,[Footnote 453] 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.[Footnote 454] 

Subtitle D - Solid Waste: 

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.[Footnote 455] 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.[Footnote 456] A key part of EPA's limited regulatory 
role[Footnote 457] for solid waste was to establish criteria defining 
which solid waste disposal facilities and practices are "sanitary 
landfills" and those which constitute "open dumps,"[Footnote 458] 
where RCRA prohibited open dumping of solid waste.[Footnote 459] 

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 appendix IX for discussion of selected aspects of state 
waste management.) 

Enforcement: 

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.[Footnote 460] 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).[Footnote 461] 

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.[Footnote 462],[Footnote 
463] 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.[Footnote 
464] Section 3007 also establishes mandatory compliance inspections. 
[Footnote 465] 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."[Footnote 466] 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.[Footnote 467] 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.[Footnote 468] 

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.[Footnote 469] 

Imminent and Substantial Endangerment Authority: 

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. 
[Footnote 470] 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.[Footnote 471] 
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.[Footnote 472] 

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.[Footnote 473] EPA has interpreted 
the authority broadly, to allow a range of actions to be taken, 
including addressing the threat of endangerment.[Footnote 474] 
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.[Footnote 475] 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.[Footnote 476] 
According to the report, the orders required operators "to remove oil 
from pits, install effective exclusionary devices, and/or clean up 
sites."[Footnote 477] 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.[Footnote 478] 

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.[Footnote 479] 

[End of section] 

Appendix VI: Key Requirements and Authorities under the Comprehensive 
Environmental Response, Compensation, and Liability Act: 

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.[Footnote 
480] 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,[Footnote 481] as well as requiring 
reporting of hazardous substances releases above threshold quantities. 
[Footnote 482] 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.[Footnote 483] 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. 

Relevant Exclusions and Definitions: 

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.[Footnote 484] EPA can 
respond to releases of hazardous substances, however, even if there 
are colocated petroleum releases.[Footnote 485] 

CERCLA's liability and reporting provisions do not apply to federally 
permitted releases--generally, where a hazardous substance is released 
in compliance with a permit issued pursuant to certain federal 
environmental laws.[Footnote 486] The statutory definition for such 
federally permitted releases exempt from CERCLA liability and 
reporting also includes: 

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.[Footnote 487] 

However, EPA has explained, "[t]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.[Footnote 488] 

CERCLA Hazardous Substance Release Reporting: 

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.[Footnote 489] EPA 
regulations establish CERCLA hazardous substances and their reportable 
quantities.[Footnote 490] 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.[Footnote 491] 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. 

Relevant EPA Authorities: 

EPA established the Superfund program to carry out its 
responsibilities and authorities under CERCLA.[Footnote 492] Under the 
Superfund program, EPA implements its authorities to compel parties 
responsible[Footnote 493] 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.[Footnote 
494] 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. 
[Footnote 495] 

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.[Footnote 496] 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.[Footnote 497] 

* Information gathering and access. Under section 104(e), EPA has 
authority to obtain information as well as authorities to enter 
property and to conduct inspections and take samples.[Footnote 498] 
Specifically, EPA may 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. 
[Footnote 499] 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.[Footnote 500] EPA may 
obtain access by agreement, warrant, or administrative order.[Footnote 
501] 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.[Footnote 502] 

* 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.[Footnote 503] 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.[Footnote 504] 

* 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 
hazardous but that may harm public health or welfare;[Footnote 505] 
however, as 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.[Footnote 506] 

* 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.[Footnote 507] 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.[Footnote 508] 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.[Footnote 509] 

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.[Footnote 510] 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.[Footnote 511] 

More recently, EPA has used CERCLA authorities to conduct response 
activities, investigations, and to obtain records relating to alleged 
hazardous substance or pollutant or contaminant releases from oil and 
gas well sites. For example, EPA used CERCLA section 104(a) to 
undertake emergency removal actions including well sampling and 
provision of alternate water supplies at a site in Dimock, 
Pennsylvania.[Footnote 512] EPA is using CERCLA section 104(b) 
authority to conduct groundwater contamination investigations at 
Pavillion, Wyoming.[Footnote 513] EPA officials also 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.[Footnote 514] 

[End of section] 

Appendix VII: Key Requirements and Authorities under the Emergency 
Planning and Community Right-to-Know Act: 

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.[Footnote 515] 

Generally Applicable Chemical Information, Inventory, and Release 
Reporting: 

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.[Footnote 516] 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.[Footnote 517] The releases for which 
EPCRA requires reporting partially overlap with those for which the 
Comprehensive Environmental Response, Compensation, and Liability Act 
of 1980 (CERCLA)[Footnote 518] requires reporting.[Footnote 519] 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.[Footnote 
520] 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.[Footnote 521] 

Requirements under EPCRA That May Be Triggered at Well Sites: 

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.[Footnote 522] 
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.[Footnote 523] 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[Footnote 524] 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."[Footnote 525] 

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.[Footnote 526] 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.[Footnote 527] 

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; 

* silica; 

* shale control additives; 

* drilling mud and associated additives; 

* deflocculants; 

* 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: 

* produced hydrocarbons, 

* salt solutions, 

* weight materials, and: 

* fuels. 

Toxic Release Inventory: 

EPCRA also requires some facilities in listed industries to report to 
EPA their releases of listed toxic chemicals to the environment; 
[Footnote 528] 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.[Footnote 529] 

EPCRA further requires EPA to make this information available to the 
public,[Footnote 530] which the agency does electronically through the 
Toxics Release Inventory (TRI) database. The Pollution Prevention Act 
of 1990 requires covered facilities that report to the TRI to also 
provide certain information about their waste management practices, 
including amounts of covered chemicals recycled or treated.[Footnote 
531] The purposes of making this information available include to 
inform citizens about releases of toxic chemicals to the environment; 
to assist governmental agencies, researchers, and other persons in the 
conduct of research and data gathering; and to aid in the development 
of appropriate regulations, guidelines, and standards, and for other 
similar purposes.[Footnote 532] 

EPCRA section 313(b)(1) specifies that these requirements shall apply 
to owners and operators of facilities meeting three conditions: (1) 
having 10 or more full-time employees;[Footnote 533] (2) in certain 
Standard Industrial Classification codes; and (3) that manufactured, 
processed, or otherwise used a listed toxic chemical in excess of the 
reporting threshold during the calendar year. The law specified the 
Standard Industrial Classification codes subject to the reporting 
requirement. EPA has, from time to time, amended its regulations to 
reflect industry codes in use; first, providing a crosswalk from 
Standard Industrial Classification codes to the North American 
Industry Classification System (NAICS) codes, and subsequently to 
update as needed to reflect changes to the NAICS codes.[Footnote 534] 

EPCRA section 313(b)(1)(B) provides EPA with authority to add or 
delete industrial codes.[Footnote 535] EPA issued initial regulations 
to implement the TRI in 1988.[Footnote 536] 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.[Footnote 537] 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. 

EPA has since expanded the list of covered industries, but it has not 
included oil and gas extraction.[Footnote 538] According to EPA's 
Sector Notebook, the addition of the oil and gas extraction industry 
to regulation under EPCRA section 313 has been a long-term 
consideration.[Footnote 539] In 1997, pursuant to section 
313(b)(1)(B), EPA added seven industry groups[Footnote 540] to the 
list of industries required to report releases in a rulemaking known 
as the Industry Expansion Rule.[Footnote 541] Oil and gas exploration 
and production was among nine candidate industries considered in EPA's 
screening process. The preamble to the proposed Industry Expansion 
Rule stated in part: 

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.[Footnote 542] 

The preamble of the final rule stated in part, "[a] 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."[Footnote 543] 

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.[Footnote 544] 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.[Footnote 545] 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. 

EPCRA section 313 also specified the chemicals subject to the 
reporting requirement and provided a process and criteria for EPA to 
add or delete chemicals from the list.[Footnote 546] In the proposal 
to the 1997 Industry Expansion Rule discussed above, EPA stated that 
oil and gas extraction activities "may involve the management of 
significant quantities of EPCRA section 313 chemicals."[Footnote 547] 
In response to our request for background data regarding these 
chemicals and their quantities, EPA officials said they were unable to 
locate any record of the specific chemicals referred to in the 1996 
proposal as being managed in "significant quantities." However, 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.[Footnote 548] 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.[Footnote 549] 

Enforcement: 

EPCRA provides EPA with various authorities to enforce the act's 
requirements.[Footnote 550] 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.[Footnote 551] In cases of violations of section 304 release 
reporting requirements, EPA may assess administrative penalties, among 
other things.[Footnote 552] 

[End of section] 

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

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.[Footnote 553] 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.[Footnote 554] 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.[Footnote 555] Generally, TSCA's reporting 
requirements fall on the manufacturers (including importers), 
processors, and distributors of chemicals, rather than users of the 
chemicals.[Footnote 556] 

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[Footnote 557] list of "chemicals used most often" 
which are on the TSCA inventory.[Footnote 558] These examples, which 
EPA chose as representative of different product function categories, 
are as follows: 

* Hydrochloric acid - Acid; 

* Peroxydisulfuric acid, ammonium salt - Breaker; 

* Ethanaminium, 2-hydroxy-N,N,N-trimethyl-, chloride (1:1) - Clay 
Stabilizer; 

* 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.[Footnote 559] The petition asserts that more than 
10,000 gallons of such chemicals may be used to fracture a single 
well.[Footnote 560] 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. 
[Footnote 561] 

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 and safety studies.[Footnote 562] EPA granted the 
section 8(a) and 8(d) portions of 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. 
[Footnote 563] 

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.[Footnote 564] 
Regulations promulgated under TSCA section 8(d) are to require 
submission to EPA of reasonably ascertainable health and safety 
studies.[Footnote 565] 

TSCA provides EPA with certain enforcement authorities. For example, 
EPA may impose a civil penalty for certain violations of 
TSCA,[Footnote 566] such as failing to comply with requirements to 
notify and provide certain information to EPA before manufacturing a 
new chemical,[Footnote 567] 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.[Footnote 568] 

[End of section] 

Appendix IX: Selected State Requirements: 

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. 

Table 11: Primary State Agencies Responsible for Regulating Oil and 
Gas Development in Six States: 

State: Colorado; 
State regulatory agencies: Colorado Oil and Gas Conservation 
Commission; 
Colorado Department of Public Health and Environment. 

State: North Dakota; 
State regulatory agencies: 
North Dakota Industrial Commission, Oil and Gas Division; 
North Dakota Department of Health. 

State: Ohio; 
State regulatory agencies: 
Ohio Department of Natural Resources, Division of Oil and Gas Resource 
Management; 
Ohio Environmental Protection Agency. 

State: Pennsylvania; 
State regulatory agencies: 
Pennsylvania Department of Environmental Protection, Office of Oil and 
Gas Management. 

State: Texas; 
State regulatory agencies: 
Texas Railroad Commission, Oil and Gas Division; 
Texas Commission on Environmental Quality. 

State: Wyoming; 
State regulatory agencies: 
Wyoming Oil and Gas Conservation Commission; 
Wyoming Department of Environmental Quality. 

Source: GAO analysis of state information. 

[End of table] 

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.[Footnotes 569, 570, 571] 

Table 12: Selected State Requirements--Siting and Site Preparation: 

Identification or testing of water wells prior to drilling of 
production wells. 

Colorado: 
Identification or testing of water wells prior to drilling of 
production wells: Testing requirements apply in certain circumstances. 
Specifically: 
* Coalbed methane wells. If a conventional or plugged well exists 
within Ľ mile of a proposed coalbed methane well, the two closest 
water wells within a ˝ mile must be sampled, if accessible. Wells must 
be tested for all major cations and anions, total dissolved solids, 
iron, manganese, selenium, nitrates, and nitrites, dissolved methane, 
field pH, sodium adsorption ration, presence of bacteria (iron 
related, sulfate reducing, slime, and coliform), specific conductance, 
and hydrogen sulfide. If there are no conventional or plugged wells 
within Ľ mile, or if access is denied to such wells, then a water well 
within Ľ mile, or, failing that, within ˝ mile shall be selected. Post-
completion sampling must be performed for the same substances within 1 
year after completion of the well and repeated 3 and 6 years 
thereafter, or in accordance with field rules. The state may require 
further sampling at any time in response to complaints from well 
owners; 
* Wells in surface water supply areas.[A] For new operations in 
surface water supply areas, pre-and post-drilling surface water 
samples must be taken for a number of substances, including pH, total 
dissolved solids, benzene, toluene, ethylbenzene, xylenes and metals, 
from streams immediately downgradient from the location. Different 
requirements apply to operations at locations that were in existence 
prior to the Spring of 2009 depending on whether new surface 
disturbance occurs at the site, and how much. 2 Colo. Code Regs. § 404-
1(608, 317B) (2012). 

North Dakota: 
Identification or testing of water wells prior to drilling of 
production wells: There is no testing requirement, but if a domestic, 
livestock, or irrigation water supply with 1 mile of an oil or gas 
well site is disrupted or diminished in quality or quantity by 
drilling operations and a certified water quality and quantity test 
has been performed within 1 year prior to drilling, a person owning an 
interest in the property supplied by that water is entitled to recover 
from the operator the costs of repairs, alterations, or construction 
necessary to deliver water of the original quality and quantity. Prima 
facie evidence of injury under this section may be established by a 
showing that the mineral developer's drilling operations penetrated or 
disrupted an aquifer in such a manner as to cause a diminution in 
water quality or quantity within the distance limits imposed by this 
section. N.D. Cent. Code § 38-11.1-06 (2012). 

Ohio: 
Identification or testing of water wells prior to drilling of 
production wells: The well owner must sample all water wells within 
300 feet of proposed well locations in urbanized areas, and within 
1,500 feet of proposed horizontal wells in any area, prior to drilling 
under the guidelines provided in the division's best management 
practices for predrilling water sampling manual.[B] The chief may 
require modification of this distance if determined necessary to 
protect water supplies or site conditions may warrant. Ohio Rev. Code 
Ann. § 1509.06 (2012). 

Pennsylvania: 
Identification or testing of water wells prior to drilling of 
production wells: There is a rebuttable presumption that pollution 
occurring within 1000 feet and 6 months after completion of drilling 
or alteration of a conventional well and 2500 feet and 12 months after 
completion, drilling, stimulation or alteration, whichever is later, 
of an unconventional well was caused by the operator. Operators can 
defend against the presumption if they have predrilling tests showing 
that the problems predated drilling. The state does not specify 
substances for which wells must be tested. 25 Pa. Code § 78.51(2012); 
58 Pa. Cons. Stat. § 3218 (2012). 

Texas: 
Identification or testing of water wells prior to drilling of 
production wells: No requirements identified in regulations or in 
statutes. 

Wyoming: 
Identification or testing of water wells prior to drilling of 
production wells: An application for a permit to drill or deepen a 
well must identify all water supply wells permitted by the state 
within Ľ mile of the land unit within which the well is located, and 
the depth from which water is being appropriated. Owner/operators must 
also keep records on all formations penetrated and the content and 
quality of oil, gas, or water in each formation tested. 055-000-003 
Code Wyo. R. §§ 8, 20 (2012). 

Required setbacks from water sources: 

Colorado: 
Identification or testing of water wells prior to drilling of 
production wells: Special rules apply to new well sites depending on 
whether the site is located in one of three buffer zones surrounding 
surface water supply areas. Operations may not occur within the 
innermost buffer zone unless a variance is granted, the Department of 
Health and Environment is consulted, and appropriate conditions are 
placed on the operation. 2 Colo. Code Regs. § 404-1(317B) (2012). 

North Dakota: 
Identification or testing of water wells prior to drilling of 
production wells: Well sites and associated production facilities 
shall not be located in, or hazardously near, bodies of water or block 
natural drainages. N.D. Admin. Code 43-02-03-19 (2012). 

Ohio: 
Identification or testing of water wells prior to drilling of 
production wells: The location of a new well or a new tank battery of 
a well shall not be within 50 feet of a stream, river, watercourse, 
water well, pond, lake, or other body of water. However, the state may 
authorize a new well or tank battery to be located within 50 feet of 
such bodies of water if necessary to reduce impacts to the owner of 
the land or to protect public safety or the environment. Ohio Rev. 
Code Ann. § 1509.021 (2012). 

Pennsylvania: 
Identification or testing of water wells prior to drilling of 
production wells: Conventional wells may not be drilled within 200 
feet, and unconventional wells may not be drilled within 500 feet, of 
water wells without written owner consent. Unconventional wells may 
not be drilled within 1,000 feet of certain water supplies used by a 
water purveyor without written purveyor consent. If consent is not 
obtained, the operator may receive a variance if it cannot otherwise 
access its mineral rights and demonstrates that additional protective 
measures will be utilized. Conventional wells may not be drilled 
within 100 feet of certain other bodies of water, such as springs.[C] 
Unconventional wells may not be drilled within 300 feet of the same 
bodies of water and wetlands and the edge of the disturbed area 
associated with the well has to be at least 100 feet from the same 
water bodies and wetlands. 58 Pa. Cons. Stat. § 3215 (2012). 

Texas: 
Identification or testing of water wells prior to drilling of 
production wells: No requirements identified in regulations or in 
statutes. 

Wyoming: 
Identification or testing of water wells prior to drilling of 
production wells: Generally, pits, wellheads, pumping units, tanks, 
and treaters shall be no closer than 350 feet from water supplies. 055-
000-003 Code Wyo. R. § 22 (2012). 

Erosion control, site preparation, surface disturbance minimization, 
and stormwater management: 

Colorado: 
Identification or testing of water wells prior to drilling of 
production wells: 
* Erosion control, site preparation, surface disturbance minimization. 
Operators must separate excavated soil by horizon, store it separately 
and note locations to facilitate subsequent reclamation. On crop land, 
segregation must be to the shallower of 6 feet or bedrock. Elsewhere, 
operators must separate the topsoil horizon or the top 6 inches, 
whichever is deeper. If soil horizons are too rocky or thin to 
segregate, the topsoil shall be segregated and stored to the extent 
possible. Remaining soils on crop land shall be segregated down to the 
shallower of 3 feet or bedrock. Stockpiled soils shall be protected 
from contamination, compaction, and, as practicable, erosion. Best 
management practices to prevent weeds and maintain microbial activity 
shall be implemented. The drill pad shall minimize total disturbance 
consistent with safe operation and shall be on the most level location 
possible. If not avoidable, deep vertical cuts and steep long fill 
slopes shall be constructed to the least slope practical. Where 
feasible, directional drilling shall be used to reduce cumulative 
impacts and adverse impacts on wildlife. Well sites, production 
facilities, pipelines, and access roads shall be located, adequately 
sized, constructed, and maintained so as to reasonably control dust 
and minimize erosion, alteration of natural features, removal of 
surface materials, and degradation due to contamination. To the extent 
practicable, operators shall avoid or minimize impacts to wetlands and 
riparian habitats and shall consolidate facilities to minimize adverse 
impacts to wildlife resources, including fragmentation of wildlife 
habitat, as well as cumulative impacts. Existing roads shall be used 
to the greatest extent practicable to avoid erosion and minimize land 
disturbance. Roads shall be engineered to avoid or minimize impacts to 
riparian areas or wetlands. Unavoidable impacts shall be mitigated. 
Where feasible and practicable, road crossings of streams shall allow 
fish passage, operators are encouraged to share access roads in 
developing a field; roads shall be routed to complement other land 
usage, and vehicles shall not travel off-road; 
* Stormwater management. Operators must obtain a construction 
stormwater permit from the Department of Public Health and Environment 
and must develop a postconstruction stormwater program upon 
termination of the permit unless the site has a slope of less than 5% 
and has low erosion risk. All operators must implement and maintain 
site-specific best management practices to control stormwater runoff 
in a manner that minimizes erosion, transport of sediment off-site, 
and site degradation. Operators must select additional best management 
practices as part of their postconstruction stormwater program that 
address potential sources of pollution that may reasonably be expected 
to affect the quality of discharges associated with the ongoing 
operation of production facilities during the postconstruction and 
reclamation operation of the facilities. 2 Colo. Code Regs. § 404-
1(1002) (2012). 

North Dakota: 
Identification or testing of water wells prior to drilling of 
production wells: 
* Erosion control, site preparation, surface disturbance minimization. 
In the construction of a drill site, access road, and all associated 
facilities, the topsoil shall be removed, stockpiled, and stabilized 
or otherwise reserved for use when the area is reclaimed. "Topsoil" 
means the first 8 inches of suitable plant growth material on the 
surface. Soil stabilization and materials to be used on-site, as well 
as access roads or associated facilities must have approval from the 
director before application. When necessary to prevent pollution of 
the land surface and freshwaters, the director may require the drill 
site to be sloped and diked. N.D. Admin. Code 43-02-03-19 (2012); 
* Stormwater management. Oil and gas construction activity that 
disturbs 5 or more acres is authorized under the terms of a general 
permit covering stormwater discharge that requires the development of 
a stormwater management program and implementation of best management 
practices. 

Ohio: 
Identification or testing of water wells prior to drilling of 
production wells: 
* Erosion control, site preparation, surface disturbance minimization. 
Site construction shall comply with the state's best management 
practices for oil and gas well site construction manual.[B] Site 
clearing and surface effects shall be minimized. During any phase of 
operation in urbanized areas, to minimize off-site sedimentation, 
erosion and to control the surface flow of water, the well owner or 
his representative must also follow the best management practices for 
oil and gas well site construction manual. Best management practices 
and design standards other than those provided by the state may be 
used if the alternative minimizes erosion to the same degree as the 
state procedure. Ohio Admin. Code Ann. 1501:9-1-02, -07 (2012). 

Pennsylvania: 
Identification or testing of water wells prior to drilling of 
production wells: Operators proposing activities that will disturb 
5,000 square feet or more or that have the potential to discharge to a 
high-quality or exceptional value water must develop and implement a 
written erosion and sedimentation plan. Operators proposing oil and 
gas activities that involve 5 acres or more of earth disturbance shall 
obtain an Erosion and Sedimentation permit prior to commencing the 
earth disturbance activity. During and after earth moving or soil 
disturbing activities, the operator must design, implement, and 
maintain best management practices relating to erosion and sediment 
control and postconstruction stormwater management. An operator may 
not commence drilling activities until the state has inspected the 
unconventional well site after the installation of erosion and 
sediment control measures. 25 Pa. Code §§ 78.53, 102.4, 102.5 (2012); 
58 Pa.Cons.Stat. § 3258 (2012). 

Texas: 
Identification or testing of water wells prior to drilling of 
production wells: 
* Stormwater management. Where required by federal law, discharges of 
stormwater associated with industrial and construction activities 
associated with the exploration, development, or production of oil or 
gas must be authorized by the EPA and the state, as applicable. Under 
federal law, EPA cannot require a permit for discharges of storm water 
from "field activities or operations associated with oil and gas 
exploration, production, processing, or treatment operations, or 
transmission facilities" unless the discharge is contaminated by 
contact with any overburden, raw material, intermediate product, 
finished product, byproduct, or waste product located on the site of 
the facility. Under state regulations, the Texas Railroad Commission 
prohibits operators from causing or allowing pollution of surface or 
subsurface water. Operators are encouraged to implement and maintain 
best management practices to minimize discharges of pollutants, 
including sediment, in stormwater to help ensure protection of surface 
water quality during storm events. 16 Tex. Admin. Code § 3.30 (2012). 

Wyoming: 
Identification or testing of water wells prior to drilling of 
production wells: 
* Erosion control, site preparation, surface disturbance minimization. 
Where practical, topsoil must be stockpiled during construction for 
use in reclamation; 
* Stormwater management. A permit is required 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, which can be 
reviewed by the Wyoming Department of Environmental Quality. 055-000-
003 Code Wyo. R. §§ 7, 17; 055-000-004 Code Wyo. R. § 1; 020-080-002 
Code Wyo. R. § 6 (2012). 

Source: GAO analysis of state information. 

[A] Surface water supply areas are certain streams that are suitable 
for or could become sources of drinking water that are within 5 miles 
upstream of a surface water intake. 

[B] Best Management Practices for Pre-drilling Water Sampling Manual, 
available at [hyperlink, 
http://www.ohiodnr.com/oil/watersampling_bmp/tabid/23361/Default.aspx]. 
The manual requires testing for barium, calcium, iron, magnesium, 
potassium, sodium, chloride, conductivity, pH, sulfate, alkalinity, 
and total dissolved solids. 

[C] Specifically, no well site may be prepared or well drilled within 
100 feet from any solid blue lined stream, spring or body of water as 
identified on the most current 7 and one-half minute topographic 
quadrangle map of the United States Geological Survey. 

[End of table] 

Table 13: Selected State Requirements--Drilling, Casing, and Cementing: 

Requirements relating to cementing/casing plans: 

Colorado
The casing[A] program adopted for each well must be so planned and 
maintained as to protect any potential oil or gas bearing horizons 
penetrated during drilling from infiltration of injurious waters from 
other sources, and to prevent the migration of oil, gas, or water from 
one horizon to another, which may result in the degradation of 
groundwater. 2 Colo. Code Regs. § 404-1(317) (2012). 

North Dakota: 
The proposed casing program, including size and weight of casing, the 
depth at which each casing string[B] is to be set, the proposed pad 
layout including cut and fill diagrams, and the proposed amount of 
cement to be used, including the estimated top of cement, must be 
submitted with the application for permit to drill. N.D. Admin. Code 
43-02-03-16 (2012). 

Ohio[C]: 
A casing and cementing plan must be submitted as part of an 
application for permit to drill. The plan must show how the owner 
proposes to drill and construct the well with the best available 
geologic information in the vicinity of the proposed wellbore and with 
the requirements of state well construction rules. The plan must 
include, at least, the name and anticipated depth of all zones to be 
tested or produced; the estimated total depth of the wellbore; the 
anticipated diameter of each wellbore segment; the proposed casing 
type, outside diameter, and setting depth for each proposed casing 
string; proposed cement volumes for each casing string; and whether 
the owner plans to stimulate any permitted hydrocarbon zone by 
hydraulic fracturing. The casing and cementing plans in the approved 
permit are understood to be estimates based upon the best available 
geologic information prior to drilling. Ohio Admin. Code Ann. 1501:9-1-
02 (2012). 

Pennsylvania: 
The operator must prepare a casing and cementing plan showing how the 
well will be drilled and completed. Upon request, the operator must 
provide a copy of the plan to the state for approval. The plan must 
include information such as the anticipated depth and thickness of any 
producing formation; expected pressures; anticipated fresh groundwater 
zones and the method or information by which the depth of the deepest 
fresh groundwater was determined; 
casing type; whether the casing is new or used; depth, diameter, wall 
thickness and burst pressure rating; cement type, yield, additives and 
estimated amount; estimated location of centralizers; proposed 
borehole conditioning procedures; and any alternative methods or 
materials required by DEP as a condition of well permit. 25 Pa. Code § 
78.83a (2012). 

Texas: 
Texas rules do not require the development or approval of a casing 
plan unless an operator proposes an alternative method of freshwater 
protection than those prescribed by rule. 16 Tex. Admin. Code § 3.13 
(2012). 

Wyoming: 
An application for permit to drill must include the proposed casing 
program including size, anticipated setting depths, American Petroleum 
Institute grade, weight per foot, burst pressure, tensile strength for 
both body and joint, yield pressure, if new or used casing is planned 
for the well, and any other information required by the state. 055-000-
003 Code Wyo. R. § 8 (2012). 

Placement of surface casing relative to groundwater zones: 

Colorado: 
Where pressure and formations are unknown, surface casing[D] shall be 
run below all known or reasonably estimated utilizable domestic 
freshwater levels. Where subsurface conditions are known, surface 
casing shall be run to a depth sufficient to protect all freshwater. 
Where freshwater aquifers are so deep that it is 
impractical/uneconomical to set casing to the required depth, 
intermediate and/or production casing may be stage cemented to isolate 
the aquifers. 2 Colo. Code Regs. § 404-1(317) (2012). 

North Dakota: 
Casing must be properly cemented at sufficient depths to adequately 
protect and isolate all formations containing water, oil, or gas or 
any combination of these. The surface casing shall be set and cemented 
at a point not less than 50 feet below the base of the Fox Hills 
formation. N.D. Admin. Code 43-02-03-21 (2012). 

Ohio: 
An owner shall set and cement surface casing at least 50 feet below 
the base of the deepest underground source of drinking water (USDW), 
or at least 50 feet into competent bedrock, whichever is deeper and as 
specified by the permit, unless otherwise approved by the state. In 
areas where bedrock USDWs cannot be mapped and where groundwater 
resources can be developed in valley-fill aquifers, surface casing 
shall be cemented at least 100 feet below the base of the valley-fill 
aquifer for any well within 1,000 feet of the 100 year floodplain. In 
other areas where bedrock USDWs cannot be mapped, surface casing shall 
be set and cemented to at least 300 feet deep or at least 100 feet 
below the deepest local perennial stream base. As an alternative where 
bedrock USDWs cannot be mapped, surface casing shall be set to at 
least 50 feet below the base of the lowest spring or deepest water 
well within 500 feet or if there are no such springs or water wells, 
conductor casing shall be set and cemented to at least 100 feet. After 
conductor casing is set through the deepest usable water zone and 
cemented to surface, the owner must set and cement to surface a 
surface casing string through water zones that may include brackish or 
brine bearing zones. This casing string shall be set and cemented to 
surface before the owner drills into potential flow zones that can 
reasonably be expected to contain hydrocarbons in commercial 
quantities. Other alternative methods of protecting USDWs may be 
approved upon written application to the state. Ohio Admin. Code Ann. 
1501:9-1-08 (2012). 

Pennsylvania
Surface casing must be set to approximately 50 feet below deepest 
fresh groundwater or at least 50 feet into consolidated rock, 
whichever is deeper. Generally, surface casing may not be set more 
than 200 feet below the deepest fresh groundwater unless necessary to 
set casing in consolidated rock. Cement placed behind the surface 
casing must be set to a minimum designed strength of 350 pounds per 
square inch (psi) at the casing seat. The cement placed at the bottom 
300 feet of the surface casing must constitute a zone of critical 
cement and achieve a 72-hour compressive strength of 1,200 psi, and 
the free water separation may be no more than 6 milliliters of cement. 
If the surface casing is less than 300 feet, the entire cemented 
string constitutes a zone of critical cement. 25 Pa. Code §§ 78.83, 
.85 (2012). 

Texas: 
Surface casing must be set to protect all usable-quality water strata, 
as defined by the Texas Commission on Environmental Quality (TCEQ). 
Before drilling any well where no field rules are in effect or in 
which surface casing requirements are not specified in the applicable 
field rules, an operator shall obtain a letter from the TCEQ stating 
the protection depth. In no case, however, is surface casing to be set 
deeper than 200 feet below the specified depth without prior approval 
from the Texas Railroad Commission. 16 Tex. Admin. Code § 3.13 (2012). 

Wyoming: 
Surface casing shall be run below all known or reasonably estimated 
utilizable groundwater. Generally, surface casing shall be set at a 
minimum of 100 to 120 feet below the depth of any state permitted 
wells designated for domestic, stock water, irrigation, or municipal 
use within a minimum of 1/4 mile. A coalbed methane well with a 
groundwater appropriation permit is exempt from this requirement. 055-
000-003 Code Wyo. R. § 22 (2012). 

Prescribed cementation techniques for surface casing: 

Colorado: 
Pump and plug, displacement, or other approved method. 2 Colo. Code 
Regs. § 404-1(317) (2012). 

North Dakota: 
Pump and plug method or other state-approved method. N.D. Admin. Code 
43-02-03-21 (2012). 

Ohio: 
Sufficient cement shall be used to fill the annular space outside the 
casing from the seat to the ground surface or to the bottom of the 
cellar. If cement is not circulated to the ground surface or the 
bottom of the cellar, and the top of cement cannot be measured from 
surface, the owner shall notify the state and perform certain tests to 
determine the nature of the deficiency and shall obtain approval for 
additional cementing operations. Ohio Admin. Code Ann. 1501:9-1-08 
(2012). 

Pennsylvania: 
Operator shall permanently cement surface casing by placing cement in 
casing and displacing it into annular space between wall of hole and 
outside of casing. 25 Pa. Code § 78.83 (2012). 

Texas: 
Surface casing shall be cemented by the pump and plug method. The 
producing string of casing shall be cemented by the pump and plug 
method, or other commission-approved method. Alternative surface 
casing programs may be approved upon written application. 16 Tex. 
Admin. Code § 3.13 (2012). 

Wyoming: 
Pump and plug, displacement, or other approved method. 055-000-003 
Code Wyo. R. § 22 (2012). 

Requirement for cement waiting period and/or integrity tests: 

Colorado: 
Surface and intermediate casing cement must achieve a minimum 
compressive strength of 300 psi after 24 hours and 800 psi after 72 
hours measured at 95°F and 800 psi. Cement placed behind surface and 
intermediate casing shall be allowed to set a minimum of 8 hours, or 
until 300 psi calculated compressive strength is developed, whichever 
occurs first, prior to commencing drilling operations. Cement placed 
behind production casing shall achieve a minimum compressive strength 
of at least 300 psi after 24 hours and 800 psi after 72 hours measured 
at 95°F and 800 psi. Cement placed behind production casing shall be 
allowed to set 72 hours, or until 800 psi calculated compressive 
strength is developed, whichever occurs first, prior to any completion 
operation. Installed production casing shall be adequately pressure-
tested for the conditions anticipated to be encountered during 
completion and production. 2 Colo. Code Regs. § 404-1(317) (2012). 

North Dakota: 
All strings of surface casing shall stand cemented under pressure for 
at least 12 hours before drilling the plug or initiating tests. 
Surface casing strings must be allowed to stand under pressure until 
the tail cement has reached a compressive strength of at least 500 
psi. All filler cements must reach a compressive strength of at least 
250 psi within 24 hours and at least 350 psi within 72 hours. 
Compressive strength on surface casing cement shall be calculated at 
80° F. Production or intermediate casing strings must be allowed to 
stand under pressure until the tail cement has reached a compressive 
strength of at least 500 psi. All filler cements utilized must reach a 
compressive strength of at least 250 psi within 24 hours and at least 
500 psi within 72 hours, although in any horizontal well performing a 
single stage cement job from a measured depth of greater than 13,000 
feet, the filler cement utilized must reach a compressive strength of 
at least 250 psi within 48 hours and at least 500 psi within 96 hours. 
After cementing, each casing string shall be tested by application of 
pump pressure of at least 1,500 psi. If, at the end of 30 minutes, 
this pressure has dropped 150 psi or more, the casing shall be 
repaired and tested in the same manner again. Further work shall not 
proceed until a satisfactory test has been obtained. The casing in a 
horizontal well may be tested by use of a mechanical tool set near the 
casing shoe[E] after the horizontal section has been drilled. N.D. 
Admin. Code 43-02-03-21 (2012). 

Ohio: 
Cemented conductor, mine, and surface casing strings shall remain 
static until all cement has reached a compressive strength of at least 
500 psi before drilling the plug, or initiating a test. The tail 
cement for all intermediate and production casing and liners shall 
remain static until the cement has reached a compressive strength of 
at least 500 psi before drilling out the plug or initiating a test. 
Tail cement shall have a 72-hour compressive strength of at least 
1,200 psi. Lead cements with volume extenders may be used to seal 
these strings but in no case shall the cement have a compressive 
strength of less than 100 psi at the time of drill out nor less than 
250 psi 24 hours after being placed. Cement mixtures for which 
published performance data are not available shall be tested by the 
owner or service company and approved prior to usage. Tests shall be 
made on representative samples of the basic mixture of cement and 
additives used, using distilled water or potable tap water for 
preparing the slurry. The tests shall be conducted using the equipment 
and procedures established in the American Petroleum Institute 
publication "RP 10 B-2 Recommended Practice for Testing Well Cements." 
Test data showing competency of a proposed cement mixture to meet the 
above requirements shall be furnished to the inspector prior to the 
cementing operation. To determine that the minimum compressive 
strength has been obtained, the owner shall use the typical 
performance data for the particular cement mixture used in the well at 
the following temperatures and at atmospheric pressure: for conductor, 
mine string, and surface casing cement, the test temperature shall be 
60°F; for intermediate and production casing cement, the test 
temperature shall be within 10°F of the formation equilibrium 
temperature of the cemented interval. Ohio Admin. Code Ann. 1501:9-1-
08 (2012). 

Pennsylvania: 
After the casing cement is placed behind surface casing, the operator 
shall permit the cement to set to a minimum designed compressive 
strength of 350 psi at the casing seat. The cement placed at the 
bottom 300 feet of the surface casing must constitute a zone of 
critical cement and achieve a 72-hour compressive strength of 1,200 
psi ,and the free water separation may be no more than 6 milliliters 
per 250 milliliters of cement. After any casing cement is placed and 
cementing is complete, casing generally may not be disturbed for at 
least 8 hours by certain activities, such as running drill pipe or 
other mechanical devices into or out of the wellbore with the 
exception of certain equipment used to determine the top of the 
cement. 25 Pa. Code 78.85 (2012). 

Texas: 
When cementing any string of casing more than 200 feet long, before 
drilling the cement plug, the operator shall test the casing at a pump 
pressure in psi calculated by multiplying the length of the casing 
string by 0.2. The maximum test pressure required, however, unless 
otherwise ordered by the commission, need not exceed 1,500 psi. If, at 
the end of 30 minutes, the pressure shows a drop of 10% or more from 
the original test pressure, the casing shall be condemned until the 
leak is corrected. A pressure test demonstrating less than a 10% 
pressure drop after 30 minutes is proof that the condition has been 
corrected. Surface casing strings must be allowed to stand under 
pressure until the cement has reached a compressive strength of at 
least 500 psi in the zone of critical cement before drilling plug or 
initiating a test. The cement mixture in the zone of critical cement 
shall have a 72-hour compressive strength of at least 1,200 psi. 
Cement mixtures for which published performance data are not available 
must be tested by the operator or service company in accordance with 
the current API RP 10B.[F] Test data showing competency of a proposed 
cement mixture must be furnished to the commission prior to cementing. 
To determine that the minimum compressive strength has been obtained, 
operators shall use typical performance data for the cement in the 
well. 16 Tex. Admin. Code § 3.13 (2012). 

Wyoming: 
Unless otherwise provided by specific order of the Oil and Gas 
Conservation Commission for a particular well or wells or for a 
particular pool or parts thereof, cemented casing string shall stand 
under pressure until the cement at the shoe has reached a compressive 
strength of 500 psi. In addition, the American Petroleum Institute 
free-water separation for all cement slurries used shall average no 
more than 4 mL per 250 mL of cement. All cements used shall achieve a 
minimum compressive strength of 100 psi in 24 hours measured at 80 F. 
Testing for these properties shall be in accordance with accepted 
industry standards. 055-000-003 Code Wyo. R. § 22 (2012). 

Other measurement, record keeping, notification and/or inspection 
during cementing/casing process: 

Colorado: 
A cement bond log shall be run on all production casing or, in the 
case of a production liner, the intermediate casing when these strings 
are run. Open hole logs shall be run at depths that adequately verify 
the setting depth of surface casing and any aquifer coverage. 2 Colo. 
Code Regs. § 404-1(317) (2012). 

North Dakota: 
If the annular space behind casing is not adequately filled with 
cement, the state must be notified immediately. Any well that appears 
to have defective casing or cementing, the operator shall report the 
defect to the director. Prior to attempting remedial work on any 
casing, the operator must obtain approval from the director and 
proceed with diligence to conduct tests, as approved or required by 
the director, to properly evaluate the condition of the wellbore and 
correct the defect. N.D. Admin. Code 43-02-03-21, -22 (2012). 

Ohio: 
Generally, the state must receive 48 hours prior notice before the 
placement of surface casing. A 24 hours or less notification may be 
approved if prior communications have been initiated with state 
officials. The state must receive 24 hours notice prior to setting any 
casing or liner string and before commencing any casing cementing. 
Within 60 days after drilling to total depth, the owner shall file 
cement job logs with the state furnishing complete data documenting 
the cementing of all cemented casing strings. Each job log shall 
include the date cemented; the name of the cementing contractor; mix 
water temperature and pH; whether or not the wellbore circulated prior 
to cementing; certain measurements for the hole, casing, and other 
equipment; cement types, additives by percent of unit volume, volume 
of cement in stacks, cement yield per sack, average slurry density, 
slurry volume, and displacement volume; pumping rates, displacement 
pressure, and final circulating pressure prior to landing the plug; 
the time the latch-down or wiper plug landed; casing test pressure and 
final test pressure; whether or not cement circulated to surface; and 
volume of cement slurry circulated to the surface. Ohio Admin. Code 
Ann. 1501:9-1-02, 1501:9-1-08 (2012). 

Pennsylvania: 
Operator must notify state if cement used to cement surface casing is 
not circulated to the surface despite use of at least 120% of expected 
volume. Casing must undergo pressure testing, and the operator must 
notify the state at least 24 hours before conducting pressure testing 
on casing. The operator shall notify the state at least 1 day before 
cementing of the surface casing begins, unless the cementing 
operations begins within 72 hours of commencement of drilling. 
Unconventional well operators shall provide the state 24 hours notice 
prior to cementing all casing strings, conducting pressure tests of 
the production casing, stimulation, and abandoning or plugging an 
unconventional well. 25 Pa. Code §§ 78.83b, .84, .85 (2012); 
58 Pa.Cons.Stat. § 3211 (2012). 

Texas: 
Upon completion of the well, a cementing report must be filed with the 
commission furnishing complete data concerning the cementing of 
surface casing in the well. 16 Tex. Admin. Code § 3.13 (2012). 

Wyoming: 
The state may require a well owner or operator to provide bond logs if 
there is a demonstrated reason to believe an inadequate cement job was 
performed. A cement bond log or cement evaluation tool must be run to 
verify adequate cement around surface casing and to evaluate cement 
integrity in each cemented zone for each cemented casing annulus in 
wells within a geologic area known as the Special Sodium Drilling 
Area. 055-000-003 Code Wyo. R. § 22 (2012). 

Requirements related to horizontal drilling: 

Colorado: 
If an operator intends to drill a horizontal or deviated wellbore 
utilizing controlled directional drilling methods, other than 
whipstocking[G] due to hole conditions, the plans shall accompany an 
application for permit to drill. The plat shall show the surface and 
bottom hole location. If the surface location is in a different 
section than the bottom hole location, a plat depicting each section 
is required. Additionally, the proposed directional survey including 
two wellbore deviation plots, one depicting the plan view and one 
depicting the side view, shall accompany the application. Within 30 
days of completion, the operator shall submit a drilling completion 
report, with a copy of the directional survey coordinate listing and 
the wellbore deviation plots. The survey data shall be provided in a 
single analysis report with sufficient detail to determine the 
location of the wellbore from the base of the surface casing to the 
kick off point and from that point to total depth. Special spacing 
rules apply to horizontal wells in the Greater Wattenberg Area. 2 
Colo. Code Regs.§§ 404-1(321, 318A) (2012). 

North Dakota: 
A permit is required prior to drilling horizontally in an existing 
pool. A directional survey shall be made and filed with the director 
on any well utilizing a whipstock or any method of deviating the 
wellbore. Special permits may be obtained to drill directionally in a 
predetermined direction. If a request for a permit to directionally 
drill is denied, the director shall immediately tell the applicant 
why. The decision of the director may be appealed to the commission. 
Filler cement used to set production or intermediate casing in any 
horizontal well performing a single stage cement job from a measured 
depth of greater than 13,000 feet must reach a compressive strength of 
at least 250 psi within 48 hours and at least 500 psi within 96 hours. 
Casing in a horizontal well may be tested by use of a mechanical tool 
set near the casing shoe after the horizontal section has been 
drilled. N.D. Admin. Code 43-02-03-16, -21, -25 (2012). 

Ohio: 
The maximum point at which a well penetrates the producing formation 
shall not vary unreasonably from the vertical drawn from the center of 
the hole at the surface, with the exception of approved directional 
drilling. Such approval must be in writing from the chief. For wells 
drilled horizontally, in the Marcellus shale, or deeper, intermediate 
casing shall be set through the Mississippian Berea sandstone or to 
1,000 feet, whichever is greater, or as determined by the state. 
Production casing shall be cemented with sufficient cement to fill the 
annular space to a point at least 500 true vertical feet above the 
seat in an open-hole vertical completion or the uppermost perforation 
in a cemented vertical completion, or 1,000 feet above the kickoff 
point of a horizontal well. Liners may only be set and cemented as 
production casing in horizontal shale gas wells if approved by the 
chief. Ohio Admin. Code Ann. 1501:9-1-02, -08 (2012). 

Pennsylvania: 
No requirements identified in regulations or in statutes.[H]. 

Texas: 
A permit for directionally deviating a well may be granted for a 
variety of reasons, including where it can be shown to be advantageous 
from the standpoint of mechanical operation to drill more than one 
well from the same surface location to reach the productive horizon at 
essentially the same positions as would be reached if the several 
wells were drilled from locations prescribed by the well spacing 
rules. Applications for directional deviation must specify surface and 
projected bottom hole locations. 16 Tex. Admin. Code § 3.11 (2012).[I]. 

Wyoming: 
For directional wells, an application for permit to drill must include 
a diagram showing the proposed direction of the deviation and the 
proposed horizontal distance between hole bottom and surface location. 
For horizontal wells, an application for permit to drill must include 
a diagram showing the wellbore path from the surface through the 
terminus of the lateral. The surface location and the proposed footage 
locations of both the initial penetration into the productive 
formation and the terminus of the lateral shall be recorded. For an 
application to drill a horizontal well, notice shall be given to 
owners within 1/2 mile of any point on the length of the wellbore. In 
the absence of any special state order, notice is not required for 
horizontal wells in federally supervised units or in American 
Petroleum Institute units provided that no portion of the horizontal 
interval is closer than 660 feet from a drilling or spacing unit 
boundary or uncommitted tract. Before beginning controlled directional 
drilling, other than whipstocking because of hole conditions, notice 
shall be filed and approval obtained. Such notice shall state: the 
depth; exact surface location of the wellbore; proposed direction of 
deviation; and proposed horizontal distance between the bottom of the 
hole and surface location. A directional survey must be filed within 
30 days of completion. 055-000-003 Code Wyo. R. §§ 8, 25 (2012). 

Blowout preventer requirements: 

Colorado: 
Operators must take all necessary precautions for keeping a well under 
control while being drilled or deepened. Blowout preventer equipment 
is not generally required but must be used in high density areas or 
other areas specified by the state. In addition, the state may 
designate specific areas, fields or formations as requiring certain 
blowout prevention equipment. If used, blowout preventer equipment 
must be identified in the operator's application for permit to drill. 
The working pressure of any blowout preventer equipment shall exceed 
the anticipated surface pressure to which it may be subjected. 2 Colo. 
Code Regs. § 404-1(317, 603) (2012). 

North Dakota: 
In all drilling operations, proper and necessary precautions shall be 
taken for keeping the well under control, including the use of a 
blowout preventer and high pressure fittings attached to properly 
cemented casing strings adequate to withstand anticipated pressures. 
N.D. Admin. Code 43-02-03-23 (2012). . 

Ohio: 
Blowout preventer equipment is not generally required, but casing 
integrity may be verified in conjunction with blowout preventer 
testing without a test plug. Ohio Admin. Code Ann. 1501:9-1-08 (2012). 

Pennsylvania: 
Blowout preventers are required (1) when drilling into an 
unconventional formation,[J] (2) when drilling out solid core 
hydraulic fracturing plugs to complete a well, (3) when anticipated 
well head pressures or natural open flows may result in a loss of well 
control, (4) where there is no prior knowledge of the pressures or 
natural open flows, (5) on wells drilled to at least 3,800 feet and 
penetrating the Onondaga horizon, and (6) when drilling within 200 
feet of a building. The operator shall use pipe fittings, valves, and 
unions placed on or connected to the blowout prevention systems that 
have a working pressure capability that exceeds the anticipated 
pressures. All lines, valves, and fittings between the closing unit 
and the blowout preventer stack must be flame resistant and have a 
rated working pressure that meets or exceeds the requirements of the 
blowout preventer system. 25 Pa. Code § 78.72 (2012). 

Texas: 
Wellhead assemblies shall be used on wells to maintain surface control 
of the well. Each component of the wellhead shall have a pressure 
rating equal to or greater than the anticipated pressure to which that 
particular component might be exposed during the course of drilling, 
testing, or producing the well. A blowout preventer or control head 
and other connections to keep the well under control at all times 
shall be installed as soon as surface casing is set. The equipment 
shall be of such construction and capable of such operation as to 
satisfy any reasonable test that may be required by the commission or 
its duly accredited agent. 16 Tex. Admin. Code § 3.13 (2012). 

Wyoming: 
Blowout preventers and related equipment shall be installed and 
maintained during drilling in accordance with state rules unless 
changed upon hearing before the Oil and Gas Conservation Commission. 
Among other things, the requirements include that the working pressure 
rating of all blowout preventers and related equipment shall be based 
on known or anticipated subsurface pressure, geologic conditions, or 
accepted engineering practices, and shall equal or exceed the maximum 
anticipated pressure to be contained at the surface. In the absence of 
better data, the maximum anticipated surface pressure shall be 
determined by using a normal pressure gradient of 0.22 psi per foot 
and assuming a partially evacuated hole. 055-000-003 Code Wyo. R. § 23 
(2012). 

Source: GAO analysis of state information. 

[A] Casing is metal pipe used to line a well. 

[B] A string is a column made up of connected pipe. 

[C] In Ohio, the state may establish alternative well construction 
standards that are well-specific, field-specific, or play-specific by 
permit condition, to ensure protection of public health or safety or 
the environment. Ohio Admin. Code Ann. 1501:9-1-08(B) (2012). 

[D] Surface casing is cemented into bedrock and serves to shut out 
shallow water formations and as a foundation for well control during 
drilling. 

[E] A casing shoe is a cylinder or ring of hard steel with a cutting 
edge attached to the bottom of a string of well casing. 

[F] American Petroleum Institute, "API RP 10B-2 (R2010) Recommended 
Practice for Testing Well Cements." July 2005. 

[G] Whipstocking is a long wedge dropped into or placed in a well to 
deflect the drill to one side of some obstruction. 

[H] Pennsylvania requires operators to provide information about the 
vertical and horizontal paths of unconventional wells through its 
permitting process. 

[I] See also 16 Tex. Admin. Code § 3.86, relating to horizontal 
drainhole wells. 

[J] Pennsylvania law defines an unconventional formation as a 
geological shale formation existing below the base of the Elk 
Sandstone or its geologic equivalent stratigraphic interval where 
natural gas generally cannot be produced at economic flow rates or in 
economic volumes except by vertical or horizontal well bores 
stimulated by hydraulic fracture treatments or by using multilateral 
well bores or other techniques to expose more of the formation to the 
well bore. 58 Pa.Cons.Stat. § 2301 (2012). 

[End of table] 

Table 14: Selected State Requirements--Hydraulic Fracturing: 

Prior authorization/notice/inspection requirements: 

Colorado: 
Operators shall give at least 48 hours advance written notice to the 
Oil and Gas Conservation Commission of a hydraulic fracturing 
treatment at any well. The state must provide prompt electronic notice 
of such intention to the relevant local governmental designee. 2 Colo. 
Code Regs. § 404-1(316C) (2012). 

North Dakota: 
No requirements identified in regulations or in statutes. 

Ohio: 
The casing and cementing plan that must be submitted with an 
application for permit to drill must indicate whether the owner plans 
to stimulate any permitted hydrocarbon zone by hydraulic fracturing. 
The owner or the owner's representative must notify the state at least 
24 hours before commencing the stimulation of a well. Ohio Admin. Code 
Ann. 1501:9-1-02(A) (2012). Ohio Rev. Code Ann. § 1509.19 (2012). 

Pennsylvania: 
Operators must give 24 hours notice prior to well stimulation. 58 Pa. 
C.S. § 3211 (2012). 

Texas: 
No requirements identified in regulations or in statutes. 

Wyoming: 
An application for permit to drill must include a description of the 
anticipated stimulation program. An approved Application for Permit to 
Drill or Sundry Notice is required prior to the initiation of any well 
stimulation activity. 055-000-003 Code Wyo. R. §§ 8, 45 (2012). 

Requirements to disclose information on fracturing fluids: 

Colorado: 
Certain disclosures are required from vendors of hydraulic fracturing 
additives, companies that provide hydraulic fracturing services, and 
operators on whose wells hydraulic fracturing treatments are 
completed. Vendors and service providers must, with the exception of 
information claimed to be a trade secret, furnish to operators 
information on the total volume of water or the type and total volume 
of any other base fluid used in the hydraulic fracturing treatment; 
each hydraulic fracturing additive used in the hydraulic fracturing 
fluid along with its trade name, vendor, and a brief descriptor of its 
intended use; each chemical intentionally added to the base fluid, its 
maximum concentration, and its Chemical Abstracts Service (CAS) 
number, if applicable. Vendors and service providers must also provide 
any other information needed for operators to comply with operators' 
own disclosure requirements. Operators must post information to 
FracFocus, including: information on the makeup of hydraulic 
fracturing treatments as described above; operator name; date of 
hydraulic fracturing treatment; location and other identifying 
information for the well; and the true vertical depth of the well. If 
the specific identity of a chemical, its concentration, or both is/are 
claimed as a trade secret, the operator must so indicate on its 
submission to FracFocus and, as applicable, the vendor, service 
provider, or operator shall submit to the state a claim of entitlement 
to have the information withheld as a trade secret. Even if a chemical 
is claimed to be a trade secret, the operator must include in its 
submission the chemical family or other similar descriptor associated 
with such chemical. Information claimed to be a trade secret shall be 
provided to any health professional who provides a written statement 
of need for the information and executes a confidentiality agreement. 
Where a health professional determines that a medical emergency exists 
and the protected information is necessary for emergency treatment, 
the information shall be immediately disclosed upon a verbal 
acknowledgment that such information shall not be used for purposes 
other than the asserted health needs and shall otherwise be maintained 
as confidential. A written statement of need and a confidentiality 
agreement may be requested as soon as circumstances permit. 
Information so disclosed does not become publicly available. 
Information claimed to be a trade secret shall be provided to the Oil 
and Gas Conservation Commission upon written request from the Director 
of the Commission stating that such information is necessary to 
respond to a spill or release or a complaint from a person who may 
have been affected or aggrieved by a spill or release. The Director or 
designee may disclose the information to additional commission staff 
if such disclosure is necessary to allow staff to respond to the 
spill, release, or complaint, provided that such individuals shall not 
disseminate the information further. In addition, the Director may 
disclose such information to any commissioner, the relevant county 
public health director or emergency manager, or to the Colorado 
Department of Public Health and Environment's director of 
environmental programs upon request by that individual. The Colorado 
Department of Public Health and Environment's director of 
environmental programs, or his or her designee, may disclose such 
information to Colorado Department of Public Health and Environment 
staff members under the same terms and conditions as apply to the 
director. Information so disclosed does not become publicly available. 
2 Colo. Code Regs. § 404-1(100, 205A) (2012). 

North Dakota: 
After performance of a hydraulic fracture stimulation, the owner, 
operator, or service company must post on FracFocus all elements made 
viewable by the FracFocus website.[A] N.D. Admin. Code 43-02-03-27.1 
(2012). 

Ohio: 
Within 60 days after the completion of drilling or after a 
determination that a well is a dry or lost hole, a well completion 
record must be filed which designates: the trade name and the total 
amount of all products, fluids, and substances, and the supplier of 
each product, fluid, or substance--not including cement and its 
constituents and lost circulation materials--intentionally added to 
facilitate the drilling of any portion of the well until the surface 
casing is set and properly sealed or to stimulate the well. The owner 
shall identify each additive used and provide a brief description of 
the purpose for which the additive is used. For stimulated wells, the 
owner shall also include the maximum concentration of the additive 
used. In addition, the owner shall include a list of all chemicals, 
not including any information that is designated as a trade secret, 
intentionally added to all products, fluids, or substances and include 
each chemical's corresponding CAS number and the maximum concentration 
of each chemical. The owner shall obtain the chemical information, not 
including trade secrets, from the company that drilled or stimulated 
the well, provided drilling services at the well, or supplied the 
chemical; and the type and volume of any fluid, not including cement 
and its constituents or trade secret information, used to stimulate 
the well, the reservoir breakdown pressure, the method used for the 
containment of fluids recovered from the fracturing of the well, the 
methods used for the containment of fluids when pulled from the 
wellbore from swabbing the well, the average pumping rate of the well, 
and the name of the person that performed the well stimulation. In 
addition, the owner shall include a copy of the log from the 
stimulation of the well, a copy of the invoice for each of certain 
procedures and methods that were used on a well, and a copy of the 
pumping pressure and rate graphs. After a well is initially completed 
and stimulated and until the well is plugged, the owner shall report 
all materials placed into the formation to refracture, restimulate, or 
newly complete the well, in addition to the information required 
above, within 60 days. If there is a material listed in the 
disclosures for which the state does not have a material safety data 
sheet, the owner shall provide a copy to the state. Information must 
be submitted to the state on state prescribed forms, through 
FracFocus, or by other state-approved means. The state must post 
information obtained online. If a medical professional, in order to 
assist in the diagnosis or treatment of an individual who was affected 
by an incident associated with the production operations of a well, 
requests the exact chemical composition of each product, fluid, or 
substance and of each chemical component in a product, fluid, or 
substance that is designated as a trade secret pursuant, the person 
claiming the trade secret protection shall provide the information 
requested. A medical professional who receives such information shall 
keep it confidential and shall not disclose it for any purpose that is 
not related to the diagnosis or treatment. This requirement does not 
preclude a medical professional from making any report required by law 
or professional ethical standards. Companies may withhold the 
identity, amount, concentration, or purpose of a product, fluid, or 
substance or of a chemical component in a product, fluid, or substance 
as a trade secret. The state may not disclose any trade secret 
information. Anyone with an interest that is or may be adversely 
affected by a product, fluid, or substance or by a chemical component 
in a product, fluid, or substance may challenge a claim of trade 
secret protection. A well owner shall maintain records of chemicals 
placed in a well for at least 2 years after placement. The chief of 
the Oil and Gas Division in the Ohio Department of Natural Resources 
may inspect the records for non trade secret information at any time 
concerning any such chemical. For trade secret information, the well 
owner must disclose records to the state upon request if the 
information is necessary to respond to a spill, release, or 
investigation. However, the state shall not disclose the information 
that is designated as a trade secret. An owner is not required to 
report chemicals that occur incidentally or in trace amounts. Ohio 
Rev. Code Ann. § 1509.10 (2012). 

Pennsylvania: 
Certain disclosures are required from vendors of hydraulic fracturing 
additives, companies that provide hydraulic fracturing services, and 
operators on whose wells hydraulic fracturing treatments are 
completed.[B] If the vendor, service provider or operator claims that 
the specific identity of a chemical or the concentration of a 
chemical, or both, are a trade secret or confidential proprietary 
information, the operator of the well must indicate that on the form 
submitted to FracFocus and submit a signed statement that the record 
contains a trade secret or confidential proprietary information. If a 
chemical is a trade secret, the operator shall include in its 
submission to FracFocus the chemical family or similar description 
associated with the chemical. Unless the information is entitled to 
protection as a trade secret or confidential proprietary information, 
information posted to FracFocus is public. A vendor, service company, 
or operator shall identify the specific identity and amount of any 
chemicals claimed to be a trade secret or confidential proprietary 
information to any health professional who executes a confidentiality 
agreement and provides a written statement of need for the information 
indicating that the information is needed for diagnosis or treatment 
of an individual who may have been exposed to a hazardous chemical, 
and that knowledge of the information will assist in the diagnosis or 
treatment. If a health professional determines that a medical 
emergency exists and the information claimed to be a trade secret or 
confidential proprietary information is necessary for emergency 
treatment, the vendor, service provider or operator shall immediately 
disclose the information upon a verbal acknowledgment that the 
information may not be used for purposes other than the health needs 
asserted and that it will be maintained as confidential. The vendor, 
service provider, or operator may request, and the health professional 
shall provide, a written statement of need and a confidentiality 
agreement as soon as circumstances permit. Trade secret or 
confidential proprietary information must also be provided to the 
department, a public health official, an emergency manager, or a 
responder to a spill, release or a complaint if that information is 
needed for response. The department must prevent further disclosure of 
trade secrets or confidential proprietary information in accordance 
with other applicable state law. 58 Pa.Cons.Stat. §§ 3203, 3222.1 
(2012). 

Texas: 
Certain disclosures are required from suppliers of hydraulic 
fracturing additives, companies that provide hydraulic fracturing 
services, and operators on whose wells hydraulic fracturing treatments 
are completed. Suppliers and service providers must provide to 
operators information on each chemical ingredient intentionally added 
to the hydraulic fracturing fluid, including each additive used, its 
trade name, supplier, and a brief description of its intended use; 
each chemical ingredient for which a material safety data sheet would 
be required under federal regulation;[C] the actual or maximum 
concentration of each chemical ingredient listed under the last two 
clauses in percent by mass; all other chemical ingredients that were 
intentionally included in and used for creating hydraulic fracturing 
treatment(s) for the well; and the Chemical Abstracts Service (CAS) 
number for each chemical ingredient, if applicable. Operators must 
post information to FracFocus, including: information on the makeup of 
hydraulic fracturing treatments as described above; operator name; 
date of hydraulic fracturing treatment; location and other identifying 
information for the well; the true vertical depth of the well; and the 
total volume of water used in the hydraulic fracturing treatment(s) of 
the well or the type and total volume of the base fluid used in the 
hydraulic fracturing treatment(s), if something other than water. If 
the supplier or service company claims that the specific identity 
and/or CAS number or amount of any additive or chemical ingredient 
used in a treatment is entitled to protection as a trade secret under 
Texas law, it must provide the operator a written statement to that 
effect and must provide its contact information and the chemical 
family, unless that is also claimed as a trade secret, in which case 
only the properties and effects of the ingredient(s) must be 
disclosed. A claim that any of the same information is a trade secret 
must be included in the submission to FracFocus, along with the 
chemical family or other similar description and the contact 
information of the business claiming the trade secret. Information not 
protected as a trade secret is public information. A supplier, service 
company, or operator may not withhold information, including trade 
secrets, from any health professional or emergency responder who needs 
the information for diagnostic, treatment or other emergency response 
purposes. A supplier, service company, or operator must provide 
directly to a health professional or emergency responder all 
information in the person's possession that is required whether or not 
the information may be a trade secret. The person disclosing 
information must include, as soon as circumstances permit, a statement 
of the health professional's confidentiality obligation. In an 
emergency, the supplier, service company, or operator must provide the 
information immediately.d A health professional or emergency responder 
to whom information is disclosed must hold the information 
confidential, except that he or she may, for diagnostic or treatment 
purposes, disclose information to another health professional, 
emergency responder, or accredited laboratory. Such a person or entity 
must hold the information confidential, and the disclosing person must 
include with the disclosure, or in a medical emergency, as soon as 
circumstances permit, a statement of the recipient's confidentiality 
obligation. Certain parties may challenge a claim of trade secret 
protection, including the landowner on whose property the relevant 
wellhead is located; the landowner who owns real property adjacent to 
property described above; and a department/agency with jurisdiction 
over a matter to which the claim is relevant. 16 Tex. Admin. Code § 
3.29 (2012). 

Wyoming; 
* The Application for Permit to Drill must include a description of 
any anticipated stimulation program, including the base stimulation 
fluid and its source, the chemical additives and proposed 
concentrations to be mixed, identified by additive type. Specifically, 
owners or operators must provide information on the stimulation fluid 
identified by additive type, the chemical compound name and CAS 
number, and the proposed rate or concentration for each additive. Upon 
prior request on certain forms and/or by written letter to the state 
justifying and documenting the nature and extent of the proprietary 
information, confidentiality protection shall be provided consistent 
with the Wyoming Public Records Act for trade secrets, privileged 
information and confidential commercial, financial, geological, or 
geophysical data furnished by or obtained from any person. Reports 
must generally be submitted to the state within 30 days of completion 
of certain activities, including formation fracturing, which present a 
detailed account of the work done and the manner in which it was 
performed, including the quantity of sand, crude, chemical, or other 
materials employed in the operation; 
* Following well stimulation, the owner, operator, or service company 
must provide the actual total well stimulation treatment volume pumped; 
detail as to each fluid stage pumped, including actual volume, 
proppant rate or concentration; and actual chemical additive name, 
type, concentration or rate, and amounts. In lieu of the preceding 
information, an owner/operator may submit a job log. 055-000-003 Code 
Wyo. R. §§§ 8, 12, 45 (2012). 

Pressure monitoring, testing, limitations or other mechanical 
integrity requirements during well treatment or stimulation: 

Colorado: 
During stimulation, bradenhead[E] annulus pressure shall be 
continuously monitored and recorded. If at any time during stimulation 
operations the bradenhead annulus pressure increases more than 200 psi 
(gauge), the operator shall verbally notify the state as soon as 
practicable, but no later than 24 hours following the incident. Within 
15 days after the occurrence, the operator shall submit a notice 
giving all details, including corrective actions taken. If 
intermediate casing has been set on the well being stimulated, the 
pressure in the annulus between the intermediate casing and the 
production casing shall also be monitored and recorded. The operator 
shall keep all well stimulation records and pressure charts on file 
and available for inspection by the state for at least 5 years. An 
operator may seek a variance from these bradenhead monitoring, 
recording, and reporting requirements under appropriate circumstances. 
2 Colo. Code Regs. § 404-1(341) (2012). 

North Dakota: 
* The state may prescribe pretreatment casing pressure testing and 
other operational requirements to protect wellhead and casing strings 
during treatment operations. If damage results to the casing or the 
casing seat from fracturing or chemically treating a well, the 
operator shall immediately notify the state and proceed with diligence 
to rectify the damage. If perforating, fracturing, or chemical 
treating results in irreparable damage that threatens the mechanical 
integrity of the well, the commission may require the operator to plug 
the well; 
* The following mechanical integrity requirements apply to hydraulic 
fracture stimulations performed through a frac string run inside the 
intermediate casing string. (1) The frac string must be stung into a 
liner or run with a packer set at a minimum depth of 100 feet below 
the top of cement or 100 feet below the top of the Inyan Kara 
formation, whichever is deeper. (2) The intermediate casing-frac 
string annulus must be pressurized and monitored during frac 
operations. (3) An adequately sized, function tested pressure relief 
valve must be utilized on the treating lines from the pumps to the 
wellhead, with suitable check valves to limit the volume of flowback 
fluid should the relief valve open. The relief valve must be set to 
limit line pressure to no more than 85% of the internal yield pressure 
of the frac string. (4) An adequately sized, function tested pressure 
relief valve and an adequately sized diversion line must be utilized 
to divert flow from the intermediate casing to a pit or containment 
vessel in case of frac string failure. The relief valve must be set to 
limit annular pressure to no more than 85% of the lowest internal 
yield pressure of the intermediate casing string. (5) The surface 
casing valve must be fully open and connected to a diversion line 
rigged to a pit or containment vessel. (6) An adequately sized, 
function tested remote operated frac valve must be utilized between 
the treating line and the wellhead; 
* The following specific mechanical integrity requirements apply to 
hydraulic fracture stimulations performed through an intermediate 
casing string: (1) The maximum treating pressure shall be no greater 
than 85% of the American Petroleum Institute rating of the 
intermediate casing. (2) Casing evaluation tools to verify adequate 
wall thickness of the intermediate casing shall be run from the 
wellhead to a depth as close as practicable to 100 feet above the 
completion formation and a visual inspection with photographs shall be 
made of the top joint of the intermediate casing and the wellhead 
flange. If the casing evaluation tool or visual inspection indicates 
wall thickness is below the American Petroleum Institute minimum or a 
lighter weight of intermediate casing than the well design called for, 
calculations must be made to determine the reduced pressure rating. If 
the reduced pressure rating is less than the anticipated treating 
pressure, a frac string shall be run inside the intermediate casing. 
(3) Cement evaluation tools to verify adequate cementing of the 
intermediate casing shall be run from the wellhead to a depth as close 
as practicable to 100 feet above the completion formation. If the 
cement evaluation tool indicates defective casing or cementing a frac 
string shall be run inside the intermediate casing. If the cement 
evaluation tool indicates the top of cement behind the intermediate 
casing is below the top of the Mowry Formation, a frac string shall be 
run inside the intermediate casing. (4) The intermediate casing and 
wellhead must be pressure tested to a minimum depth of 100 feet below 
the top of the Tyler formation for at least 30 minutes with less than 
5% loss to a pressure equal or greater than the maximum frac design 
pressure. (5) If the pressure rating of the wellhead does not exceed 
the maximum frac design pressure, a wellhead and blowout preventer 
protection system must be utilized during the frac. (6) An adequately 
sized, function tested pressure relief valve must be utilized on the 
treating lines from the pumps to the wellhead, with suitable check 
valves to limit the volume of flow back fluid should the relief valve 
open. The relief valve must be set to limit line pressure to no 
greater than the test pressure of the intermediate casing, less 100 
psi; (7) The surface casing valve must be fully open and connected to 
a diversion line rigged to a pit or containment vessel. (8) An 
adequately sized, function tested remote operated frac valve must be 
utilized between the treating line and the wellhead; 
* If during stimulation, the pressure in the intermediate casing-
surface casing annulus exceeds 350 psi, the owner or operator shall 
verbally notify the state as soon as practicable but no later than 24 
hours later. N.D. Admin. Code 43-02-03-27, 27-1 (2012). 

Ohio: 
All casing installed in a well must have a minimum internal yield 
pressure rating designed to withstand at least 1.2 times the maximum 
pressure to which the casing may be subjected during stimulation 
operations. Reconditioned casing that is permanently set in a well 
shall be hydrostatically pressure tested with an applied pressure at 
least 1.2 times the maximum internal pressure to which the casing may 
be subjected or pressure that may be applied during stimulation, 
whichever is greater, and assuming no external pressure. Test results 
shall be provided to the state before casing is installed in the well. 
Wellhead assemblies shall be used to maintain surface control of the 
well. Each component of the wellhead shall have a working pressure 
rating equal to or greater than the highest anticipated operating 
pressure to which the particular component might be exposed during the 
course of stimulating the well. During stimulation or workover 
operations, all annuli shall be pressure-monitored. Stimulation or 
workover operations shall be immediately suspended for any 
inexplicable pressure deviation above those anticipated increases 
caused by pressure or thermal transfer. In the event that stimulation 
fluids circulate, or annular pressures deviate from anticipated, the 
owner shall immediately notify the state and acquire approval for 
remediation of casing or cement. If the chief determines that the 
stimulation of the well has resulted in irreparable damage to the 
well, the chief shall order that the well be plugged and abandoned 
within 30 days of issuance of the order. Ohio Admin. Code Ann. 1501:9-
1-08 (2012). 

Pennsylvania: 
No requirements identified in regulations or in statutes. 

Texas: 
No requirements identified in regulations or in statutes. 

Wyoming: 
Setting depths of all casing strings shall be determined based on 
formation fracture gradients and the maximum anticipated pressure to 
be maintained within the wellbore. 055-000-003 Code Wyo. R. § 22 
(2012).The Owner/Operator shall provide geological names, geological 
description and depth of the formation into which well stimulation 
fluids are to be injected and a detailed description of the proposed 
well stimulation design, which shall include: the anticipated surface 
treating pressure range; the maximum injection treating pressure; and 
the estimated or calculated fracture length and fracture height. The 
state may require, prior to well stimulation, the owner or operator to 
perform a suitable mechanical integrity test of the casing or of the 
casing-tubing annulus or other mechanical integrity test methods. 
During well stimulation, the Owner/Operator shall monitor and record 
the annulus pressure at the bradenhead. If intermediate casing has 
been set on the well being stimulated, the pressure in the annulus 
between the intermediate casing and the production casing shall also 
be monitored and recorded. A continuous record of the annulus pressure 
during the well stimulation shall be submitted to the state. If during 
the stimulation the annulus pressure increases by more than 500 psig, 
the Owner or Operator shall verbally notify the Supervisor as soon as 
practicable but no later than 24 hours following the incident. The 
Owner or Operator shall include a report containing all details 
pertaining to the incident, including corrective actions taken. 055-
000-003 Code Wyo. R. §§ 22, 45 (2012). 

Other: 

Colorado: 
An operator making application for approval of an oil and gas location 
assessment shall provide the surface owner and owners of surface 
property within 500 feet of the proposed oil and gas location with 
certain information, including a state information sheet on hydraulic 
fracturing treatments and must provide notice of subsequent well 
operations, such as refracturing of a well, at least 7 days in advance 
of the operations. Placement of all stimulation fluids shall be 
confined to the objective formations during treatment to the extent 
practicable. 2 Colo. Code Regs. § 404-1(305, 341) (2012). 

North Dakota: 
No additional requirements identified in regulations or in statutes. 

Ohio: 
* When cementing the production string of a well that will be 
stimulated by hydraulic fracturing, and the uppermost perforation is 
less than 500 feet below the base of the deepest underground source of 
drinking water, sufficient cement shall be used to fill the annular 
space outside the casing from the seat to the ground surface or to the 
bottom of the cellar. If it is not so circulated, the owner shall 
notify the state and perform tests approved by the state. After the 
top of cement outside the casing is determined, the owner or his/her 
authorized representative shall contact the state and obtain approval 
for the procedures to be used to perform any required additional 
cementing operations; 
* Using steel production casing with sufficient cement, an oil and gas 
reservoir shall be isolated during well stimulation and during the 
productive life of the well. A well shall not be perforated for 
purposes of well stimulation in any zone that is located around casing 
that protects underground sources of drinking water without written 
authorization from the state; 
* An owner who elects to stimulate a well shall do so in a manner that 
will not endanger underground sources of drinking water. If during the 
stimulation of a well, damage to the production casing or cement 
occurs, and results in the circulation of fluids from the annulus of 
the surface production casing, the owner shall immediately terminate 
the stimulation of the well and notify the state. If the state 
determines that the casing and the cement may be remediated in a 
manner that isolates the oil and gas bearing zones of the well, the 
state may authorize the completion of the stimulation of the well. If 
the state determines that the stimulation of a well resulted in 
irreparable damage to the well, the state shall order that the well be 
plugged within 30 days. For purposes of determining the integrity of 
the remediation of the casing or cement of a well that was damaged 
during the stimulation of the well, the state may require the owner to 
submit cement evaluation logs, temperature surveys, pressure tests, or 
a combination of such logs, surveys, and tests. Ohio Admin. Code Ann. 
1501:9-1-08 (2012); Ohio Rev. Code Ann. §§ 1509.17, .19 (2012). 

Pennsylvania: 
A well permit application must be accompanied by a plat showing the 
name of all surface landowners and water purveyors whose water 
supplies are within 3,000 feet. The applicant must notify the 
aforementioned landowners and purveyors, and each municipality and 
storage operator within 3,000 feet. A containment plan for 
unconventional wells is required. Practices under the plan must be 
sufficiently impervious and able to contain spilled material until it 
can be removed or treated, and be compatible with the material to be 
contained. The plan must be submitted to the state. Containment 
systems must be used for drilling mud, hydraulic oil, diesel fuel, 
drilling mud additives, hydraulic fracturing additives, and hydraulic 
fracturing flowback. Areas where any additives, chemicals, oils, or 
fuels are to be stored must have sufficient containment capacity to 
hold the volume of the largest container stored in the area plus 10% 
to allow for precipitation, unless the container is equipped with 
individual secondary containment. An owner/operator of a facility 
conducting natural gas operations in unconventional formations shall 
submit to the department a source report identifying and quantifying 
actual air contaminant emissions from any air contamination source. 58 
Pa.Cons.Stat. §§ 3211, 3218.2, 3227 (2012). 

Texas: 
No additional requirements identified. 

Wyoming: 
The injection of volatile organic compounds, such as benzene, toluene, 
ethylbenzene and xylene, (BTEX compounds), or any petroleum 
distillates into groundwater is prohibited. The proposed use of BTEX 
compounds or petroleum distillates for well stimulation into 
hydrocarbon bearing zones is authorized with prior state approval. It 
is accepted practice to use produced water that may contain small 
amounts of naturally occurring petroleum distillates, as well 
stimulation fluid in hydrocarbon bearing zones; 
Following well stimulation, the owner, operator, or service company 
must provide the actual total well stimulation treatment volume pumped; 
detail as to each fluid stage pumped, including actual volume, 
proppant rate or concentration; actual chemical additive name, type, 
concentration or rate, and amounts; the actual surface pressure and 
rate at the end of each fluid stage and the actual flush volume, rate 
and final pump pressure; the instantaneous shut-in pressure, and the 
actual 15-minute and 30-minute shut-in pressures when available. In 
lieu of the preceding information, an owner/operator may submit a job 
log; The owner/operator shall provide information to the state as to 
the amounts, handling and, if necessary, disposal at an identified 
appropriate disposal facility, or reuse of the well stimulation fluid 
load recovered during flowback, swabbing, and/or recovery from 
production facility vessels. Storage of such fluid shall be protective 
of groundwater as demonstrated by the use of either tanks or lined 
pits. If lined pits are utilized to store fluid for use in well 
stimulation, or for reconditioning, for reuse, or to hold for 
appropriate disposal, then additional requirements to protect wildlife 
and migratory birds shall be met. 055-000-003 Code Wyo. R. § 45 (2012). 

Source: GAO analysis of state information. 

[A] Elements that are viewable on the FracFocus website include date 
of fracturing treatment, identifying information for wells, and 
information on hydraulic fracturing fluid composition, including trade 
name of component, supplier, purpose, ingredients, CAS number, and 
maximum ingredient concentrations in the additive and in the fluid as 
a whole. 

[B] Pennsylvania law does not specify what information must be 
disclosed. 

[C] 29 C.F.R. § 1910.1200(g)(2) (2011). 

[D] The disclosures required by this subsection must be made in 
accordance with the procedures in 29 C.F.R. § 1910.1200(i) (2011) with 
respect to a written statement of need and confidentiality agreements, 
as applicable. 

[E] A bradenhead is a casing head in an oil well having a stuffing box 
packed to make a gastight connection. 

[End of table] 

Table 15: Selected State Requirements--Well Plugging: 

Requirements for notification, plugging plan or method, witnessing, 
and reporting: 

Colorado: 
The operator must obtain prior approval of the plugging method. A hole 
must be plugged so that substances are confined to the reservoir from 
which they originated. Cement plugs shall be at least 50 feet long and 
extend at least 50 feet above each zone to be protected. Plugging 
material, whether cement, a mechanical plug, or other equivalent 
method approved by the state, must permanently prevent migration of 
oil, gas, water, or other substance from the formation or horizon in 
which it originally occurred. Where cement is used, the operator may 
choose among the following methods of placing cement in the hole: by 
dump bailer, pumping a balanced cement plug through tubing or drill 
pipe, pump and plug, or equivalent method approved by the state prior 
to plugging. Unless prior approval is given, all wellbores shall have 
water, mud, or other approved fluid between all plugs. The operator 
must provide notice of the estimated time and date of plugging. 
Reports of plugging and abandonment must be submitted with a job log 
or cement verification report from the plugging contractor specifying 
the fluid used to fill the wellbore, type and slurry volume of cement 
used, date of work, and depth of plugs. 2 Colo. Code Regs. § 404-
1(319) (2012). 

North Dakota: 
A notice of intention to plug, including the proposed method of 
plugging and a detailed statement of proposed work, must be approved 
by the state prior to plugging. Generally, wells must be plugged so to 
confine permanently all oil, gas, and water in the separate strata 
originally containing them. This operation shall be accomplished by 
the use of mud-laden fluid, cement, and plugs, used singly, or in 
combination, as may be approved by the state. After the plugging of a 
well, a plugging record shall be filed with the state. N.D. Admin. 
Code 43-02-03-33, -34, -31 (2012). 

Ohio: 
A permit must be obtained to plug a well. Wells must be plugged so 
that oil, gas, water, or other fluids shall be confined to the 
reservoir rock in which it occurs or originates. The owner, or his 
agent, may have the option of using any method of emplacing the 
plugging material approved by the state including dump bailer, 
bullhead, pumping through tubing, casing, or drill pipe. The state may 
designate an alternate method of plugging in certain areas. Plugging 
operations must be conducted under the supervision of a state 
inspector. The owner or his/her agent shall notify the inspector when 
plugging operations will commence at a dry hole or lost hole in 
sufficient time to enable the inspector to be present. For all other 
wells, the owner or agent shall notify the inspector a minimum of 24 
hours in advance. The state may grant verbal authorization to commence 
plugging when the inspector is unable to be present. The state 
regulations include detail on when plugging must be commenced, when 
specific types of pipe and casing can be pulled from a well, the 
materials that can be used for plugging, and how plugging with those 
materials must proceed. When plugging operations are not witnessed by 
an inspector, a plugging report on a form provided by the state and 
signed by the owner or his agent, shall be filed with the state within 
30 days after completion of plugging. For all wells plugged with 
cement, a cementing ticket made by the party cementing the well shall 
be attached to the plugging report. For all wells plugged with 
prepared clay, a copy of the prepared clay purchase record shall be 
attached to the plugging report. When an inspector is present to 
supervise the plugging operations, a plugging report shall be filed on 
such form as the chief may prescribe. Ohio Admin. Code Ann. 1501:9-11-
02, -03, -04, -12 (2012). 

Pennsylvania: 
Notification and witnessing requirements apply only to wells in coal 
areas. Prior to plugging a well in an area underlain by a workable 
coal seam, the operator or owners must notify the state, and the coal 
operator, lessee or owner to permit representatives to be present at 
the plugging. Detailed plugging requirements differ based on whether 
the well is in a coal or noncoal area, whether surface casing is 
present and how it is attached, and whether the well was stimulated 
with explosives. A plan is only required if operator proposes an 
alternate plugging method for approval. Reporting requirements also 
only apply to coal areas. When plugging of a well in an area underlain 
by a workable coal seam has been completed, a certification shall be 
prepared and signed by two experienced and qualified people who 
participated in the work setting forth the time and manner in which 
the well was plugged. One copy of the certificate shall be mailed to 
each coal operator, lessee or owner, and another shall be mailed to 
the state. 25 Pa. Code §§ 78.91-.98 (2012). 58 Pa.C.S. §§ 3220, 3221 
(2012). 

Texas: 
Generally, the operator must give notice of its intention to plug any 
well prior to plugging. The notice shall set out the proposed plugging 
procedure as well as the complete casing record. The proposed plugging 
procedure must be approved before plugging commences. Generally, wells 
shall be plugged to insure that all formations bearing usable quality 
water, oil, or gas are protected. Cement plugs shall be set to isolate 
each productive horizon and usable quality water strata; 
cement plugs shall be placed by the circulation or squeeze method 
through tubing or drill pipe. Cement plugs shall be placed by other 
methods only upon written request with the written approval of the 
state. The regulations list different specific requirements for wells 
with surface, intermediate, and production casing, wells with screens 
or liners, and wells without production casing and open-hold 
completions. Plugging cannot commence before the date in the notice 
unless otherwise authorized, and the operator shall notify the 
district office at least 4 hours before plugging. Exceptions to the 
timing requirements may be granted in certain circumstances. The 
operator shall file a plugging record within 30 days of plugging. 16 
Tex. Admin. Code 3.14 (2012). 

Wyoming: 
Before plugging, a notice of intent must be filed with the state. The 
notice must give a detailed statement of proposed work including kind, 
location, and length of plugs (by depths), and plans for mudding, 
cementing, shooting, testing, and removing casing, as well as any 
other pertinent information. Approval must be obtained prior to 
commencing plugging operations. The regulations list different 
specific requirements for wells with and without production casing, 
coalbed methane wells in the Powder River Basin, and wells within a 
geologic area known as the Special Sodium Drilling Area. When the well 
has been plugged, a notarized report accompanied by a job log or 
cement verification report from the plugging contractor specifying the 
type of fluid used to fill the wellbore, type of slurry volume of 
cement used, date of work, and depth of plugs placed must be 
submitted. 055-000-003 Code Wyo. R. §§ 15, 18 (2012). 

Source: GAO analysis of state information. 

[End of table] 

Table 16: Selected State Requirements--Site Reclamation: 

Backfilling, regrading, recontouring, and compaction alleviation 
requirements: 

Colorado: 
Areas disturbed by drilling and subsequent operations no longer needed 
for production will be restored to their original condition or their 
final land use as designated by the surface owner and shall be 
maintained to control dust and minimize erosion. If subsidence occurs 
on crop lands, additional topsoil shall be added, and the land shall 
be releveled as close to its original contour as practicable. Interim 
reclamation must occur no later than 3 months on crop land or 6 months 
on noncrop land after operations cease unless that time is extended by 
the state. Areas needed for subsequent operations within the year 
shall be stabilized and maintained to minimize dust and erosion. Areas 
compacted by drilling and subsequent operations no longer needed for 
production shall be cross-ripped. On crop land, operations shall be 
undertaken when soil moisture is below 35% of field capacity to a 
depth of 18 inches unless bedrock is shallower. After well plugging, 
all access roads to plugged wells shall be closed, graded, and 
recontoured. Culverts and other obstructions shall be removed. As 
applicable, compaction alleviation will be performed to the same 
standards as for interim reclamation. Final reclamation must be 
completed within 3 months on crop land and 12 months on noncrop land 
unless that time is extended by the state. Reclamation of the well 
site and access road shall be considered complete on crop land when, 
among other things, observation over two growing seasons indicates no 
significant unrestored subsidence. Stabilization so as to minimize 
erosion to the extent practicable is a factor in determining 
completion of final reclamation for all disturbed areas. 2 Colo. Code 
Regs. § 404-1(1003, 1004) (2012). 

North Dakota: 
The well site, access road, and other associated facilities 
constructed for the well shall be reclaimed within a year after a well 
is plugged or a permit expires or is canceled or revoked. Operators 
must submit and obtain approval of a reclamation plan, including a 
description of the proposed work, including topsoil redistribution and 
reclamation plans for the access road and other associated facilities. 
Gravel and other surfacing material must be removed, stabilized soil 
must be remediated, and the well site, access road, and other 
associated facilities shall be reshaped as near as practicable to 
their original contour. Previously stockpiled topsoil shall be evenly 
distributed over the disturbed area. N.D. Admin. Code 43-02-03-34.1 
(2012). 

Ohio: 
Unless the state approves a longer time period, within 3 months after 
drilling commences in an urbanized area and within 6 months after 
drilling commences in all other areas, the owner or the owner's agent 
shall grade or terrace disturbed areas that are not required in 
production. Within 3 months after a well is plugged in an urbanized 
area, and within 6 months after a well is plugged in all other areas, 
or after the plugging of a dry hole, unless the state approves a 
longer time period, the owner or the owner's agent shall fill 
remaining excavations. Ohio Rev. Code Ann. § 1509.072 (2012). 

Pennsylvania: 
Each oil or gas well owner or operator shall restore the land surface 
within the area disturbed in siting, drilling, completing, and 
producing the well. Within 9 months after completion of drilling a 
well, the owner or operator shall restore the well site, remove or 
fill all pits used to contain produced fluids or industrial wastes, 
remove all production and storage facilities, supplies and equipment, 
and remove all drilling supplies and equipment not needed for 
production. Drilling supplies and equipment not needed for production 
may be stored on the well site if express written consent is obtained 
from the surface landowner. This time frame may be extended to a 
maximum of 2 years upon request and submission of a plan demonstrating 
that the extension will result in less earth disturbance or that site 
restoration cannot be achieved due to adverse weather conditions or a 
lack of essential fuel, equipment or labor. 58 Pa.C.S. § 3216. 

Texas: 
The operator shall fill the rathole, mouse hole, and cellar, and shall 
empty all tanks, vessels, related piping, and flowlines that will not 
be actively used in the continuing operation of the lease within 120 
days after plugging work is completed. Within the same 120-day period, 
the operator shall remove all such tanks, vessels, and related piping, 
remove all loose junk and trash from the location, and contour the 
location to discourage pooling of surface water at or around the 
facility site. The operator shall close all pits. The district 
director or the director's delegate may grant a reasonable extension 
of time of not more than an additional 120 days for the removal of 
tanks, vessels and related piping. 16 Tex. Admin. Code 3.14 (2012). 

Wyoming: 
Reclamation must be initiated within 1 year of permanent abandonment 
of a well or last use of a pit and must be completed in accordance 
with the landowner's reasonable requests and/or resemble the original 
contour of adjoining lands. All disturbed areas on state lands will be 
recontoured unless the state approves otherwise. 055-000-003 Code Wyo. 
R. §§ 7, 17 (2012). 

Revegetation requirements: 

Colorado: 
When a well is completed for production, all disturbed areas no longer 
needed will be revegetated as soon as practicable. For crop lands, all 
segregated soil horizons shall be replaced to their original relative 
positions and contour and shall be tilled to establish a proper 
seedbed. The area shall be treated if necessary and practicable to 
prevent weeds and erosion. Previously present perennial forage crops 
shall be reestablished. For noncrop lands, all segregated soil 
horizons shall be replaced to their original relative positions and 
contour as near as practicable to achieve erosion control and long-
term stability and shall be tilled to establish a proper seed bed. The 
area shall be reseeded in the first favorable season following rig 
demobilization. Reseeding consistent with adjacent plant communities 
is encouraged. Seed mix should be as agreed with surface owner or 
based on consultation with the local soil conservation district. To be 
considered complete, reclamation must, among other things, establish 
uniform vegetative cover reflecting predisturbance or reference area 
vegetation with total cover of at least 80% of predisturbance levels, 
excluding weeds. After a well is plugged, revegetation of well sites, 
associated production facilities, and access roads shall be performed 
to the same standards. A decision as to whether final reclamation has 
been completed will take into account permanent physical erosion 
reduction methods as an alternative to 80% revegetation. 2 Colo. Code 
Regs. § 404-1(1003, 1004) (2012). 

North Dakota: 
The reclamation plan for the well site, access road, and other 
associated facilities shall include a reseeding plan, if applicable. 
Disturbed areas shall be revegetated with native species or according 
to the reasonable specifications of the government land manager or 
surface owner. N.D. Admin. Code 43-02-03-34.1 (2012). 

Ohio: 
Unless the state approves a longer time period, within 3 months after 
the date upon which the surface drilling of a well is commenced in an 
urbanized area, and within 6 months after the date upon which the 
surface drilling of a well is commenced in all other areas, the owner 
or the owner's agent shall plant, seed, or sod the area disturbed that 
is not required in production of the well where necessary to bind the 
soil and prevent substantial erosion and sedimentation. Within 3 
months after a well that has produced oil or gas is plugged in an 
urbanized area, and within 6 months after a well that has produced oil 
or gas is plugged in all other areas, or after the plugging of a dry 
hole, unless the chief approves a longer time period, the owner or the 
owner's agent shall plant, seed, or sod the area disturbed where 
necessary to bind the soil and prevent substantial erosion and 
sedimentation. Ohio Rev. Code Ann. § 1509.072 (2012). 

Pennsylvania: 
Upon final completion of an earth disturbance activity or any stage or 
phase of activity, the site must have topsoil immediately restored, 
replaced, or amended, seeded, mulched, or otherwise permanently 
stabilized and protected from accelerated erosion and sedimentation. 
For the earth disturbance activity or any stage or phase of an 
activity to be considered permanently stabilized, the disturbed area 
must be covered with a minimum uniform 70% perennial vegetative cover 
with a density capable of resisting accelerated erosion and 
sedimentation or an acceptable best management practice that 
permanently minimizes accelerated erosion and sedimentation; See also 
specific pit closure requirements above. In addition, where residual 
waste is disposed of by land application, the application area shall 
be revegetated to stabilize the soil surface. The revegetation shall 
establish a diverse, effective permanent vegetative cover which is 
capable of self-regeneration and plant succession. Where vegetation 
would interfere with the intended use of the surface by the landowner, 
the surface shall be stabilized against erosion. 25 Pa Code §§ 78.63, 
102.22 (2012). 

Texas: 
No requirements identified in regulations or in statutes.[A]. 

Wyoming: 
Reclamation must be initiated within 1 year of permanent abandonment 
of a well or last use of a pit and must be completed in accordance 
with the landowner's reasonable requests and/or resemble the original 
vegetation of adjoining lands. All disturbed areas on state lands will 
be reseeded unless the state approves otherwise. 055-000-003 Code Wyo. 
R. §§ 7, 17 (2012). 

Source: GAO analysis of state information. 

[A] According to Texas state officials, however, requirements may be 
included in permits issued by the Railroad Commission. 

[End of table] 

Table 17: Selected State Requirements--Waste Management in Pits: 

Pit siting requirements (with regard to sensitive areas): 

Colorado: 
Generally, pits shall not be constructed in areas where pathways for 
communication with groundwater or surface water are likely to exist. 
Operations at new locations within the intermediate and external 
buffer zones surrounding a public water system cannot use pits.[A] 2 
Colo. Code Regs. § 404-1(317B, 902) (2012). 

North Dakota: 
Reserve pits may be used for wells drilled to certain depths providing 
the pit can be constructed, used, and reclaimed in a manner that will 
prevent pollution of the land surface and freshwaters. In special 
circumstances, based on site-specific conditions, the state may 
prohibit construction of a reserve pit or may impose more stringent 
pit construction and reclamation requirements. Drilling pits and 
reserve pits shall not be located in, or hazardously near, bodies of 
water, nor shall they block natural drainages. No pit shall be wholly 
or partially constructed in fill dirt unless approved by the state. 
N.D. Admin. Code 43-02-03-19.4, 19.5 (2012). 

Ohio: 
Drilling permits for urbanized areas are conditioned on the state 
receiving direct notification at least 48 hours prior to pit 
construction. All pits used for temporary storage of saltwater and oil 
field wastes shall not be used in an area that is subject to flooding 
by streams, rivers, lakes, or drainage ditches, unless so constructed 
that the pits would not normally be affected by flooding. Ohio Admin. 
Code Ann. 1501:9-1-02,-3-08 (2012). 

Pennsylvania: 
Generally, pits for the control, storage, and disposal of production 
fluids may not be located within 100 feet of a stream, body of water, 
or wetland. Pits for the disposal of drill cuttings may not be located 
within 100 feet of a stream, body of water, or wetland unless 
otherwise permitted, and may not be located within 200 feet of a water 
supply. Pits for the disposal of residual waste may not be located 
within 100 feet of a stream, body of water, or wetland or within 200 
feet of a water supply. Generally, pit bottoms must be at least 20 
inches above the seasonal high groundwater table. 25 Pa. Code § 78.56, 
57, .61, .62 (2012). 

Texas: 
No commercial oil and gas waste disposal pits may be constructed in 
any coastal natural resource area[B] and all oil and gas waste 
disposal pits shall be designed to prevent releases of pollutants that 
adversely affect coastal waters or critical areas. 16 Tex. Admin. Code 
§ 3.8 (2012).c. 

Wyoming: 
Owners or operators must obtain state approval for the location of 
noncommercial centralized pits, reserve pits, and workover and 
completion and produced water pits proposed for critical areas. Pits 
in critical areas include those located within Ľ mile of water 
supplies, areas where groundwater is less than 20 feet from the 
surface, locations which are within 500 feet of wetlands, ponds, 
lakes, perennial drainages or within a floodplain, and areas where pit 
fluids are greater than 10,000 mg/l total dissolved solids. When a 
retaining pit is located in an area with a high potential for 
communication between pit contents and surface water or shallow 
groundwater, or to protect people, livestock, or wildlife, the state 
may require changes to plans including running a closed system, lining 
the pit, or installing monitoring systems and providing additional 
reporting. In areas where groundwater is less than 20 feet below the 
surface, a closed system must be utilized. Generally, pits cannot be 
located closer than 350 feet from water supplies. 055-000-001 Code 
Wyo. R. § 2; 055-000-003 Code Wyo. R. § 22; 055-000-004 Code Wyo. R. § 
1 (2012). 

Pit lining requirements: 

Colorado: 
Certain pits, including drilling pits for fluids containing 
hydrocarbon or chloride concentrations exceeding certain levels; 
production pits in certain regions unless the quality of the produced 
water is as good or better than that of the underlying groundwater or 
seepage will not reach the underlying aquifer or waters of the state 
at levels in excess of applicable standards; special purpose pits 
excluding emergency pits and certain flare pits; skim pits; and 
multiwell pits in certain regions used to contain produced water, 
drilling fluids, or completion fluids that will be recycled or reused, 
must be lined if they were constructed after Spring of 2009. Liners 
shall be synthetic, impervious, have high puncture and tear strength 
and adequate elongation, and be resistant to ultraviolet light 
deterioration, weathering, hydrocarbons, acids, alkali, fungi and 
other substances in produced water. All pit lining systems shall be 
designed, constructed, installed, and maintained in accordance with 
the manufacturers' specifications and good engineering practices. 
Field seams must be installed and tested in accordance with 
manufacturer specifications and good engineering practices. Unless an 
operator can demonstrate equivalent protection with an alternative 
system, liners for on-site pits must also meet the following 
requirements. Liners shall have a minimum thickness of 24 mils and 
must cover bottom and insides of pit with enough overhang to be 
secured in a 12-inch anchor trench. Foundation for the liner shall be 
constructed with (1) at least 12 inches of soil compacted such that 
the amount of liquid it can conduct does not exceed 1.0 x 10 [-7] 
centimeters per second or (2) with other material if two liners of at 
least 24 mils in thickness are used and the pit bottom and sides are 
padded and free of material that could puncture the liner. In 
Sensitive Areas, a leak detection system, increased record-keeping, 
monitoring, or underlying gravel fill sumps and lateral systems may be 
required. 2 Colo. Code Regs. § 404-1(904) (2012). 

North Dakota: 
Generally, no saltwater, drilling mud, crude oil, waste oil, or other 
waste shall be stored in earthen pits or open receptacles except in an 
emergency and upon state approval. A lined earthen pit or open 
receptacle may be temporarily used to retain oil, water, cement, 
solids, or fluids generated in well completion, servicing, or 
plugging. Such a pit or receptacle must be sufficiently impermeable to 
provide adequate temporary containment. Pit contents must be removed 
within 72 hours after operations have ceased and disposed of at an 
authorized facility. Freshwater pits must also be lined. N.D. Admin. 
Code 43-02-03-19.3 (2012). 

Ohio: 
No requirements identified in regulations or in statutes, though pits 
used for the temporary storage of saltwater and oil field wastes shall 
be "liquid tight." Ohio Admin. Code Ann. 1501:9-3-08 (2012). 

Pennsylvania: 
Pits used for temporary containment, for control, storage, and 
disposal of production fluids, and for disposal of residual waste must 
be lined. Liners must meet a specific permeability threshold and be of 
sufficient strength and thickness to maintain the integrity of the 
liner. For pits other than those used for temporary containment, the 
minimum liner strength must be 30 mils. Liners shall be sealed 
together to prevent leakage in accordance with the manufacturer's 
directions. The liner shall be designed, constructed, and maintained 
so that the physical and chemical characteristics of the liner are not 
adversely affected by the waste and the liner is resistant to 
physical, chemical, and other failure during transportation, handling, 
installation, and use. Alternate liners or materials may be approved. 
Pits must be smooth so they do not tear the liner and must be able to 
bear the weight of their contents without settling that may affect the 
liner integrity. If the pit bottom or sides consist of rock, shale, or 
other materials that may cause the liner to fail, a subbase of at 
least 6 inches of soil, sand, or smooth gravel, or sufficient amount 
of an equivalent material, shall be installed over the area as the 
subbase for the liner. 25 Pa. Code §§ 78.56, .57, .62 (2012). 

Texas: 
A permit issued to maintain or use any lined pit for storage or 
disposal of oil field brines or other mineralized waters will contain 
requirements relating to liner material, thickness, procedures for 
installing liners, schedules for inspecting and/or replacing liners. A 
permit issued to maintain or use a pit for storage of oil field fluids 
or oil and gas wastes may contain such requirements. 16 Tex. Admin. 
Code § 3.8 (2012). 

Wyoming: 
Before drilling commences, approval to construct reserve pits must be 
applied for and received. Special precautions, including an 
impermeable liner and/or membrane, shall be taken if necessary to 
prevent water contamination and where drilling is conducted close to 
water supplies, residences, schools, hospitals, or other structures. 
Unlined pits shall not be constructed in fill. Lining of pits with 
reinforced oilfield grade material, compatible with the waste to be 
received, will be required under certain circumstances including pits 
proposed to be constructed in critical areas as well as on sites with 
sandy soils, shallow groundwater, in groundwater recharge areas, or 
sites immediately adjacent to the Green River or the Colorado River 
drainage and other sensitive environments or circumstances. Pits 
constructed in fill or those used to retain oil base drilling muds, 
high-density brines, and/or completion or treating fluids must be 
lined. Pits constructed to retain produced water with a total 
dissolved solids concentration in excess of 10,000 mg/l must be lined. 
Pits retaining water with a total dissolved solids concentration less 
than 10,000 mg/l may be required to be lined on a case-by-case basis. 
Soil mixture liners, recompacted clay liners, and manufactured liners 
must be compatible with the waste contained. Synthetic liners must 
meet the following specifications: a 9 to 12 mil thickness, greater 
than 20% elongation at failure, puncture strength of 60 lbs, tear 
strength of 50 lbs, and permeability less than 10-7 cm/sec. Joints 
must be overlapped at least 2 inches and seams sealed per manufacturer 
recommendation. Blemishes, holes, or scars must be repaired per 
manufacturer recommendation. Breaches for equipment must be 
reinforced. Slopes shall not exceed 3:1 for soil mixture or 
recompacted liners or 1:1 for manufactured liners. Reasonable 
provisions for protection of liners during filling and emptying 
activities must be included in the construction plans. Manufactured 
liners must be installed over smooth fill that is free of pockets or 
materials which could damage the liner. Sand, sifted dirt ,or 
bentonite are suggested. At no time will straw or any other organic 
material except synthetic cushion fabric designed for that purpose be 
used for a liner cushion. Installation of synthetic or soil mixture 
liners must be in accordance with accepted engineering practice. Liner 
edges must be secured by placing in a trench which is deep enough to 
receive approximately 1' of compacted soil which will anchor the 
material. 055-000-003 Code Wyo. R. § 22, 055-000-004 Code Wyo. R. § 1 
(2012). 

Freeboard[D] and secondary containment requirements for pits and tanks: 

Colorado: 
* Pits shall be constructed, monitored, and operated to provide for a 
minimum of 2 feet of freeboard at all times between the top of the pit 
wall at its point of lowest elevation and the fluid level of the pit. 
A method of monitoring and maintaining freeboard shall be employed; 
* For new operations at new locations within the intermediate buffer 
zone surrounding a public water system and certain operations that 
create a new surface disturbance but were otherwise in existence 
before the spring of 2009 and are in the internal buffer zone 
surrounding a public water system, flowback and stimulation fluids 
must be contained within tanks that are either on the well pad or in 
an area with downgradient perimeter berming. Berms or other 
containment devices must be constructed around crude oil, condensate, 
and produced water storage tanks. Tanks containing oil, condensate, or 
produced water with greater than 3,500 mg/l total dissolved solids 
shall have secondary containment sufficient to hold the contents of 
the largest single tank and enough freeboard for precipitation. 2 
Colo. Code Regs. §§ 404-1(317B, 604, 902, 906) (2012). 

North Dakota: 
When necessary to prevent pollution of the land surface and 
freshwaters, the state may require the drill site to be sloped and 
diked. Pits containing drill cuttings and other solids must be diked 
so as to prevent surface water from running into the pit. Dikes must 
be erected and maintained around oil tanks at any production facility 
and saltwater tanks at any saltwater handling facility built or 
rebuilt on or after July 1, 2000, within 30 days after the well has 
been completed. Dikes must be erected and maintained around tanks and 
facilities built earlier when deemed necessary by the state. Dikes as 
well as the base material under the dikes and within the diked area 
must be constructed of sufficiently impermeable material to provide 
emergency containment. Dikes must be of sufficient dimension to 
contain the total capacity of the largest tank plus 1 day's fluid 
production. The required capacity of the dike may be lowered if need 
can be demonstrated. Discharged saltwater liquids or brines must be 
properly removed and may not be allowed to remain standing within or 
outside of any diked areas. N.D. Admin. Code 43-02-03-19, -19.4, -49, -
53 (2012). 

Ohio: 
All pits shall have a continuous embankment surrounding them 
sufficiently above the level of the surface to prevent surface water 
from entering. In order to protect life, health, and property the 
state may require where a clear and present hazard exists that any 
producing equipment at the well-head and related storage tanks be 
protected by an earthen dike or earthen pit that shall have a capacity 
sufficient to contain any substances resulting, obtained, or produced 
in connection with the operation of the related oil or gas well. The 
dike or pit shall be maintained for the purpose for which it was 
constructed, and the reservoir within shall be kept reasonably free of 
water and oil. Ohio Admin. Code Ann. 1501:9-3-08, 1501:9-9-05 (2012). 

Pennsylvania: 
* Pits used for temporary containment or the control, storage, and 
disposal of production fluids must maintain 2 feet of freeboard at all 
times. If open tanks are used for temporary containment, 2 feet of 
freeboard must remain at all times unless the tank is provided with an 
overflow system with sufficient volume. If an open standby tank is 
used, it shall be maintained with 2 feet of freeboard. If this 
requirement is violated, the operator immediately shall take the 
necessary measures to ensure the structural stability of the pit or 
tank, prevent spills, and restore the 2 feet of freeboard; 
* See above for secondary containment provisions applicable 
specifically to unconventional wells. In addition, if an owner or 
operator uses a tank with a capacity of at least 660 gallons or tanks 
with a combined capacity of at least 1,320 gallons to contain oil 
produced from a well, the owner or operator shall construct and 
maintain a dike or other method of secondary containment that 
satisfies the requirements of certain federal rules[E] around the tank 
or tanks which will prevent the tank contents from entering waters of 
this Commonwealth. The containment area shall have capacity sufficient 
to hold the volume of the largest single tank, plus a reasonable 
allowance for precipitation based on local weather conditions and 
facility operation. 25 Pa. Code §§ 78.56, .57, .64 (2012). 

Texas: 
A permit to maintain or use a pit for storage of oil field fluids or 
oil and gas wastes may contain requirements including dike design, 
overflow warning devices, and leak detection devices. 16 Tex. Admin. 
Code 3.8 (2012). 

Wyoming: 
Operators are reminded to comply with federal regulations[F] that 
require facilities to construct appropriate containment or 
diversionary structures or equipment to prevent discharged oil from 
reaching waters of the United States. Liquids in pits must be kept at 
a level that takes into account extreme precipitation events and 
prevents overtopping and unpermitted discharges. 055-000-004 Code Wyo. 
R. §§ 1, 4 (2012). 

Pit closure requirements: 

Colorado: 
All pits unnecessary for further operations, excluding the drilling 
pit, must be backfilled as soon as possible after the drilling rig is 
released to conform with surrounding terrain. Drill pits must be 
closed after drilling and completion activities conclude: no more than 
3 months later for crop land, and no more than 6 months for noncrop 
land. Drilling fluids must be removed from drill pits and soils must 
meet contaminant concentration levels specified in the rules. Material 
removed from the pit for drying shall be returned prior to 
backfilling, and only de minimis amounts may be incorporated into 
surface material. Dry pits shall be backfilled to return soils to 
their original relative positions. Subsidence within 2 years must be 
corrected. On crop land, or within the 100-year floodplain, 
reclamation shall not form an impermeable barrier in the pit and at 
least 3 feet of backfill shall be applied over any remaining drilling 
pit contents. Emergency pits shall be closed and remediated as soon as 
the initial phase of emergency response operations are complete or 
process upset conditions are controlled. Upon plugging of a well, all 
other pits must be backfilled. Pits other than drilling pits must be 
closed in accordance with a remediation plan approved by the state. 
General site investigation and remediation requirements include a 
sensitive area determination, sampling and analysis of soil and 
groundwater to determine the extent of any contamination, removal and 
management of exploration and production waste, and remediation of 
contaminated soil and groundwater. Synthetic liners must be removed 
and disposed of. Constructed soil liner material may be removed for 
treatment or disposal, or ripped and mixed with native soils such that 
it continues to meet applicable soil concentration levels. Pits must 
be backfilled to return the soils to their original relative 
positions. If there is subsidence, additional topsoil shall be added 
and the land shall be releveled as close to its original contour as 
practicable. 2 Colo. Code Regs. § 404-1 (1003, 905, 909, 1004) (2012). 

North Dakota: 
A lined earthen pit or open receptacle may be temporarily used to 
retain oil, water, cement, solids, or fluids generated in well 
completion, servicing, or plugging operations. The contents of earthen 
pits or open receptacles must be removed within 72 hours after 
operations have ceased and must be disposed of at an authorized 
facility. Pits must be reclaimed and open receptacles must be removed 
within 30 days after operations have ceased. Drill cuttings and solids 
generated during well drilling and completion may be buried in pits 
provided that the pit can be reclaimed in a way that will prevent 
pollution of the land surface and freshwaters. Drilling pits must be 
reclaimed within 30 days after drilling or the expiration of a 
drilling permit. Reserve pits can be used in certain circumstances to 
contain certain solids and fluids used and generated during well 
drilling and completion operations, provided that the pit can be 
reclaimed in a manner that will prevent pollution of the land surface 
and freshwaters. Reserve pits must be reclaimed within a year of the 
completion of a shallow well or prior to drilling below the surface 
casing shoe on any other well. Prior to reclaiming a pit, approval of 
a pit reclamation plan must be obtained from the state. Any water or 
oil accumulated on the pit must be removed prior to reclamation. 
Drilling waste shall be encapsulated in the pit and covered with at 
least 4 feet of backfill and topsoil and surface sloped, when 
practicable, to promote surface drainage away from the reclaimed pit 
area. In certain circumstances, the state may impose more stringent 
reclamation requirements for pits. N.D. Admin. Code 43-02-03-19.3, -
19.4, -19.5 (2012). 

Ohio: 
Each drilling permit issued in an urbanized area will be conditioned 
on the state receiving direct notification a minimum of 48 hours prior 
to pit closure. Pits may be used for the temporary storage of 
saltwater and oil field wastes but no pit may be used for the ultimate 
disposal of saltwater. Saltwater and oil field wastes must be drained 
or removed and properly disposed of periodically, at intervals not to 
exceed 180 days. Pits may be used for the temporary storage of frac-
water and other liquid substances produced from the fracturing 
process, but upon termination of the fracturing process, pits not 
otherwise permitted shall be emptied, the contents disposed of and the 
pits filled in, unless this requirement is waived or extended. Within 
14 days after the date upon which the drilling of a well is completed 
to total depth in an urbanized area and within 2 months after the date 
upon which the drilling is completed in all other areas, the owner or 
his agent, in accordance with a restoration plan filed with the state, 
must fill all the pits for containing brine and other waste substances 
resulting, obtained, or produced in connection with exploration or 
drilling for oil or gas that are not required by other state or 
federal law or regulation. Ohio Admin. Code Ann. 1501:9-1-02, -3-08 
(2012); Ohio Rev. Code Ann. § 1509.072 (2012). 

Pennsylvania: 
Generally, pits used for temporary containment must be removed or 
filled within 9 months after completion of drilling or within 90 days 
of construction for pits used during servicing, plugging, and 
recompleting. Upon abandonment of a well, the operator shall restore 
pits used to store production fluids by removing and disposing of the 
contents of the pit, including the liner. The pit shall be backfilled 
to the ground surface. Dewatered, uncontaminated drill cuttings may be 
buried at the site where they were generated in structurally sound 
pits. The pit must be backfilled to the ground surface. Residual 
waste,[G] including contaminated drill cuttings, may be buried at the 
site where it was generated in structurally sound, impermeable, lined 
pits. Free liquid must be removed from the pit prior to waste 
encapsulation and a liner must cover the contents so that water does 
not infiltrate. The pit shall be backfilled to at least 18 inches over 
the top of the liner. Residual waste may not be disposed of at the 
well site if it exceeds specified concentrations. In all cases, 
backfilled pits must be graded to promote runoff with no depressions. 
The stability of backfilled pits must be compatible with the adjacent 
land. The surface of the backfilled pit must be revegetated or 
otherwise stabilized against accelerated erosion consistent with land 
use. 25 Pa. Code §§ 78.56, .57, .61, .62 (2012). 

Texas: 
A person who maintains or uses a reserve pit, mud circulation pit, 
fresh makeup water pit, fresh mining water pit, completion/workover 
pit, basic sediment pit, flare pit, or water condensate pit shall 
dewater, backfill, and compact the pit. Reserve pits and mud 
circulation pits must be closed within a year of the completion of 
drilling operations; if they contain fluids exceeding a certain 
chloride concentration, they must be dewatered within 30 days. All 
completion/workover pits shall be dewatered within 30 days and closed 
within 120 days of well completion or workover. Basic sediment pits, 
flare pits, freshwater pits, and water condensate pits shall be 
dewatered and closed within 120 days of cessation of use. The state 
may require that pits be backfilled sooner if oil and gas wastes or 
oil field fluids are likely to escape from the pit or the pit is being 
used for improper storage or disposal of oil and gas wastes or oil 
field fluids. Prior to backfilling, all oil and gas wastes which are 
in the pit must be disposed of. 16 Tex. Admin. Code 3.8 (2012). 

Wyoming: 
If the pit is proposed to be closed through the usual method of on-
site natural evaporation and subsequent burial of solids, if pit 
treatment procedures are going to be applied, or if closure plans have 
changed from the original proposal, or any time wastes are disposed 
off-site, a notice must be submitted and approved prior to closure. 
Oil and Gas Conservation Commission staff must be provided the 
opportunity to witness closure. Verbal notice of at least 24 hours 
prior to closure is required. Oil, water, and other fluids must be 
immediately removed from temporary emergency pits and disposed. 
Trenching or squeezing pits is expressly prohibited. Burial methods 
cannot compromise the integrity of manufactured, soil mixture, or 
recompacted clay liners without written approval. Closure standards 
and testing requirements for all pits will be determined by the state 
based on site-specific conditions. Pit solids showing high 
concentrations of salt must be removed from the location and disposed 
in a permitted facility, encapsulated, or chemically or mechanically 
treated. When drilling with oil-based muds, oil-based mud solids must 
be removed and disposed in a permitted facility; solidified using a 
commission-approved commercial pit treatment, roadspread, landspread, 
landfarmed; or, bioremediated. Burial after encapsulation or 
solidification will be approved if the stabilized mixture contains 
less than 10 mg/l leachable oil and less than 5,000 mg/l leachable 
dissolved solids. Reserve pits containing oil, sheens, condensate, 
other hydrocarbons or chemicals proven to be hazardous shall undergo 
fluid removal as soon as practical or shall be fenced and netted to 
avoid loss of animals and birds. The state may require testing of 
wastes and additional disposal requirements prior to closure of a pit 
if it has reason to believe exempt exploration and production wastes 
have been commingled with hazardous wastes. An Operator or Owner 
wishing to treat pits for closure must submit to the commission a plan 
outlining the objectives that the treatment is designed to achieve. 
Production pit areas and reserve pits will be reclaimed after they 
have dried sufficiently following the removal of any oil, sheens, or 
other hydrocarbons, or if they contain hazardous chemicals. Pits used 
solely for water retention in coalbed methane areas in the Powder 
River Basin may be left open with state approval at the landowner's 
request. 055-000-004 Code Wyo. R. § 1 (2012). 

Source: GAO analysis of state information. 

[A] Generally, operations may not occur at all within the internal 
buffer zone surrounding a public water system, so pits may not be 
located there either. 

[B] A coastal natural resource areas include coastal barriers, coastal 
historic areas, coastal preserves, coastal shore areas, coastal 
wetlands, critical dune areas, critical erosion areas, gulf beaches, 
hard substrate reefs, oyster reefs, submerged lands, special hazard 
areas, submerged aquatic vegetation, tidal sand or mud flats, water in 
the open Gulf of Mexico, or water under tidal influence, as these 
terms are defined in Texas law. 

[C] In addition, according to Texas state officials, permit 
applications for waste management are evaluated to determine proximity 
to sensitive areas and may be denied if the proposed facility is to be 
located in or near a sensitive area. "Sensitive areas" are "defined by 
the presence of factors, whether one or more, that make an area 
vulnerable to pollution from crude oil spills. Factors that are 
characteristic of sensitive areas include the presence of shallow 
groundwater or pathways for communication with deeper groundwater; 
proximity to surface water, including lakes, rivers, streams, dry or 
flowing creeks, irrigation canals, stock tanks, and wetlands; 
proximity to natural wildlife refuges or parks; or proximity to 
commercial or residential areas." 16 Tex. Admin. Code § 3.91 (2012). 

[D] Freeboard is the height that is above the recorded highwater mark 
of a structure associated with a body of water and that is an 
allowance against overtopping by waves or other transient disturbances. 

[E] 40 C.F.R. pt. 112 (2011) (relating to oil pollution prevention). 

[F] 40 C.F.R. pt. 112 (2011) (relating to oil pollution prevention). 

[G] "Residual waste" means any garbage, refuse, other discarded 
material or other waste including solid, liquid, semisolid, or 
contained gaseous materials resulting from industrial, mining and 
agricultural operations and any sludge from an industrial, mining or 
agricultural water supply treatment facility, waste water treatment 
facility or air pollution control facility, provided that it is not 
hazardous. 

[End of table] 

Table 18: Selected State Requirements--Waste Management through 
Underground Injection[A]: 

Requirements regarding existing wells: 

Colorado: 
Application for a well shall include (1) plan of the area within 1/4 
mile of the proposed disposal well showing the location of all oil and 
gas wells, domestic and irrigation wells of public record; 
and (2) the identification of all oil and gas wells currently 
producing from the proposed injection zone within 1/2 mile of the 
disposal zone. Remedial action shall be required for any well within 
one-quarter (1/4) mile of the proposed disposal well in which the 
injection zone is not adequately confined. The application must 
identify the need for such remedial action and a plan for the 
performance of such work. 2 Colo. Code Regs. § 404-1 (325) (2012). 

North Dakota: 
Applications must include a plat of the area of review (1/4-mile 
radius) and detailing the location, well name, and operator of all 
wells in the area of review. The plat should include all injection 
wells, producing wells, plugged wells, abandoned wells, drilling 
wells, dry holes, and water wells. The application is also to identify 
the need for corrective action on wells penetrating the injection zone 
in the area of review. Before injection commences in an underground 
injection well, the applicant must complete any needed corrective 
action on wells penetrating the injection zone in the area of review. 
N.D. Admin. Code 43-02-05-04 (2012). 

Ohio: 
Application to include a map showing the geographic location of all 
wells penetrating the formation proposed for injection, regardless of 
status, within the area of review (Ľ mile to ˝ mile from the well 
depending on its volume). Application must also include a proposed 
corrective action of wells penetrating the proposed injection 
formation or zone within the area of review, if required to ensure the 
injection well will not cause or allow movement of fluid into a source 
of underground water. Ohio Admin. Code Ann. 1501:9-3-06, 9-3-12 
(2012)[B]. 

Pennsylvania[C]: 
Operator must identify the location of all known wells in the area of 
review that penetrate the injection zone (or for wells operating over 
the fracture pressure of the injection formation, all known wells in 
the area of review penetrating formations affected by the increase in 
pressure). For such wells that are improperly sealed, completed, or 
abandoned, the operator shall also submit a plan of actions necessary 
to prevent movement of fluid into underground sources of drinking 
water (Requirements regarding existing wells: ("corrective action"); 
status of corrective actions is considered in permit review and a 
compliance schedule may be a permit condition.[D,E] 40 C.F.R. §§ 
144.31, 144.55, 146.7, 146.24 (2012). 

Texas: 
Applicants shall, based on review of the public record, identify wells 
that penetrate the proposed disposal zone within a 1/4 mile radius of 
the proposed disposal well to determine if all abandoned wells have 
been plugged in a manner that will prevent the movement of fluids from 
the disposal zone into freshwater strata, and identify any wells which 
appear to be unplugged or improperly plugged and any other such wells 
of which the applicant has actual knowledge; unless a variance is 
granted. (No specific regulatory provision for corrective action.[F]) 
16 Texas Admin. Code § 3.9 (2012). 

Wyoming: 
Application to include plan showing the location of the disposal well 
or wells, including abandoned and drilling wells and dry holes; 
and investigation of mechanical conditions of all wells which have 
penetrated the disposal zone within 1/4 mile radius of the proposed 
disposal well. Wyo. Code R. 055-000-004 § 5 (2012). 

Casing/cementing: 

Colorado: 
No specific requirements for disposal wells, but applications must 
include information on casing and cement bond log.[G,H] (See also 
integrity testing.) 2 Colo. Code Regs. § 404-1 (325) (2012). 

North Dakota: 
All injection wells shall be cased and cemented to prevent movement of 
fluids into or between underground sources of drinking water or into 
an unauthorized zone. The casing and cement used in construction of 
each new injection well shall be designed for the life expectancy of 
the well. In determining and specifying casing and cementing 
requirements, all of the following factors shall be considered: 
* depth to the injection zone; 
* depth to the bottom of all underground sources of drinking water; 
* estimated maximum and average injection pressures; 
* fluid pressure; 
* estimated fracture pressure, and; 
* physical and chemical characteristics of the injection zone; 
N.D. Admin. Code 43-02-05-06 (2012). 

Ohio: 
Surface casing shall be free of apparent defects and set at least 50 
feet below the deepest underground source of water containing less 
than 10,000 mg/L chlorides, and sealed by circulating cement to the 
surface under the supervision of the state. Casing to be mechanically 
centralized and enclosed in cement to a height no less than 300 feet 
above the top of the injection zone. The cement bond log or cement 
records are to be submitted, or the state is to verify the number of 
sacks of cement. State inspector to be notified in advance. Ohio 
Admin. Code Ann. 1501:9-3-05 (2012). 

Pennsylvania: 
Wells shall be cased and cemented to prevent movement of fluids into 
or between protected aquifers.[I] Surface casing shall be installed 
and cemented from the surface to at least 50 feet below the base of 
the lowermost protected aquifer, and for brine disposal wells, install 
long string casing and tubing extending to the injection zone and 
cement to a point 50 feet above the injection zone. Design shall 
consider the depth to injection zone, depth to the bottom of the 
aquifer, and the estimated injection pressures. 40 C.F.R. §§ 
146.22,147.1955 (2012). 

Texas: 
Disposal wells shall be cased and the casing cemented in such a manner 
that the injected fluids will not endanger oil, gas, geothermal 
resources, or freshwater resources. Disposal wells must meet casing 
and cementing requirements for production wells, such as: 
* use of pressure-tested steel casing; 
* anchoring of casing; 
* all usable-quality water zones must be isolated and sealed off to 
effectively prevent contamination or harm; 
* requirements for surface, intermediate, and production casing; 
* cementing by the pump and plug method; and; 
* pressure-test standards during cementing; 
16 Texas Admin. Code §§ 3.9, .13 (2012). 

Wyoming: 
Disposal wells shall be cased and the casing cemented in such a manner 
that damage will not be caused to oil, gas, or freshwater sources. The 
disposal application shall include a description of the casing in the 
disposal well or wells, or the proposed casing program and the 
proposed method for testing casing before use of the disposal well or 
wells. Wyo. Code R. 055-000-004 § 5 (2012). 

Operating pressure requirements: 

Colorado: 
Operator to indicate operating pressures on application. Maximum 
injection pressure will be set by the Director upon approval. 2 Colo. 
Code Regs. § 404-1 (325) (2012). 

North Dakota: 
Injection pressure at the wellhead shall not exceed a maximum that 
shall be calculated so as to assure that the pressure in the injection 
zone during injection does not initiate new fracture or propagate 
existing fractures in the confining zone adjacent to the freshwater 
resource. In no case shall injection pressure initiate fractures in 
the confining zone or cause the movement of injection or formation 
fluids into an underground source of drinking water. N.D. Admin. Code 
43-02-05-09 (2012). 

Ohio: 
The maximum allowable operating pressure for any injection well shall 
be determined by a formula or method approved by the state. Under no 
circumstances shall liquids or waste matter from any source, other 
than saltwater from oil and gas operations or standard well treatment 
fluid, be injected into any injection well. Ohio Admin. Code Ann. 
1501:9-3-07, -08 (2012). 

Pennsylvania: 
Injection pressure shall not exceed maximum calculated to prevent new 
or propagation of fractures in the confining zone and shall not cause 
movement of injection or formation fluids into a protected aquifer. 40 
C.F.R. §§ 144.51, 146.23 (2012). 

Texas: 
Authorized pressure based on pressure test; 
regulations do not specify limit or formula. 16 Texas Admin. Code § 
3.9 (2012). 

Wyoming: 
Regulations do not specify limit or formula.[J]. 

Monitoring/reporting requirements: 

Colorado: 
Monthly reports are required, and are to include: types of chemicals 
used to treat injection water; the date of initial fluid injection for 
new injection wells; and the type and amount of fluids. Operators must 
record and report the volume of produced water; the volume of water 
injected into a Class II dedicated injection well; and the volume of 
water injected and produced in simultaneous injection wells. 2 Colo. 
Code Regs. §§ 404-1 (316A, 330) (2012). 

North Dakota: 
The operator of an injection well shall meter or use an approved 
method to keep records and shall report monthly, including: 
* volume and nature (produced water, makeup water, etc.) of the fluid 
injected, 
* the injection pressure, and; 
* such other information as may be required; 
Reports are required after completion or recompletion, or any remedial 
work that includes a detailed account of all work done, including the 
reason for the work; the date; the shots per foot, and size and depth 
of perforations; the quantity of sand, crude, chemical, or other 
materials employed in the operation; the size and type of tubing; 
the type and location of packer; the result of the packer pressure 
test; and other pertinent information that affects the status of the 
well. N.D. Admin. Code 43-02-05-12 (2012). 

Ohio: 
Operator to monitor injection pressures and injection volumes daily, 
with average and maximum pressures and volumes compiled monthly and 
filed annually. (See also mechanical integrity testing.) Ohio Admin. 
Code Ann. 1501:9-3-07 (2012).[B]. 

Pennsylvania
Permits are to specify monitoring requirements, including: 
(1) representative monitoring of the nature of injected fluids; 
(2) observation of injection pressure, flow rate, and cumulative 
volume (at specified frequencies depending on type of well and 
activity); and; 
(3) recording of injection pressure, flow rate and cumulative volume 
at least monthly; 
Results are to be summarized in an annual report. 40 C.F.R. §§ 144.54, 
146.23 (2012). 

Texas: 
The operator shall monitor the injection pressure and injection rate 
of each disposal well monthly and report results annually. The 
operator shall report within 24 hours any significant pressure changes 
or other monitoring data indicating the presence of leaks in the well. 
16 Texas Admin. Code § 3.9 (2012). 

Wyoming: 
Operators shall report the type and source of the injected substance, 
the total amount injected, and the injected pressures and casing-
tubing annulus pressure during injection. Wyo. Code R. 055-000-004 § 
10 (2012). 

Mechanical integrity testing: 

Colorado: 
Mechanical integrity tests are required initially and every 5 years to 
determine if there is:(1) a significant leak in the casing, tubing, or 
packer of the well, by pressure test, monthly pressure monitoring, or 
other approved test; and (2) any significant fluid movement into an 
underground source of drinking water through vertical channels 
adjacent to the wellbore, by tracer surveys, cement logs, temperature 
surveys, or other approved test. 2 Colo. Code Regs. § 404-1 (326) 
(2012). 

North Dakota: 
Operator of a new injection well must demonstrate the mechanical 
integrity of the well prior to commencing operations, and at least 
once every 5 years. An injection well has mechanical integrity if: (1) 
there is no significant leak in the casing, tubing, or packer 
(demonstrated via a pressure test with liquid or gas, monitoring of 
positive annulus pressure following a valid pressure test, or a 
radioactive tracer survey); and (2) there is no significant fluid 
movement into an underground source of drinking water or an 
unauthorized zone through vertical channels adjacent to the injection 
bore (demonstrated via a log from which cement can be determined or 
well records demonstrating the presence of adequate cement to prevent 
such migration or a radioactive tracer survey, temperature log, or 
noise log). N.D. Admin. Code 43-02-05-07 (2012). 

Ohio: 
Mechanical integrity to be documented by monitoring the annulus 
between the casing and tubing during injection of fluids at least 
monthly at a pressure sufficient to detect leaks, and reported 
annually. If such monitoring is not feasible, then once every 5 years 
the operator shall conduct mechanical integrity tests by pressure 
test, tracer surveys, noise logs; 
temperature surveys; 
or other approved test. Ohio Admin. Code Ann. 1501:9-3-07 (2012).[B]. 

Pennsylvania: 
Mechanical integrity to be established prior to initial injection and 
tested once every 5 years: 
(1) must demonstrate absence of leaks by either monitoring of annulus 
pressure or pressure test with liquid or gas; (2) must demonstrate no 
significant fluid movement by results of a temperature or noise log; 
or cementing records demonstrating the presence of adequate cement to 
prevent such migration. 40 C.F.R. §§ 144.51,146.8, 146.23 (2012). 

Texas: 
The mechanical integrity of a disposal well shall be evaluated by 
conducting pressure tests to determine whether the well tubing, 
packer, or casing have sufficient mechanical integrity to meet the 
prescribed performance standards. Each disposal well shall be tested 
for mechanical integrity prior to initial use, at least once every 5 
years, and after every workover of the well. Mechanical integrity to 
be demonstrated by pressure test, or an approved alternate method such 
as tubing-casing annular pressure monitoring. The operator shall 
notify the Railroad Commission at least 48 hours prior to the testing. 
A complete record of all tests shall be filed within 30 days after the 
testing. 16 Texas Admin. Code § 3.9 (2012). 

Wyoming: 
Mechanical integrity must be established by pressure testing at least 
once every 5 years to determine whether significant leaks are present 
in the casing, tubing, or packer. The initial mechanical integrity 
test for all disposal wells shall include one of the following tests 
to determine whether there are significant fluid movements in vertical 
channels adjacent to the wellbore: 
* tracer surveys; 
* cementing records with a cement bond log or other acceptable cement 
evaluation log; 
* temperature surveys; or; 
* any other test or combination of tests approved by EPA; 
Operators must provide the Oil and Gas Conservation Commission the 
opportunity to witness all integrity tests. If not witnessed, the 
Operator is required to provide documentation of the test to the 
commission. If normal testing, surveys, or monitoring schedules 
provide inconclusive proof of mechanical reliability, the commission 
shall require that other appropriate logs or additional well tests be 
performed. Wyo. Code R. 055-000-004 § 5 (2012). 

Approval prior to operation: 

Colorado: 
Yes. Each injection well must satisfactorily pass a mechanical 
integrity test prior to application approval and be approved prior to 
injection. 2 Colo. Code Regs. §§ 404-1 (325, 326) (2012). 

North Dakota: 
Unclear. Prior to commencing operations, the operator of a new 
injection well must demonstrate the mechanical integrity of the well. 
Regulations do not specify approval. N.D. Admin. Code 43-02-05-07 
(2012). 

Ohio: 
Yes. Initial pressure testing of annulus between the tubing and the 
casing outside the tubing, under supervision of state, required prior 
to commencing injection. Ohio Admin. Code Ann. 1501:9-3-05 (2012). 

Pennsylvania: 
Yes, unless alternative schedule approved by EPA. 40 C.F.R. § 144.51 
(2012). 

Texas: 
Mechanical integrity of each disposal well shall be demonstrated prior 
to initial use. 16 Texas Admin. Code § 3.9 (2012). 

Wyoming: 
Unclear. Testing required prior to operation. Regulations do not 
specify approval. Wyo. Code R. 055-000-004 § 5 (2012). 

Plugging: 

Colorado: 
The operator must obtain approval from the Director of the plugging 
method prior to plugging and shall notify the Director of the 
estimated time and date the plugging operation of any well is to 
commence and identify the depth and thickness of all known sources of 
groundwater. Abandoned wells must be plugged in such a manner that 
oil, gas, water, or other substance shall be confined to the reservoir 
in which it originally occurred. Any cement plug shall be a minimum of 
50 feet in length and shall extend a minimum of 50 feet above each 
zone to be protected. The top of the pipe must be sealed with either a 
cement plug and a screw cap, or cement plug and a steel plate welded 
in place or by other approved method, or marked with a permanent 
monument. All final reports of plugging and abandonment shall be 
submitted on a Well Abandonment Report and accompanied by a job log or 
cement verification report from the plugging contractor specifying the 
type of fluid used to fill the wellbore, type and slurry volume of 
American Petroleum Institute Class cement used, date of work, and 
depth the plugs were placed. 2 Colo. Code Regs. § 404-1 (319) (2012). 

North Dakota: 
Well must be plugged with cement or other types of plugs, or both, in 
a manner that will not allow movement of fluids into an underground 
source of drinking water. The operator shall file a notice of 
intention to plug and obtain approval of the plugging method prior to 
the commencement of plugging operations. N.D. Admin. Code 43-02-05-08 
(2012). 

Ohio: 
Abandoned wells shall be plugged in such a manner that oil, gas, 
water, or other fluids shall be confined to the reservoir rock in 
which it occurs or originates. All Class II saltwater injection, 
enhanced recovery and Class III solution mining wells must be plugged 
with cement. Operators may use any method of emplacing the plugging 
material approved by the state but not limited to dump bailer, 
bullhead, pumping through tubing, casing, or drill pipe. Regulations 
specify intervals, including but not limited to: 
* Wells must be plugged from total depth or a minimum of 50 feet below 
the base of the lowest reservoir rock penetrated to a minimum of 200 
feet above the top of the lowest reservoir rock penetrated; 
* From a minimum of 100 feet below to a minimum of 100 above the base 
of the surface casing; 
* From a minimum of 100 feet below the grade level to 30 inches below 
grade level; 
Each plugging operation shall be conducted under the supervision of an 
inspector. When plugging operations are not witnessed by an inspector, 
a plugging report is required. Ohio Admin. Code Ann. 1501:9-11-03, -
04, -08, -12 (2012). 

Pennsylvania: 
Operator must submit plugging plan consistent with requirements. Well 
shall be plugged with cement to not allow the movement of fluids 
either into or between protected aquifers; allowed methods include (i) 
the Balance method; (ii) the Dump Bailer method; (iii) the Two-Plug 
method; or (iv) an approved comparable alternative. Report required 
within 60 days of plugging, certifying compliance or providing updated 
plan. 40 C.F.R. §§ 144.32,144.51, 146.10 (2012). 

Texas: 
Disposal wells shall be plugged upon abandonment. Disposal wells must 
meet plugging requirements for production wells, such as; 
* insure that all formations bearing usable quality water, oil, gas, 
or geothermal resources are protected; 
* cement plugs shall be set as necessary to separate multiple usable 
quality water strata by placing the required plug at each depth as 
determined by the Texas Commission on Environmental Quality; 
* cement plugs shall be placed by the circulation or squeeze method 
through tubing or drill pipe; 
* additional requirements for cement and cementing; and; 
* mud-laden fluid of at least 9-1/2 pounds per gallon with a minimum 
funnel viscosity of 40 seconds shall be placed in all portions of the 
well not filled with cement; 
The operator shall give the Railroad Commission advance notice of its 
intention to plug, and shall not commence the work until the proposed 
procedure has been approved. All cementing operations during plugging 
shall be performed under the direct supervision of the operator or his 
authorized representative. 16 Texas Admin. Code § 3.9, 3.14 (2012). 

Wyoming: 
Wells must be plugged in a manner sufficient to properly protect all 
freshwater bearing formations and possible or probable oil or gas 
bearing formations. Plugging must be accomplished by the following: 
* All cement and additives shall consist of API class cement and 
additives; 
* Wells with production casing must be plugged by placing cement plugs 
of at least 100 foot length at least every 2,500 feet, in the base of 
the surface casing, and at least 100 feet inside the casing at the 
surface. If multiple casing strings are present, a minimum 100-foot 
plug must be placed in the annulus between each casing string at the 
outside casing shoe, and a minimum 100-foot plug in each annulus at 
the surface; 
* Regulations include other conditions of plugging, including 
requirements related to cement volume, perforations, and casing; 
Verbal approval to plug and abandon must be obtained prior to 
commencing actual plugging operations. When the well has been plugged, 
a notarized Subsequent Report of Abandonment accompanied by a job log 
or cement verification report from the plugging contractor specifying 
the type of fluid used to fill the wellbore, type of slurry volume of 
API Class cement used, date of work, and depth of plugs placed must be 
submitted to the Oil and Gas Conservation Commission. Wyo. Code R. 055-
000-003 § 18 (2012). 

Seismicity: 

Colorado: 
None identified. According to Colorado Oil and Gas Commission 
documents, its UIC permit review process was expanded in September 
2011 to include a review for seismicity by the Colorado Geological 
Survey, and if historical seismicity is identified in the vicinity, 
the commission may require an operator to define the seismicity 
potential and the proximity to faults through geologic and geophysical 
data prior to any permit approval.[L]. 

North Dakota: 
The application plan should depict faults, if known or suspected. All 
new injection wells shall be sited in such a fashion that they inject 
into a formation which has confining zones that are free of known open 
faults or fractures within the area of review. N.D. Admin. Code 43-02-
05-04, -05 (2012). 

Ohio: 
None identified.[B]. 

Pennsylvania: 
Wells must be sited to inject into a formation which is separated from 
any protected aquifer by a confining zone that is free of known open 
faults or fractures within the area of review, which is either 
calculated or a minimum area within 14 mile radius of the well. 
Applicant must identify faults if known or suspected within the area 
of review. 40 C.F.R. §§ 146.3, .6, .22, .24 (2012). 

Texas: 
None identified. 

Wyoming: 
None identified. 

Source: GAO analysis of state information. 

[A] Requirements shown generally apply to new wells permitted after 
the early 1980s. Existing Class II wells, and new wells built in 
existing fields, were generally authorized by rule for up to five 
years from the effective date of the initial program, subject to 
conditions and requirements such as submission of inventory 
information. In Colorado, existing Class II enhanced recovery or 
hydrocarbon storage wells may be authorized by rule for the life of 
the well. Ohio requirements for annular disposal wells, enhanced 
recovery wells, and hydrocarbon storage wells may differ from those 
shown in this table. 

[B] Ohio Department of Natural Resources identified several reforms to 
its Class II deep injection well program, and proposed revisions to 
key regulations (1501:9-3-06, 9-3-07) including changes to 
application, testing, and monitoring requirements. See Ohio Department 
of Natural Resources, Preliminary Report on the Northstar 1 Class II 
Injection Well and the Seismic Events in the Youngstown, Ohio, Area 
(March 2012). In July 2012, the governor of Ohio signed an executive 
order determining that an emergency existed requiring the immediate 
adoption of the proposed rules. Rules filed as emergency rules remain 
in effect for 90 days, during which time Ohio Department of Natural 
Resources must go through the regular rule filing procedure. The 
emergency rules are undergoing public comment through August 31, 2012. 
Because the emergency rules are still subject to change through these 
processes, the table shows requirements as of June 2012, and does not 
reflect the emergency revisions. 

[C] EPA implements the UIC program in Pennsylvania, so the table shows 
federal requirements applicable in the state of Pennsylvania. 

[D] Requirements shown generally apply to new wells. Existing Class II 
wells were generally authorized by rule for up to five years from the 
effective date of the initial program, subject to conditions and 
requirements such as submission of inventory information. 40 C.F.R. § 
144.21 (2011). EPA officials said the expectation was that existing 
Class II wells authorized by rule for 5 years and allowed to continue 
operations until permitted would eventually apply for and operate 
under a permit. In Pennsylvania, the effective date of the federal UIC 
program was June 25, 1984. 

[E] See generally 40 C.F.R. §§147.1951-1955, 144.1(f), pts. 144, 146 
(2012). 

[F] According to Texas state officials, however, every injection well 
permit includes a condition that states that "should it be determined 
that such injection fluid is not confined to the approved interval, 
then the permission given herein is suspended and the disposal 
operation must be stopped until the fluid migration from such interval 
is eliminated." 

[G] Enhanced recovery or storage wells (e.g., wells used for injection 
of fluids into the producing formation) shall be cased with safe and 
adequate casing or tubing so as to prevent leakage, and shall be so 
set or cemented that damage will not be caused to oil, gas or 
freshwater resources. 2 Colo. Code Regs. § 404-1-404. 

[H] See also 40 C.F.R. § 147.305(d) (providing additional casing and 
cementing requirements that may be imposed by the EPA Regional 
Administrator). 

[I] In this table, "protected aquifer" refers to underground sources 
of drinking water; however, EPA UIC regulations define underground 
sources of drinking water as a subset of aquifers, namely an aquifer 
or its portion: (a)(1) Which supplies any public water system; or (2) 
which contains a sufficient quantity of groundwater to supply a public 
water system; and (i) currently supplies drinking water for human 
consumption; or (ii) contains fewer than 10,000 mg/l total dissolved 
solids; and (b) which is not an exempted aquifer. 40 C.F.R. § 144.3 
(2011). EPA estimates there are approximately 1,000-2,000 exempted 
portions of aquifers. 

[J] Disposal well permit applicants, are, however, required to submit 
evidence and data to support a state finding that the proposed 
disposal well will not initiate fractures through the overlying strata 
or confining zone which could enable the injection fluid or formation 
fluid to enter the freshwater strata. Wyo. Code R. 055-000-004 § 5 
(2012). According to Wyoming state officials, pressure limits were 
administratively set on all injection wells existing before Nov. 22, 
1982, and were set by orders on all Class II wells permitted after 
that time. 

[K] Only the initial tests are required for simultaneous injection 
wells. A simultaneous injection well is a well in which water produced 
from oil and gas producing zones is injected into a lower injection 
zone and such water production is not brought to the surface. 404-1-
100. 

[L] See Colorado Oil and Gas Commission, COGCC Underground Injection 
Control and Seismicity in Colorado (Jan. 19, 2011). 

[End of table] 

Table 19: Selected State Requirements--Managing Air Emissions: 

Requirements related to hydrogen sulfide gas (H2S): 

Colorado: 
When well servicing operations take place in zones known to or 
reasonably expected to contain at or above 100 parts per million of 
H2S, the operator shall file a H2S drilling operations plan. Any gas 
analysis indicating the presence of H2S shall be reported to the state 
and local government. 2 Colo. Code Regs. § 404-1(607) (2012). 

North Dakota: 
Production facilities that emit sulfur compounds are subject to 
registration and reporting requirements. Anticipated H2S content in 
produced gas from a proposed source of supply must be included in the 
application for permit to drill. The owner or operator of any oil or 
gas well production facility shall install equipment necessary to 
ensure that emissions comply with ambient air quality standards, 
including, but not limited to, H2S. Each flare used for treating gas 
containing H2S must be equipped and operated with an automatic ignitor 
or a continuous burning pilot that must be maintained in good working 
order. This is required even if the flare is used for emergency 
purposes only. Routine inspections and maintenance of tanks, hatches, 
compressors, vent lines, pressure relief valves, packing elements, and 
couplings must be conducted to minimize emissions from equipment used 
for gas containing H2S. Tank hatches must hold a positive working 
pressure or must be repaired or replaced. N.D. Admin. Code 33-15-20-
01,-02, -04; 43-02-03-16 (2012). 

Ohio: 
A well that yields H2S must be plugged with sulfate-resistant cement. 
In urbanized areas where there is a known occurrence of shallow gas or 
H2S, drilling on air may not be permitted, fluid drilling shall be 
required. During drilling, the state inspector shall require 
converting to fluid drilling where there is an imminent threat to 
safety of the rig crew and/or the public. Ohio Admin. Code Ann. 1501:9-
11-07, -9-03 (2012). 

Pennsylvania: 
An operator proposing to drill a well within a 1-mile radius of a well 
drilled to or through the same formation where H2S has been found 
while drilling shall install monitoring equipment during drilling at 
the well site to detect the presence of H2S in accordance with 
American Petroleum Institute publication API RP49, "Recommended 
Practices for Safe Drilling of Wells Containing H2S." When H2S is 
detected in concentrations of 20 parts per million or greater, the 
well shall be drilled in accordance with API RP49. An operator who 
operates a well in which H2S is discovered in concentrations of 20 
parts per million or greater shall operate the well in a way that 
presents no danger to human health or to the environment. When an 
operator discovers H2S in concentrations of 20 parts per million or 
greater during the drilling of a well, the operator shall notify the 
state and identify the location of the well and the concentration of 
H2S detected. The state will maintain a list of all notices that will 
be available to operators for their reference. 25 Pa. Code § 78.77 
(2012). 

Texas: 
H2S emissions from source(s) must not exceed a net ground level 
concentration of 0.08 parts per million averaged over 30 minutes if 
the downwind concentration affects a residential, business or 
commercial property; Certain storage tanks must be posted with a 
warning sign on or within 50 feet of the facility; fencing is required 
when tanks are located inside towns or cities, or where tanks are 
exposed to the public; tanks are also subject to certain marker and 
compliance provisions. Operations where the 100 parts per million 
radius of exposure is greater than 50 feet are subject to warning and 
marker, security, and materials and equipment provisions. Certain 
other operations where the radius of exposure includes public areas or 
is greater than 3,000 feet are also subject to control and equipment 
safety provisions. Drilling and workover operations where the 100 
parts per million radius of exposure is 50 feet or greater are subject 
to requirements related to protective breathing equipment; 
wind direction indicators installed; and automatic H2S detection and 
alarm equipment. Drilling and workover operations where the 100 parts 
per million radius of exposure includes a public area or is 3,000 feet 
or greater are subject to additional provisions relating to protective 
breathing equipment; methods of igniting the gas in the event of an 
uncontrollable emergency; installation of a choke manifold, mud-gas 
separator, and flare line and provision of a suitable method for 
lighting the flare; secondary remote control of blowout prevention and 
choke equipment; drill stem testing of H2S zones; certificates of 
compliance; pressure testing of blowout preventers and well control 
systems; and training. Operators may apply for exceptions. 30 Tex. 
Admin. Code § 112.31(2012); 16 Tex. Admin. Code § 3.36 (2012). 

Wyoming: 
All flaring operations shall be conducted in a safe and workmanlike 
manner. If the gas stream is sour or venting would present a safety 
hazard, a constant flare igniter system or other state approved method 
to safely manage sour gas may be required. Venting of gas containing 
H2S content in excess of 50 parts per million is generally not 
allowed. Venting does not include emissions associated with fugitive 
losses. State approval is required for venting of gas containing H2S 
content in excess of 50 parts per million for specific job tasks in 
controlled environments, such as well repairs, pipeline purging, well 
failures, decommissioning of facilities, or where necessary as a 
safety measure where flaring would be dangerous due to the 
introduction of an ignition source at the work site or when the 
operation is conducted under the authority and regulations of the 
Department of Environmental Quality. 055-000-003 Code Wyo. R. § 39 
(2012). 

Requirements related to venting and flaring: 

Colorado: 
Any gas escaping from the well during drilling operations shall be, so 
far as practicable, conducted to a safe distance from the well site 
and burned. The operator shall notify the local emergency dispatch as 
provided by the local governmental designee of any such flaring. Such 
notice shall be given prior to the flaring if it can be reasonably 
anticipated and, in all other cases, as soon as possible but in no 
more than 2 hours after it occurs. Unnecessary/excessive 
venting/flaring of natural gas produced from a well is prohibited. 
Except for gas flared or vented during an upset condition, well 
maintenance, well stimulation flowback, purging operations, or a 
productivity test, gas shall be flared or vented only after notice and 
approval. The notice shall estimate the volume and content of the gas 
and whether it contains more than 1 parts per million of H2S. If 
necessary to protect the public health, safety, or welfare, the 
Director may require the flaring of gas; Gas flared, vented, or used 
on the lease shall be estimated based on a gas-oil ratio test or other 
approved equivalent test, and reported on Operator's Monthly 
Production Report. Flared gas shall be directed to a controlled flare 
or other combustion device operated as efficiently as possible to 
provide maximum reduction of air contaminants where practicable and 
without endangering the safety of the well site personnel and the 
public. Operators shall notify local emergency and government 
officials prior to flaring when it can be reasonably anticipated, or 
ASAP, but not more than 2 hours after it occurs; All salable quality 
gas shall be directed to the sales line as soon as practicable or shut 
in and conserved. Temporary flaring or venting shall be permitted as a 
safety measure during upset conditions and in accordance with all 
other applicable laws, rules, and regulations. In instances where 
green completion practices are not technically feasible or are not 
required, operators shall employ best management practices to reduce 
emissions. Such best management practices may include measures or 
actions, considering safety, to minimize the time period during which 
gases are emitted directly to the atmosphere, or monitoring and 
recording the volume and time period of such emissions. Such examples 
could include the flaring or venting of gas. 2 Colo. Code Regs. § 404-
1(317, 912, 805) (2012). 

North Dakota: 
Gas produced with crude oil from an oil well may be flared during a 1-
year period from the date of first production from the well. 
Thereafter, flaring of gas from the well must cease and the well must 
be capped, connected to a gas gathering line, or equipped with an 
electrical generator that consumes at least 75 percent of the gas from 
the well. For a well operated in violation of this section, the 
producer shall pay royalties to royalty owners upon the value of the 
flared gas and shall also pay gross production tax on the flared gas. 
A producer may obtain an exemption from this section upon application 
and a showing that connection of the well to a natural gas gathering 
line is economically infeasible at the time of the application or in 
the foreseeable future or that a market for the gas is not available 
and that equipping the well with an electrical generator to produce 
electricity from gas is economically infeasible. Pending arrangements 
for disposition for some useful purpose, all vented casinghead gas 
shall be burned. Each flare shall be equipped with an automatic 
ignitor or a continuous burning pilot, unless waived by the state for 
good reason. N.D. Cent. Code, § 38-08-06.4 (2012); N.D. Admin. Code 43-
02-03-45 (2012). 

Ohio: 
All owners, lessees, or their agents, drilling for or producing crude 
oil or natural gas, shall use every reasonable precaution in 
accordance with the most approved methods of operation to stop and 
prevent waste of oil or gas, or both. Any well productive of natural 
gas in quantity sufficient to justify utilization shall be utilized or 
shut in within 10 days after completion. The owner of any well 
producing both oil and gas may burn such gas in flares when it is 
necessary to protect the health and safety of the public or when the 
gas is lawfully produced and there is no economic market at the well 
for the escaping gas. All gas vented to the atmosphere must be flared, 
with the exception of gas released by a properly functioning relief 
device and gas released by controlled venting for testing, blowing 
down, and cleaning out wells. Flares must be a minimum of 100 feet 
from the well, a minimum of 100 feet from oil production tanks and all 
other surface equipment, and 100 feet from existing inhabited 
structures and in a position so that any escaping oil or condensate 
cannot drain onto public roads or toward existing inhabited structures 
or other areas that could cause a safety hazard. In urbanized areas 
where flaring is expected, permittee shall notify local emergency 
response officials that such may occur. It is recommended that notice 
be provided if possible just prior to the expected flaring and/or 
immediately upon flare ignition. Ohio Rev.Code Ann. § 1509.20 (2012). 
Ohio Admin. Code Ann. 1501:9-9-05, -03 (2012). 

Pennsylvania: 
Excess gas encountered during drilling, completion, or stimulation 
shall be flared, captured, or diverted away from the drilling rig in a 
way that does not create a public health or safety hazard. 25 Pa. Code 
§ 78.73 (2012). 

Texas: 
Certain gas releases need not be flared, including: releases of gas 
that are not readily measured such as vapors from crude oil storage 
tanks; releases of gas from a well that must be unloaded or cleaned-up 
to atmospheric pressure (limited to 24 continuous hours or 72 hours in 
1 month); releases of gas from a facility served by a gas gathering 
system, compression facility or gas plant (limited to 24 hours unless 
an exception is granted). Other authorized releases exceeding 24 hours 
shall be flared unless burning cannot be done safely. Such releases 
include: gas released for no more than 10 days after initial 
completion, recompletion in another field, or workover operations in 
the same field; hydrocarbon gas contained in the waste stream from a 
membrane unit or molecular sieve used to remove carbon dioxide, H2S, 
or other contaminants from a gas stream, provided that at least 85% of 
the hydrocarbon gas in the inlet gas stream is recovered and directed 
to a legal use; low pressure separator gas, not to exceed 15 mcfd of 
hydrocarbon gas per gas well or 50 mcfd of hydrocarbon gas per 
commission-designated oil lease or commingling point for commingled 
operations; releases resulting from cleaning a well of solids or 
fluids or both for more than 10 producing days following initial 
completion, recompletion in another field, or workover operations in 
the same field; releases resulting from unloading excess formation 
fluid buildup in a wellbore for periods in excess of 24 hours in one 
continuous event or 72 hours total in 1 calendar month; releases of 
volumes of low pressure gas that can be measured with devices 
routinely used in oil and gas exploration, development, and production 
operations and that are not directed by an operator to a gas gathering 
system, gas pipeline, or other marketing facility, or other purposes 
and uses authorized by law due to mechanical, physical, or economic 
impracticability; for casinghead gas only, releases associated with 
the unavailability of a gas pipeline or other marketing facility, or 
other purposes and uses authorized by law; and releases associated 
with avoiding curtailment of gas production which will result in a 
reduction of ultimate recovery from a gas well or oil reservoir. 16 
Tex. Admin. Code § 3.32 (2012). 

Wyoming: 
Venting or flaring during emergencies or upset conditions; well 
purging and evaluation tests; or production tests is not waste and is 
authorized. The state encourages employment of technologies that 
minimize or prevent venting and flaring during drilling and 
completion. Unless it is determined that waste is occurring, up to 60 
MCF of gas per day is authorized to be vented or flared from 
individual oil wells. Venting or flaring is authorized either at the 
well or at a lease facility which serves several wells. An 
Owner/Operator must apply for retroactive or prospective venting or 
flaring authorization in other circumstances. Authorization may be 
granted if the venting or flaring does not constitute waste.055-000-
003 Code Wyo. R. § 39 (2012). 

Source: GAO analysis of state information. 

[End of table] 

[End of section] 

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

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. 

Table 20: Crosswalk between Selected Requirements from EPA, Six 
States, and Federal Minerals: 

Siting and site preparation: 

Area of regulation: Comprehensive environmental assessment prior to 
drilling; 
EPA environmental and public health requirements: No[A]; 
Requirements of six states reviewed: [B]; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Identification or testing of water wells prior to 
drilling of production wells; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 1 of 6 (Wyoming) [identification 
alone]; 2 of 6 (Colorado, Ohio) [identification and testing][C]; 
Additional requirements for federal minerals: Yes - identification; 
No - testing. 

Area of regulation: Required setbacks from water sources; 
EPA environmental and public health requirements: No[D]; 
Requirements of six states reviewed: 5 of 6 (Colorado, North Dakota, 
Pennsylvania, Ohio, Wyoming); 
Additional requirements for federal minerals: Yes. 

Area of regulation: Erosion control, site preparation, surface 
disturbance minimization, and stormwater management; 
EPA environmental and public health requirements: Effectively no[E]; 
Requirements of six states reviewed: 6 of 6 [any]; 
4 of 6 (Colorado, North Dakota, Pennsylvania, Wyoming) [stormwater 
permitting][F]; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Drilling, casing, and cementing; 
EPA environmental and public health requirements: [Empty]; 
Requirements of six states reviewed: [Empty]; 
Additional requirements for federal minerals: [Empty]. 

Area of regulation: Requirements relating to cementing/casing plans; 
EPA environmental and public health requirements: No[G]; 
Requirements of six states reviewed: 6 of 6[H]; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Prescribed placement of surface casing relative to 
groundwater zones; 
EPA environmental and public health requirements: No[G]; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Prescribed cementation techniques for surface 
casing; 
EPA environmental and public health requirements: No[G]; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: No; 
instead the Bureau of Land Management (BLM) has performance standards. 

Area of regulation: Requirement for cement waiting period and/or 
integrity tests; 
EPA environmental and public health requirements: No[G]; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Blowout preventer[I] requirements; 
EPA environmental and public health requirements: No[G]; 
Requirements of six states reviewed: 5 of 6[J] (Colorado, North 
Dakota, Pennsylvania, Texas, Wyoming); 
Additional requirements for federal minerals: Yes. 

Hydraulic fracturing: 

Area of regulation: Prior authorization/notice/inspection requirements; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 4 of 6 (Colorado, Ohio, 
Pennsylvania, Wyoming); 
Additional requirements for federal minerals: Not currently, but in 
BLM proposed rule. 

Area of regulation: Requirements to disclose information on fracturing 
fluids; 
EPA environmental and public health requirements: No[K]; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Not currently, but in 
BLM proposed rule. 

Area of regulation: Pressure monitoring, testing, limitations or other 
mechanical integrity requirements specific to hydraulic fracturing; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 4 of 6 (Colorado, North Dakota, 
Ohio, Wyoming); 
Additional requirements for federal minerals: Not currently, but in 
BLM proposed rule. 

Well plugging: 

Area of regulation: Requirements for notification, plugging plan or 
method, witnessing, and reporting; 
EPA environmental and public health requirements: No[L]; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Programs to plug wells that are not properly 
plugged and have been abandoned; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes[M]. 

Site reclamation: 

Area of regulation: Requirements for backfilling, regrading, 
recontouring, and alleviating compaction of soil; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Revegetation requirements; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 5 of 6 (Colorado, North Dakota, 
Ohio, Pennsylvania, Wyoming); 
Additional requirements for federal minerals: Yes. 

Waste management: 

Area of regulation: Options for waste disposal: Underground injection; 
EPA environmental and public health requirements: Yes (Safe Drinking 
Water Act); 
Requirements of six states reviewed: 5 states have their own 
requirements (Colorado, North Dakota, Ohio, Texas, Wyoming); 
EPA implements the program in Pennsylvania; 
Additional requirements for federal minerals: In the permit 
application, operators must describe the final disposal of waste 
materials. 

Area of regulation: Options for waste disposal: Direct discharge to 
surface water; 
EPA environmental and public health requirements: Yes (Clean Water 
Act--certain discharges prohibited, others subject to conditions and 
permits); 
Requirements of six states reviewed: Surface discharges are allowed in 
certain cases in 3 western states (Colorado, Texas, Wyoming); 
Additional requirements for federal minerals: In the permit 
application, operators must describe the final disposal of waste 
materials. 

Area of regulation: Options for waste disposal: Requirements for 
discharge to publicly-owned treatment works (POTWs) or Centralized 
Waste Treatment Facilities (CWT); 
EPA environmental and public health requirements: Pretreatment 
standards for shale gas wastewater under development (Clean Water Act); 
Requirements of six states reviewed: Disposal at POTWs is an option in 
two states[N] (Ohio, Pennsylvania); Disposal at CWT facilities is an 
option in 3 states (Colorado, Pennsylvania, Wyoming); 
Additional requirements for federal minerals: In the permit 
application, operators must describe the final disposal of waste 
materials. 

Area of regulation: Options for waste disposal: Recycling or other 
reuse; 
EPA environmental and public health requirements: Yes (Clean Water 
Act--certain produced water discharges); 
Requirements of six states reviewed: 6 of 6 states allow recycling or 
other reuse[O]; 
Additional requirements for federal minerals: In the permit 
application, operators must describe the final disposal of waste 
materials. 

Area of regulation: Options for waste disposal: Solid waste disposal; 
EPA environmental and public health requirements: Effectively no[P]; 
Requirements of six states reviewed: Yes; 
Additional requirements for federal minerals: In the permit 
application, operators must describe the final disposal of waste 
materials. 

Area of regulation: Options for waste disposal: Hazardous waste 
disposal; 
EPA environmental and public health requirements: Effectively no[Q]; 
Requirements of six states reviewed: No; 
Additional requirements for federal minerals: In the permit 
application, operators must describe the final disposal of waste 
materials. 

Area of regulation: Pit siting requirements (with regard to sensitive 
areas); 
EPA environmental and public health requirements: No[R]; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: No specific requirements 
but pits must be approved. 

Area of regulation: Pit lining requirements; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 5 of 6[S] (Colorado, North 
Dakota, Pennsylvania, Texas, Wyoming); 
Additional requirements for federal minerals: Not currently, but BLM 
proposed rule would require liners for pits used to store hydraulic 
fracturing flowback fluids. 

Area of regulation: Pit closure requirements; 
EPA environmental and public health requirements: No; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes. 

Managing air emissions: 

Area of regulation: Requirements for criteria pollutants; 
EPA environmental and public health requirements: Certain Clean Air 
Act provisions apply; 
Requirements of six states reviewed: 5 of 6 states have permitting or 
registration programs (Colorado, North Dakota, Ohio, Texas, 
Wyoming)[T]; 
Additional requirements for federal minerals: No. 

Area of regulation: Requirements for hazardous air pollutants; 
EPA environmental and public health requirements: Certain Clean Air 
Act provisions apply; 
Requirements of six states reviewed: State permitting or registration 
programs may address hazardous air pollutants; 
Additional requirements for federal minerals: No. 

Area of regulation: Requirements related to hydrogen sulfide gas; 
EPA environmental and public health requirements: No specific 
requirements[U]; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes. 

Area of regulation: Requirements related to flaring; 
EPA environmental and public health requirements: Under new New Source 
Performance Standards, most hydraulically fractured gas wells must do 
green completions; 
Requirements of six states reviewed: 6 of 6; 
Additional requirements for federal minerals: Yes. 

Sources: GAO analysis of federal and state laws and regulations. 

[A] Under the National Environmental Policy Act (NEPA), federal 
agencies must assess the effects of major federal actions--those they 
propose to carry out or to permit--that significantly affect the 
environment. Many Environmental Protection Agency (EPA) activities 
relevant here are exempt from NEPA's procedural requirements by 
statute or recognition by courts that EPA procedures or environmental 
reviews under enabling legislation are functionally equivalent to the 
NEPA process. See 63 Fed. Reg. 58045 (Oct. 29, 1998). 

[B] We did not specifically analyze state requirements in this area. 
However, when asked whether they had a comprehensive environmental 
assessment process prior to drilling, officials from Ohio, Texas, 
Pennsylvania, and Wyoming said they did not. Officials in North Dakota 
said that an environmental assessment is required for drilling on 
state lands and officials in Colorado said that a location assessment 
is required, which includes assessing transportation access, future 
reclamation plans, and determination of whether the proposed location 
is within a sensitive wildlife habitat. 

[C] Testing requirement applies only to certain wells--certain wells 
near proposed coalbed methane wells in Colorado and wells proposed for 
urbanized areas or in the vicinity of horizontal wells in Ohio. 
Pennsylvania does not require operators to identify or test nearby 
water wells, but state law incentivizes operators to do so by 
establishing a rebuttable presumption that operators are liable for 
changes in water quality of certain wells after drilling. 

[D] There are no federal requirements regarding setbacks, but under 
Section 404 of the Clean Water Act, a permit from the U.S. Army Corps 
of Engineers is required to fill waters of the United States, such as 
wetlands. 

[E] Oil and gas well sites are only required to get 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, 
rather than prior to commencing construction or causing discharges. 

[F] Ohio and Texas state regulations address stormwater in other ways. 

[G] Generally federal environmental laws do not have drilling, 
cementing, or casing requirements related to drilling production 
wells. However, according to EPA officials, if the well is to be 
hydraulically fractured with diesel fuel, it is subject to regulation 
as a Class II well under the underground injection control (UIC) 
program authorized by the Safe Drinking Water Act, and be subject to 
cementing and casing requirements. See 40 C.F.R. §§ 144.52 and 146.22. 
In May 2012, EPA published draft guidance on how its UIC permit 
writers should address hydraulic fracturing with diesel in the context 
of the Class II UIC program. To date, however, EPA officials are 
unaware of any wells that were regulated in this way. 

[H] Colorado, North Dakota, Ohio, Pennsylvania, and Wyoming require 
cementing/casing plans. Texas requires cementing/casing plans if an 
operator proposes a method of freshwater protection other than those 
prescribed by state regulations. 

[I] Blowout preventers are devices placed on wells to help maintain 
control over pressures in the well and prevent the well from spewing 
oil, gas, or other formation fluids in the case of a blowout. 

[J] North Dakota, Texas, and Wyoming require blowout preventers; 
Colorado and Pennsylvania require blowout preventers in certain 
circumstances. 

[K] Under TSCA, to the extent a hydraulic fracturing fluid is a 
chemical substance or mixture, manufacturers (including importers), 
processors, and distributors of such fluids generally would be subject 
to applicable reporting requirements. Generally, well site operators 
would not be subject to any such applicable TSCA reporting 
requirements. 

[L] Generally federal environmental laws do not have requirements 
related to well plugging. However, according to EPA officials, if the 
well is to be hydraulically fractured with diesel fuel, it is subject 
to regulation as a Class II UIC well under the SDWA UIC program, as 
discussed in table note g above. 

[M] According to BLM officials, BLM periodically conducts orphan and 
idle well operations. 

[N] Disposal at a POTW is currently available in Pennsylvania and 
Ohio. Discharges may be authorized from a POTW in Pennsylvania if 
preceded by treatment at a CWT. The Ohio Environmental Protection 
Agency recently prohibited disposal at a POTW in the state, but an 
administrative review commission removed the prohibition as beyond the 
agency's authority. The Ohio Department of Natural Resources may take 
separate action to prohibit the practice. We are also aware that the 
city of Forth Worth, Texas had a pilot program within the last several 
years under which it accepted flowback for disposal through its POTW, 
but current information suggests that the city is no longer accepting 
flowback water. 

[O] For example, four states allow operators to reuse certain types of 
fluid waste for road applications. 

[P] The existing federal regulations under RCRA solid waste provisions 
apply to nonhazardous waste disposal facilities and practices, 
including those involving oil and gas wastes, and prohibit open 
dumping of solid waste. However, EPA has a limited role in the 
enforcement of RCRA solid waste provisions. 

[Q] Per EPA's 1988 regulatory determination, oil and gas exploration 
and production wastes--including wastes originating in the well or 
associated field operations--are not regulated as hazardous. Small 
amounts of other hazardous waste may be at well sites (such as 
discarded, unused hydraulic fracturing fluids) but we could not 
identify any instances where these wastes were available in high 
enough quantities to trigger RCRA requirements. 

[R] Under Section 404 of the Clean Water Act, a permit from the U.S. 
Army Corps of Engineers is required to fill waters of the United 
States, such as wetlands. 

[S] Colorado, North Dakota, Pennsylvania, and Wyoming have specific 
pit lining requirements. Texas regulations provide for pit lining 
requirements to be addressed in permits. 

[T] In addition, Pennsylvania is in the process of developing an 
inventory for oil and gas emissions information. 

[U] Although there are no specific requirements, owners and operators 
are subject to the Clean Air Act general duty clause to take steps to 
prevent accidental releases of listed and other substances to the air; 
these include hydrogen sulfide. 

[End of table] 

[End of section] 

Appendix XI: Comments from the Department of Agriculture: 

United States Department of Agriculture: 
Forest Service: 
Washington Office: 
1400 Independence Avenue, SW: 
Washington, DC 20250: 

File Code: 1470: 

Date: August 15, 2012: 

Mr. David Trimble: 
Director, Natural Resources and Environment: 
Washington, DC, 20548: 

Dear Mr. Trimble: 

Thank you for the opportunity to review and provide comment on the 
draft U.S. Government Accountability Office (GAO) report on 
"Unconventional Oil and Gas Development: Key Environmental and Public 
Health Requirements" (GAO-12-874). The Forest Service has
reviewed the report and generally concurs with the information 
provided in the report and noted that there are no specific 
recommendations or findings. 

Relative to the description of challenges identified by the various 
agencies; page 70 of the report addresses the Bureau of Land 
Management challenge of hiring and retaining qualified staff in areas 
with very active oil and gas development. Thee Forest Service shares 
that challenge, especially on the Dakota Prairie Grassland. 

We compliment GAO in the use of graphics in the report to facilitate 
visual display of operations or processes, which are very helpful in 
understanding quite technical information. 

If you have any questions, please contact Thelma Strong, Acting Chief 
Financial Officer at 202-205-1321 or tstrong@fs.fed.us. 

Sincerely, 

Signed by: 

[Illegible] for: 

Thomas L. Tidwell: 
Chief: 

[End of section] 

Appendix XII: Comments from the Department of the Interior: 

United States Department of the Interior: 
Office of The Secretary: 
Washington, DC 20240: 

August 20, 2012: 

Mr. David C. Trimble: 
Director, Natural Resources and Environment: 
U.S. Government Accountability Office: 
441 G Street, N.W. 
Washington, D.C. 20548: 

Dear Mr. Trimble: 

On July 25, 2012, the Government Accountability Office (GAO) issued a 
draft report on hydraulic fracturing entitled, Unconventional Oil and 
Gas Development: Key Environmental and Health Requirements (GA0-12-
874). The GAO made no recommendations to the Department of the 
Interior (Department). However, the Department offers comments on 
certain findings and conclusions contained in the report. We believe 
these additions are necessary to create a fuller public understanding 
of Departmental initiatives that are otherwise only briefly mentioned 
in the report. 

Proposed Hydraulic Fracturing Rule: 

The Department appreciates the GAO's recognition of the Bureau of Land 
Management's (BLM's) proposed rule on hydraulic fracturing, which the 
report describes briefly (p. 65). This proposed rule is a significant 
advance toward responsible development of unconventional oil and gas 
resources on the public lands, with the potential to increase public 
confidence in its regulation. The BLM's proposed rule focuses on 
disclosure of chemicals used in the process, welt integrity, and 
management of flowback fluids. We believe that the report would 
benefit from greater attention to this proposed rule, and therefore 
request that the GAO address additional information in its discussion 
of the proposed rule, as detailed below. 

Hydraulic Fracturing Rule Characterization: 

Secretary Salazar has placed significant policy and program emphasis 
on the establishment of a new regulatory framework to assist industry 
and the BLM in managing hydraulic fracturing on Federal and Tribal 
lands among the many states in which BLM oversees leasing of the Federal
subsurface estate. The BLM currently administers Federal and Indian 
oil and gas leases across 34 states. BLM regulations on hydraulic 
fracturing will apply consistently to all leases managed by the BLM, 
whereas state management of such leases may differ by jurisdiction. 
Consistent standards governing BLM-managed subsurface will help the 
Bureau achieve sensible, responsible stewardship of the public estate. 

There are three main aspects of the BLM's proposed rule: 1) the 
requirement for operators to publicly disclose all chemicals used 
during hydraulic fracturing operations, while protecting trade 
secrets; 2) the requirement to confirm wellbore integrity before and 
during the hydraulic fracturing operation; and 3) the requirement to 
properly manage waters that flow hack to the surface from hydraulic 
fracturing operations. The Department believes this rule will result in
significant improvements for the BLM's management of unconventional 
oil and gas development on Federal and Indian lands, and increase 
public confidence in this industry practice. 

BLM Mission and Framework: 

The GAO report should more fully articulate distinctions between BLM 
and state land management responsibilities. We suggest adding 
additional language to the report's description of the proposed rule 
on p. 65 to include the following information: Pursuant to the Federal 
Land Policy and Management Act (FLPMA) and other applicable laws, the 
BLM has a mission to manage the public lands for multiple use and 
sustained yield, in the national interest. This imposes stewardship 
responsibilities that may differ, substantially in many cases, from 
state authorities and interests addressed in the report. State lands 
are often managed solely or primarily for revenue, and state 
provisions governing oil and gas activities on state-administered 
lands may not address conservation needs and natural resource values, 
such as air, soil, water, wildlife, recreation, and cultural and 
scenic landscapes, in a manner that would satisfy FLPMA's multiple-use 
directive. The BLM's multiple-use mission is reflected in the BLM's 
proposed rule on hydraulic fracturing, which is intended to improve 
stewardship and operational efficiency by establishing a uniform set 
of standards for hydraulic fracturing practices across the public and
Indian lands. 

Cement Bond Logs and Surface Casing: 

The Department also requests that the GAO report more specifically 
describe the provisions of the proposed rule relating to well bore 
integrity and the requirements for cement bond logs and surface 
casing. These elements of unconventional gas recovery are of primary 
importance to surrounding landowners, stakeholders, and the public, 
and the Department believes that they merit further explanation in the 
report. The BLM's proposed regulations would require that an operator 
take the following steps to ensure well bore integrity: 1) run a 
string of steel pipes (surface and intermediate casing) across all 
usable water zones; 2) cement the steel pipes to the rock formation in 
a manner that seals all spaces behind the pipe; and 3) use available 
technology (e.g., cement bond logs) to verify that there is a secure 
cement seal between the steel pipes and the rock formation to avoid 
fluid migration outside the pipes. Finally, at the conclusion of 
drilling and before hydraulic fracturing takes place, the proposed 
rule would require an operator to test the steel pipes to ensure that 
the steel pipe construction is suitable to withstand the force and 
pressure to be applied by the hydraulic fracturing activity. The BLM's 
requirements in the proposed rule arc consistent with the American 
Petroleum Institute's published guidelines on industry best practices 
for mitigating environmental impacts that may be associated with 
hydraulic fracturing operations. The BLM will consider public comments 
on this proposal. 

Aquifer Protection: 

The Department also requests that the GAO more specifically articulate 
the provisions of the proposed rule relating to the protection of 
aquifers. The provisions relating to well bore integrity through 
casing and cementing isolation, described above, provide important 
protection for aquifers. Additionally, the proposed rule includes 
requirements for operators to submit the length and height of the 
hydraulic fractures, both before and after the actual fracturing, so 
that the BLM can ensure the safety and zonal isolation integrity of 
aquifers in the vicinity of the oil and gas reserves. Overall, the BLM 
has taken measures to protect aquifers through the proposed rule's 
commitment to wellbore integrity; mechanical integrity, and the 
management of the flowback water (as discussed below). 

Flowback: 

The Department also requests that the report include a description of 
provisions in the proposed rule regarding the collection of 
information about and management of disposal of flowback water. 
Flowback water (fluids recovered after fracturing), if mishandled, can 
pose a risk to water supply. The BLM's proposed rule therefore would 
require that an operator store flowback water in a steel tank and/or a 
lined pit. The proposed rule would also mandate that operators 
estimate the volume of flowback water and report how they will handle 
it. The proposed rule would further specify that operators must comply 
with the BLM's Onshore Oil and Gas Order Number 7 Disposal of Produced 
Water, when managing flowback fluids associated with hydraulic 
fracturing operations. The BLM believes that the above steps arc 
necessary to protect water and natural resources at the surface from 
contamination by hydraulic fracturing. Further, these steps are 
consistent with industry practice and guidelines published by the 
American Petroleum Institute. Finally, in the proposed rule the BLM 
reserves the right to place additional restrictions and issue 
additional guidelines on the handling of flowback water, as 
appropriate. 

Inspection and Enforcement Workforce Strategy Report: 

The GAO Report also mentions difficulties faced by the BLM in hiring 
and retaining skilled technical staff (pp.70-71). A BLM team 
consisting of field, state, and headquarters staff has reviewed the 
ongoing issues related to hiring, training, and retaining qualified 
Petroleum Engineers and Petroleum Engineering Technicians. The BLM is 
in the process of developing a report that will provide current 
information related to these issues and make recommendations for 
improvements. We request that the GAO report acknowledge this 
initiative. 

Thank you for the opportunity to comment on this report and its 
analysis of the important topic of hydraulic fracturing. In addition 
to the above comments, we also enclose a number of technical comments. 
If you have any questions, please contact Nicholas Douglas, Senior 
Policy Advisor, at 202-912-7311 or LaVanna Stevenson-Harris, BLM Audit 
Liaison Officer, at 202-912-7077. 

Sincerely, 

Signed by: 

Ned Farquhar: 
Deputy Assistant Secretary: 
Land and Minerals Management: 

Enclosure: 

[End of section] 

Appendix XIII: GAO Contact and Staff Acknowledgments: 

GAO Contact: 

David C. Trimble, (202) 512-3841 or trimbled@gao.gov: 

Staff Acknowledgments: 

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. 

[End of section] 

Footnotes: 

[1] Conventional sandstone has well-connected pores, but tight 
sandstone has irregularly distributed and poorly connected pores. Due 
to this low connectivity or permeability, gas trapped within tight 
sandstones is not easily produced. 

[2] The Energy Information Administration is the statistical and 
analytical agency within the Department of Energy that collects, 
analyzes, and disseminates independent and impartial information on 
energy issues. 

[3] Shale oil differs from "oil shale." Oil shale requires a different 
process to extract. Specifically, to extract the oil from oil shale, 
the rock needs to be heated to very high temperatures--ranging from 
about 650 to 1,000 degrees Fahrenheit--in a process known as 
retorting. For additional information on oil shale, see GAO, Energy-
Water Nexus: A Better and Coordinated Understanding of Water Resources 
Could Help Mitigate the Impacts of Potential Oil Shale Development, 
[hyperlink, http://www.gao.gov/products/GAO-11-35] (Washington, D.C.: 
Oct. 29, 2010). 

[4] Department of Energy, Secretary of Energy Advisory Board, Shale 
Gas Production Subcommittee 90-Day Report (Washington, D.C.: 2011) 

[5] GAO is conducting a separate and more detailed review of risks 
associated with shale oil and gas development. 

[6] EPA announced in March 2010 that its Office of Research and 
Development would conduct a study to examine the potential effects of 
hydraulic fracturing on drinking water resources. According to EPA 
officials, the agency anticipates issuing a progress report in 2012 
and a final report in 2014. 

[7] BLM also manages oil and gas development on American Indian lands, 
but American Indian lands are outside the scope of this review. 

[8] Unconventional reservoirs may also be located on tribal lands, but 
these were outside the scope of our review. 

[9] Prior to beginning these activities, the operator must acquire the 
necessary leases to gain the right to drill for oil or gas on a 
particular area of land. Leasing is not discussed here because it is 
outside the scope of our review; however, aspects of BLM's process for 
issuing leases that are relevant to environmental requirements are 
discussed later in this report. In addition, the operator must obtain 
a permit to drill from applicable federal or state agencies, but the 
details of the permitting process are not generally within the scope 
of our review. 

[10] In acquiring this water, operators must comply with applicable 
state and regional laws or rules regarding water withdrawals, but 
these are outside the scope of this report. 

[11] The Ground Water Protection Council is a nonprofit organization 
whose members are state groundwater regulatory agencies. Ground Water 
Protection Council and ALL Consulting. "Modern Shale Gas Development 
in the United States: A Primer." Prepared for the Department of Energy 
and National Energy Technology Laboratory. April 2009. 

[12] Not all the fluids injected into the well during hydraulic 
fracturing necessarily flow back to the surface. 

[13] Backfilling is refilling a pit or other area with soil. 

[14] 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, 
[hyperlink, http://www.gao.gov/products/GAO-12-156] (Washington, D.C.: 
Jan. 9, 2012). 

[15] The other criteria pollutant is lead, but it is not commonly 
associated with oil and gas development. 

[16] Volatile organic compounds are emitted as gases from certain 
solids or liquids and include a variety of chemicals, some of which 
may have short-and long-term adverse health effects. Volatile organic 
compounds are emitted by a wide array of products numbering in the 
thousands including paints and lacquers, paint strippers, cleaning 
supplies, and pesticides. 

[17] Flaring involves the burning of gas either for safety reasons or 
because operators do not have the infrastructure to bring the gas to 
market. For more information on flaring, see GAO, Federal Oil and Gas 
Leases: Opportunities Exist to Capture Vented and Flared Natural Gas, 
Which Would Increase Royalty Payments and Reduce Greenhouse Gases, 
[hyperlink, http://www.gao.gov/products/GAO-11-34] (Washington, D.C.: 
Oct. 29, 2010). 

[18] The National Environmental Policy Act may also apply and is 
discussed later in this report. 

[19] Pub. L. No. 93-523 (1974), codified as amended at 42 U.S.C. §§ 
300f-300j-26 (2010). 

[20] Other classes of UIC wells are used by other industries. For 
example, Class I wells are for the injection of hazardous, 
radioactive, and industrial wastes. Class III wells are used for the 
injection of fluids as part of mining operations, such as for mining 
salts or uranium. 

[21] A third type of Class II UIC well is a hydrocarbon storage well, 
which injects liquid hydrocarbons into underground formations, such as 
salt caverns, which can store the hydrocarbons for later use. EPA 
estimates there are over 100 hydrocarbon storage wells in use in the 
United States. 

[22] See discussion below. According to EPA, some states' UIC 
requirements for Class II wells are very similar or identical to EPA 
requirements. 

[23] For simplicity, throughout this report we refer to requirements 
on well operators. In some cases requirements may also apply to well 
owners. 

[24] The court ordered EPA to reconsider its approval of Alabama's 
program. Legal Environmental Assistance Foundation v. EPA, 118 F.3d 
1467, 1478 (11th Cir.1997). 

[25] UIC regulations at the time and now provide that "any 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. 

[26] 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 underground sources of drinking water during hydraulic 
fracturing of coalbed methane wells. 

[27] According to EPA officials, EPA Region 3 has sent letters to the 
relevant operators who may have used diesel in hydraulic fracturing 
stating they must apply for a Class II UIC permit if they continue 
using diesel in hydraulic fracturing. 

[28] The Federal Water Pollution Control Act Amendments of 1972, Pub. 
L. No. 92-500, § 2, 86 Stat. 816, codified as amended at 33 U.S.C. §§ 
1251-1387 (2011) (commonly referred to as the Clean Water Act). 

[29] For the purpose of this document, when we use the term "surface 
waters" in relation to federal regulation, we refer to waters of the 
United States, including jurisdictional rivers, streams, wetlands, and 
other waters. State definitions of the term "surface waters" may 
differ. EPA officials noted that some surface waters may not be 
jurisdictional for certain CWA provisions. 

[30] The scope of jurisdiction for the section 311 oil spill program 
is broader than that for the NPDES program. The section 311 oil spill 
program and the NPDES program both have jurisdiction over navigable 
waters of the United States; Section 311 also provides jurisdiction 
over spills of oil or hazardous substances into or on adjoining 
shorelines or that may affect natural resources of the United States, 
among others. 

[31] EPA established additional industrial categories in the oil and 
gas sector for wells in certain near-shore coastal areas, but effluent 
limitation guidelines for this category are not discussed here, as 
this report is focused on onshore unconventional oil and gas 
production. 

[32] Specifically, the agricultural and wildlife water use subcategory 
includes wells located west of the 98TH meridian, which extends from 
approximately the eastern border of North Dakota south through central 
Texas. 

[33] POTWs will be discussed in greater detail later in this report. 

[34] The 1987 Water Quality Act also exempted oil and gas processing, 
treatment, and transmission facilities from permit requirements for 
stormwater discharges. 

[35] EPA has established by regulation threshold amounts of certain 
pollutants that, if released, trigger reporting requirements; these 
amounts are known as "reportable quantities." Specifically, the 
reportable quantities triggering a permit are listed in 40 C.F.R. §§ 
117.21, 302.6, 110.6 (2011). 

[36] In addition to having total aboveground oil storage capacity 
greater than 1,320 gallons, facilities could be required to comply 
with the SPCC rule if they meet other thresholds, including 
underground storage capacity of 42,000 gallons, among others. 

[37] See GAO, Aboveground Oil Storage Tanks: More Complete Facility 
Data Could Improve Implementation of EPA's Spill Prevention Program, 
[hyperlink, http://www.gao.gov/products/GAO-08-482] (Washington, D.C.: 
Apr. 30, 2008). In that report, we found that EPA has information on 
only a portion of the facilities subject to the SPCC rule, hindering 
its ability to identify and effectively target facilities for 
inspection and enforcement. We recommended that EPA analyze the costs 
and benefits of the options available to EPA for obtaining key data 
about the universe of SPCC-regulated facilities, including, among 
others, a tank registration program similar to those employed by some 
states. EPA has begun taking action on this recommendation. 

[38] Specifically, EPA cited authorities under CWA section 308, as 
well as under CERCLA and RCRA. 

[39] Clean Air Act Amendments of 1970, Pub. L. No. 91-604, 84 Stat. 
1676 (1970), codified as amended at 42 U.S.C. §§ 7401-7671q (2011) 
(commonly referred to as the Clean Air Act). 

[40] See GAO, Diesel Pollution: Fragmented Federal Programs That 
Reduce Mobile Source Emissions Could Be Improved, [hyperlink, 
http://www.gao.gov/products/GAO-12-261] (Washington, D.C.: Feb. 7, 
2012). 

[41] For example, precursors to ground level ozone are nitrogen oxides 
and volatile organic compounds. 

[42] EPA did promulgate standards related to other parts of the oil 
and gas industry. For example, in 1985, EPA promulgated NSPS that 
focused on natural gas processing plants, which remove impurities from 
natural gas to prepare it for use by consumers. 

[43] EPA's April 2012 rulemaking also set NSPS for other parts of the 
oil and natural gas industry, such as for equipment leaks, certain 
types of compressors, and pneumatic controllers located at natural gas 
processing plants. 

[44] This estimate includes green completions that are required to 
occur under the rule, including some that would likely occur 
voluntarily (e.g., without the rule). EPA estimated that of this total 
approximately 4,800 such completions would likely occur voluntarily. 

[45] In addition to NESHAPs specific to the oil and natural gas 
production industrial source category, EPA promulgated other NESHAPs 
that could apply to oil and gas well sites depending on the types of 
equipment in use and their size. See appendix IV for more details. 

[46] EPA Region 6 includes the states of Arkansas, Louisiana, New 
Mexico, Oklahoma, and Texas. 

[47] In addition, a 1999 law provided an exemption for flammable 
substances being used as fuel; this exemption applies to any type of 
facility using fuel. Chemical Safety Information, Site Security and 
Fuels Regulatory Relief Act, Pub. L. No. 106-40 § 2, 113 Stat 207 
(1999). 

[48] The Chemical Safety Board is an independent federal agency 
investigating chemical accidents to protect workers, the public, and 
the environment. See U.S. Chemical Safety and Hazard Investigation 
Board, Investigative Study Final Report: Public Safety at Oil and Gas 
Storage Facilities, Report No. 2011-H-1 (September 2011). 

[49] The Chemical Safety Board also noted that exploration and 
production storage tanks are exempt from the security requirements of 
CWA's spill prevention program. 

[50] Other major greenhouse gases covered by EPA's greenhouse gas 
reporting rule include hydrofluorocarbons, perfluorocarbons, and 
sulfur hexafluoride. 

[51] Pub. L. No. 94-580, 90 Stat. 2795 (1976) (amending the Solid 
Waste Disposal Act, but generally referred to as RCRA), codified as 
amended at 42 U.S.C. §§ 6901-6992k (2011). RCRA also created a 
framework in which states are largely responsible for solid (i.e., 
nonhazardous) waste regulations, including treatment and land disposal 
of these wastes. State solid waste provisions will be discussed in 
greater detail later in this report. 

[52] Specifically, oil and gas exploration and production waste 
includes drilling fluids, produced waters, and other wastes associated 
with the exploration, development, or production of crude oil or 
natural gas, among other things. 

[53] Field operations include, for example, water separation, 
demulsifying, degassing, and storage at well sites. 

[54] Small quantity generators are those generating between 100 and 
1,000 kilograms of hazardous waste per month, and large quantity 
generators are those generating more than 1,000 kilograms per month. 
Both small and large quantity generators are required to obtain an EPA 
identification number and are subject to certain regulations. 
Facilities generating less than 100 kilograms of hazardous waste per 
month are considered conditionally exempt small quantity generators 
provided they meet certain conditions, and if so, do not need to 
obtain an identification number. 

[55] These conditionally exempt small quantity generators are subject 
to limited generator waste management standards, namely to identify 
their hazardous waste, comply with storage limit requirements, and 
ensure waste treatment or disposal in a proper facility. 

[56] Pub. L. No. 96-510, 94 Stat. 2767 (1980), codified as amended at 
42 U.S.C. §§ 9601-9675 (2012). 

[57] Pub. L. No. 99-499, 100 Stat. 1728 (1986), codified at 42 U.S.C. 
§§ 11001-11050 (2012). 

[58] Three types of releases must be reported: (1) release of 
extremely hazardous substances for which notification is also required 
under CERCLA § 103(c), (2) release of extremely hazardous substances 
for which notification is not required under CERCLA § 103(c), but 
above reporting thresholds and subject to additional conditions, and 
(3) release of other hazardous substances for which notification is 
also required under CERCLA § 103(c), subject to CERCLA reporting 
thresholds or 1 pound default threshold. EPCRA § 304(a), 42 U.S.C. §§ 
11004(a) (2011). 

[59] Specifically, the thresholds are (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. 

[60] In addition to identifying industries, EPCRA specifies that 
reporting requirements apply to owners or operators of covered 
facilities: (1) with 10 or more full-time employees and (2) that 
manufactured, processed, or otherwise used a listed toxic chemical in 
excess of the reporting threshold during the calendar year. 

[61] The complete list of industries added by EPA in 1997 includes 
metal mining, coal mining, electrical utilities that combust coal 
and/or oil for the purpose of generating power for distribution in 
commerce, refuse processing or destruction facilities regulated under 
RCRA's hazardous waste provisions, chemical wholesalers, petroleum 
terminals, and bulk stations and solvent recovery services. 

[62] Other thresholds include the number of employees at the facility. 

[63] Officials said that EPA is also considering steam generation from 
coal and/or oil, petroleum bulk storage, iron ore mining, phosphate 
mining, large dry cleaning, and solid waste combustors and 
incinerators. 

[64] Pub. L. No. 94-469, 90 Stat. 2003 (1976), codified as amended at 
15 U.S.C. §§ 2601-2692 (2012). TSCA addresses those chemicals 
manufactured or imported into the United States, but it generally 
excludes certain substances, such as pesticides, which are regulated 
under the Federal Insecticide, Fungicide, and Rodenticide Act, and any 
food, food additive, drug, cosmetic, or device regulated under the 
Federal Food, Drug, and Cosmetics Act. Hereinafter, references to 
chemical substances in discussions of TSCA are intended to include 
mixtures. 

[65] These authorities are conditional on EPA making certain findings. 
For example, prior to requiring testing under section 4, TSCA requires 
EPA to make findings (1) regarding the risk of injury to health or the 
environment or regarding human exposure, (2) that existing data are 
insufficient, and (3) that testing with respect to such effects is 
necessary to develop needed data. Regarding actions to protect 
adequately against unreasonable risks, examples of EPA actions include 
prohibiting or limiting the manufacture, processing, or distribution 
in commerce of chemical substances or by placing restrictions on 
chemical uses. 

[66] Earthjustice et al., Letter to Lisa P. Jackson, EPA 
Administrator, re: Citizen Petition under Toxic Substances Control Act 
Regarding the Chemical Substances and Mixtures Used in Oil and Gas 
Exploration or Production, Aug. 4, 2011. 

[67] The Federal Environmental Pesticide Control Act, Pub. L. No. 92-
516, 86 Stat. 973 (1972) (amending FIFRA), codified as amended at 7 
U.S.C. §§ 136-136y (2012). 

[68] Ground Water Protection Council and ALL Consulting. "Modern Shale 
Gas Development in the United States: A Primer." Prepared for the 
Department of Energy and National Energy Technology Laboratory. April 
2009. 

[69] Glutaraldehyde is also used as a disinfectant for medical and 
dental equipment, in water treatment systems, and as a preservative. 

[70] See EPA, Memorandum, Use of CERCLA § 106 To Address Endangerments 
that May Also Be Addressed Under Other Environmental Statutes, App. A 
(2001). 

[71] Charles G. Groat, Ph.D. and Thomas W. Grimshaw, Ph.D., Fact-Based 
Regulation for Environmental Protection in Shale Gas Development 
(Austin, Texas: The Energy Institute, The University of Texas at 
Austin, February 2012). Ground Water Protection Council and ALL 
Consulting. "Modern Shale Gas Development in the United States: A 
Primer." Prepared for the Department of Energy and National Energy 
Technology Laboratory. April 2009. 

[72] An abandoned well is a well that is no longer under control of an 
operator, whether or not it was properly plugged. In Colorado, wells 
must be tested for all major cations (positively-charged ions) and 
anions (negatively-charged ions), total dissolved solids, iron, 
manganese, selenium, nitrates and nitrites, dissolved methane, field 
pH, sodium adsorption ratio, presence of bacteria (iron related, 
sulfate reducing, slime, and coliform), specific conductance, and 
hydrogen sulfide. 

[73] In Ohio, sampling must be conducted in accordance with state 
guidelines, which require testing for barium, calcium, iron, 
magnesium, potassium, sodium, chloride, conductivity, pH, sulfate, 
alkalinity, and total dissolved solids. 

[74] Pennsylvania has a similar provision for conventional wells, 
which presumes operators to be liable for any pollution of water wells 
within 1,000 feet of a conventional well that occurs within 6 months 
of drilling activities. 

[75] For conventional wells in Pennsylvania, the required setback is 
200 feet. 

[76] According to state regulators, this maximum surface casing depth 
requirement prevents fresh and brackish groundwater from commingling 
behind the same casing, among other things. 

[77] FracFocus is the national hydraulic fracturing chemical registry 
managed by the Ground Water Protection Council and Interstate Oil and 
Gas Compact Commission. The Ground Water Protection Council is a 
nonprofit organization whose members consist of state groundwater 
regulatory agencies, which come together to mutually work toward the 
protection of the nation's groundwater supplies. The Interstate Oil 
and Gas Compact Commission is a multistate government agency that 
works to ensure the nation's oil and natural gas resources are 
conserved and maximized while protecting health, safety, and the 
environment. 

[78] Pennsylvania law defines an unconventional formation as a shale 
formation existing below a certain geologic interval where natural gas 
generally cannot be produced economically except by hydraulic 
fracturing or other specialized techniques. 58 Pa. Cons. Stat. § 2301 
(2012). 

[79] A soil horizon is a layer roughly parallel to the soil surface 
whose properties and characteristics differ from the layers above and 
beneath. 

[80] Pennsylvania has five currently operating Class II UIC disposal 
wells, and produced water generated in Pennsylvania is often recycled 
or shipped to other states such as Ohio for disposal. Until recently, 
EPA did not receive many applications for new Class II UIC wells in 
Pennsylvania. In the last 7 months, however, EPA officials said that 
they have received five permit applications for Class II UIC disposal 
wells and expect continued interest in the future. 

[81] Texas has not been authorized to issue NPDES permits for 
activities associated with the exploration, development, or production 
of oil or gas or geothermal resources. EPA is the NPDES permitting 
authority for those facilities in Texas. 

[82] As discussed earlier in this report, EPA sets pretreatment 
standards that apply when wastewater is sent to a facility--such as an 
industrial treatment facility or POTW--before being discharged to 
surface waters. To date, EPA has not set pretreatment standards 
specifically for produced water, though there is a general requirement 
that discharges to POTWs cannot cause the POTW to violate its own 
NPDES permit or interfere with treatment processes. 

[83] The federal secondary standard for drinking water is 500 
milligrams per liter. 

[84] Ohio law provides that, generally, produced water must be 
disposed of only by underground injection, by surface application, in 
association with enhanced recovery of oil or gas resources from a 
well, or by other methods approved by the Chief of the Division of Oil 
and Gas Resources Management within the Ohio Department of Natural 
Resources for testing or implementing a new technology or method of 
disposal. Ohio Rev. Code Ann. § 1509.22(C)(1) (2012). According to 
OEPA officials, the permit did not involve an approved test or 
implementation of a new technology or method of disposal. 

[85] Patriot Water Treatment, LLC v. Korleski, ERAC case Nos. 156477, 
156588, 786501, and 786589 (2012). 

[86] State Review of Oil and Natural Gas Environmental Regulations, 
Inc., Colorado Hydraulic Fracturing State Review (Oklahoma City, OK: 
2011). 

[87] Landfarming is a method of treatment and disposal of low toxicity 
wastewater that involves spreading and mixing the wastewater into the 
soils to promote reduction of organic constituents and dilution and 
attenuation of metals. According to the Texas Railroad Commission, 
landfarming uses the physical, chemical, and biological capabilities 
of the soil-plant system to control waste migration and to provide a 
safe means of disposal without impairing the potential of the land for 
future use. 

[88] Technologically-enhanced NORM is produced when activities 
associated with oil and gas development concentrate or expose 
radioactive materials that occur naturally in soils, water, or other 
natural materials. 

[89] The Susquehanna River Basin Commission--located partially in 
Pennsylvania--also regulates water withdrawals but not water quality 
in the context of oil or gas development and therefore was not 
included in our review. 

[90] The purpose of the Pennsylvania Governor's Marcellus Shale 
Advisory Commission was to develop a comprehensive, strategic proposal 
for the responsible and environmentally sound development of the 
Marcellus Shale. Its membership consisted of the Lieutenant Governor, 
who served as the chair, and appointees chosen by the Governor and 
representing, among other things, the interests of environmental, 
conservation, industry, local and state government groups. 

[91] BLM has also issued leases that underlie lands managed by the 
Park Service and FWS. These lands are generally not available for oil 
and gas development except in special circumstances. For example, FWS 
lands may be leased if an oil and gas operation outside of FWS lands 
is draining federal minerals under the FWS land. For the Park Service, 
small portions of three units of the National Park system are also 
open to federal mineral leasing based on their enabling legislation: 
Glen Canyon National Recreation Area, Lake Mead National Recreation 
Area, and Whiskeytown National Recreation Area. Currently, there are 
no parcels under lease in these areas. In order for oil and gas 
development to occur in these areas, the National Park system regional 
director must consent to the lease and permit, and can do so only upon 
determination that the activity permitted will not have significant 
adverse effect upon the resources or administration of the unit. (43 
C.F.R. § 3109.2(b)). Three other units have a total of 16 wells under 
leases predating these policies. 

[92] Pub. L. No. 91-190 (1970), codified as amended at 42 U.S.C. §§ 
4321-4347 (2012). 

[93] Agencies may prepare an environmental assessment--a concise 
public document--that provides sufficient evidence and analysis for 
determining whether to prepare an environmental impact statement or a 
finding of no significant impact. An environmental impact statement is 
a more detailed statement than an environmental assessment, and NEPA 
implementing regulations specify requirements and procedures--such as 
providing the public with an opportunity to comment on the draft 
document. An environmental impact statement must, among other things, 
(1) describe the environment that will be affected, (2) identify 
alternatives to the proposed action and identify the agency's 
preferred alternative, (3) present the environmental impacts of the 
proposed action and alternatives, and (4) identify any adverse 
environmental impacts that cannot be avoided should the proposed 
action be implemented. The environmental impact statement or 
environmental assessment may also be used to document that the 
proposed leasing action is in compliance with other federal laws, 
including the National Historic Preservation Act (intended to preserve 
historic and archeological sites) and the Endangered Species Act 
(intended to protect threatened and endangered species). 

[94] BLM and the Forest Service also include air quality impacts in 
the NEPA analysis conducted for leasing and permitting actions. 

[95] In implementing requirements on the development of private 
mineral rights, agencies must consider the potential applicability of 
the Fifth Amendment to the U.S. Constitution. The Fifth Amendment 
prohibits the federal government from taking private property for 
public use without justly compensating the private property owner. 
Government regulation may place restrictions on the use of property to 
the extent that it deprives the owner of its use or economic value. In 
such cases of "regulatory taking," the owner may be entitled to just 
compensation under the Fifth Amendment. Thus, if agency requirements 
"regulated" the mineral rights to the point that they were deemed to 
be taken, the agency would have to compensate the owner. See, e.g., 
Foster v. United States, 607 F.2d 943 (Ct. Cl. 1979) (government's 
refusal to allow permit holders of mineral interest on government land 
any right of access for the purpose of extracting minerals was a 
compensable taking). 

[96] In addition, an agency's authority may vary depending on whether 
the private rights were severed from the surface land before the land 
was conveyed to the United States, or were retained by the owner who 
conveyed the land to the United States; whether the lands in question 
are public domain or acquired; and on other factors. 

[97] According to Forest Service officials, private mineral ownership 
is more common in the eastern United States because most eastern 
forest lands were acquired through the 1911 Weeks Act, which had 
different stipulations for mineral rights of lands conveyed to the 
Forest Service. See also Minard Run v. U.S. Forest Service, 2009 WL 
4937785 at *3 (W.D.Pa.) (discussing the Weeks Act); and GAO, Private 
Mineral Rights Complicate the Management of Eastern Wilderness Areas, 
[hyperlink, http://www.gao.gov/products/GAO/RCED-84-101] (Washington, 
D.C.: July 26, 1984). 

[98] See GAO, National Wildlife Refuges: Opportunities to Improve the 
Management and Oversight of Oil and Gas Activities on Federal Lands, 
[hyperlink, http://www.gao.gov/products/GAO-03-517] (Washington, D.C.: 
Aug. 28, 2003). 

[99] Officials said that these other federal authorities could 
include, for example, CWA, Endangered Species Act, or Migratory Bird 
Conservation Act. 

[100] As discussed earlier in this report, three of the six states we 
reviewed--Colorado, Ohio, and Pennsylvania--have requirements that 
encourage or require operators to conduct baseline water testing in 
certain cases. 

[101] 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. 

[102] EPA Region 5 includes Indiana, Illinois, Michigan, Minnesota, 
Ohio, and Wisconsin. 

[103] EPA officials said that, at present, they could specifically 
request this type of information, but do not receive it automatically. 

[104] EPA Region 8 includes Colorado, Montana, North Dakota, South 
Dakota, Utah, and Wyoming. 

[105] GAO, Oil and Gas Management: Interior's Oil and Gas Production 
Verification Efforts Do Not Provide Reasonable Assurance of Accurate 
Measurement of Production Volumes, [hyperlink, 
http://www.gao.gov/products/GAO-10-313] (Washington, D.C.: Mar. 15, 
2010). 

[106] GAO, Oil and Gas Leasing: Past Work Identifies Numerous 
Challenges with Interior's Oversight, [hyperlink, 
http://www.gao.gov/products/GAO-11-487T] (Washington, D.C.: Mar. 17, 
2011). 

[107] For example, Ground Water Protection Council and ALL Consulting. 
"Modern Shale Gas Development in the United States: A Primer." 
Prepared for the Department of Energy and National Energy Technology 
Laboratory. April 2009. Natural Resources Defense Council. "Drilling 
Down: Protecting Western Communities from the Health and Environmental 
Effects of Oil and Gas Production." October 2007. 

[108] Pub. L. No. 93-523, 88 Stat. 1660 (1974) (codified as amended at 
42 U.S.C. §§ 300f-300j-26). Hereinafter, references to SDWA sections 
are as amended. 

[109] SDWA §§ 1421-1426, 42 U.S.C. §§ 300h to 300h-5 (2012). 

[110] 40 C.F.R. § 146.3 (2012). 

[111] 40 C.F.R. § 146.4 (2012). 

[112] 40 C.F.R. § 146.4 (2012). 

[113] 40 C.F.R. § 144.7(b)(3) ("For approved State programs exemption 
of aquifers identified (i) under § 146.04(b) shall be treated as a 
program revision under § 145.32"); § 146.4(b) (allowing exemption of 
aquifers that are producing or are economically producible for 
hydrocarbons); § 145.32 (establishing procedures for EPA approval of 
program revisions). According to EPA officials, nonsubstantial aquifer 
exemptions must be approved by the Regional Administrator, while 
substantial or major aquifer exemptions must be approved by the EPA 
Administrator. See also UIC Program Guidance 34. 

[114] EPA regulations established well classes. 40 C.F.R. § 144.6 
(2012). 

[115] The other classes of UIC program wells are as follows: Class I 
wells are used for the disposal of hazardous and certain nonhazardous 
waste; Class III wells are used to inject fluids for mineral 
extraction; Class IV wells are used to dispose of hazardous or 
radioactive wastes, into or above an underground source of drinking 
water; Class VI wells are used for carbon sequestration. Class IV 
wells are currently banned. Class V wells are for any injection not 
covered by Classes I, II, III, IV, or VI. 

[116] 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). 

[117] SDWA § 1425, 42 U.S.C. § 300h-4 (2012). As explained by EPA, 
under this alternative approval "instead of meeting the Federal 
Regulations (40 C.F.R. Parts 124, 144, and 145) and related Technical 
Criteria and Standards (40 C.F.R. Part 146), a State may demonstrate 
that its program meets the more general statutory requirements of 
Section 1421(b)(1)(A) through (D) and represents an effective program 
to prevent endangerment of underground sources of drinking water." 
See, e.g., 49 Fed. Reg. 13,040 (Apr. 2, 1984) (EPA approval of 
Colorado application). Thus, among other things, the state program 
must include adequate recordkeeping and reporting. The statute also 
provides that "regulations of the Administrator under this section for 
State underground injection control programs may not prescribe 
requirements which interfere with or impede--(A) the underground 
injection of brine or other fluids which are brought to the surface in 
connection with oil or natural gas production or natural gas storage 
operations, or (B) any underground injection for the secondary or 
tertiary recovery of oil or natural gas." SDWA § 1421(b)(2), 42 U.S.C. 
§ 300h(b)(2) (2012). 

[118] See Environmental Appeals Board, Order, UIC Appeal No. 11-03 
(June 28, 2012). 

[119] Id. 

[120] SDWA §§ 1421(b)(1)(A), 1422(c), 42 U.S.C. §§ 300h(b)(1)(A) 
(state programs), 300h-1(c) (EPA direct implementation programs); 40 
C.F.R. § 144.11 (2012). 

[121] See 40 C.F.R. pt. 144 (2012). 

[122] 40 C.F.R. §§ 146.21 - 146.24 (2012). 

[123] 40 C.F.R. §§ 146.24, 146.6 (2012). 

[124] 40 C.F.R. §§ 144.55(a), (b)(2)-(3); 146.7 (2012). 

[125] See Karen Johnson, Chief, Ground Water & Enforcement Branch, EPA 
Region 3, Marcellus Shale Educational Webinar, Feb. 18, 2010 (written 
Q&A). 

[126] 40 C.F.R. §§ 146.24, 146.24(a)(2) (2012). 

[127] 40 C.F.R. § 146.22(a) (2012). 

[128] See 40 C.F.R. §§ 144.27(a), 144.51(h), 144.52(a)(9), 
144.52(b)(1) (2012). 

[129] 40 C.F.R. §§ 144.12(a), 144.1(b), (f) (2012). 

[130] See, e.g., Legal Envtl. Assistance Found. Inc. v. EPA, 118 F.3d 
1467, 1471 (11th Cir.1997). 

[131] Id. 

[132] Ala. Admin. Code r. 400-4-5-.04 (filed July 9, 1999; amended 
Nov. 9, 1999; repealed Apr. 11, 2000). 

[133] 65 Fed. Reg. 2889 (Jan. 19, 2000); 40 C.F.R. § 147.52 (2012). In 
May 2000, Alabama repealed the hydraulic fracturing regulations at 400-
4-5-.04 and established regulations at 400 -3-8-.03. EPA's regulations 
reference the state's repealed regulations. 

[134] Legal Envtl. Assistance Found. Inc. v. EPA, 276 F.3d 1253 (11th 
Cir. 2001). 

[135] See Ala. Admin. Code r. 400 -3-8-.03. 

[136] 69 Fed. Reg. 42,341 (July 15, 2004) (referencing Alabama rule 400 
-3-8-.03). 

[137] EPA, Evaluation of Impacts to Underground Sources of Drinking 
Water by Hydraulic Fracturing of Coalbed Methane Reservoirs, EPA 816-R-
04-003 (2004). 

[138] Memorandum of Agreement Between the United States Environmental 
Protection Agency and BJ Services Company, Halliburton Energy 
Services, Inc., and Schlumberger Technology Corporation, Elimination 
of Diesel Fuel in Hydraulic Fracturing Fluids Injected into 
Underground Sources of Drinking Water During Hydraulic Fracturing of 
Coalbed Methane Wells 4(a) (Dec. 12, 2003). 

[139] 151 Cong. Rec. S7277 (daily ed. June 23, 2005) (letter of 
Benjamin Grumbles, Assistant Administrator, Office of Water, EPA, to 
Senator Jeffords). 

[140] Id. 

[141] Pub. L. No. 109-58 § 322, 119 Stat. 594 (2005) (modifying SDWA § 
1421(d)(1), 42 U.S.C. § 300h(d)(1) (2012)). 

[142] EPA, Permitting Guidance for Oil and Gas Hydraulic Fracturing 
Activities Using Diesel Fuels--Draft: Underground Injection Control 
Program Guidance #84 (May 2012 draft); see also 77 Fed. Reg. 27,451 
(May 10, 2012) (announcing availability of the draft for public 
comment). 

[143] 77 Fed. Reg. at 27,452. 

[144] SDWA requires that EPA approve state programs and revisions by 
regulation, in part 147 (rather than through an administrative 
process). SDWA § 1422(b)(2), (4), 42 U.S.C. § 300h-1(b)(2),(4) (2012). 

[145] For federal regulations setting forth EPA-approved state 
programs, see 40 C.F.R. pt. 147 (2012). 

[146] SDWA § 1423(a), 42 U.S.C. § 300h-2(a) (2012). 

[147] SDWA § 1423(a)(1), 42 U.S.C. § 300h-2(a)(1) (2012). 

[148] SDWA § 1445(b)(1), 42 U.S.C. § 300j-4(b)(1) (2012). 

[149] Titusville Oil and Gas, Docket No. SDWA-03-20,11-0170 (July 19, 
2011). EPA Region 3 officials noted that Pennsylvania Department of 
Environmental Protection also issued several orders at the site, and 
that the wells are being plugged. 

[150] In the Matter of EXCO Resources (PA) LLC, Consent Agreement, EPA 
Docket No. SDWA-03-2012-0061 (Mar. 30, 2012). 

[151] SDWA includes nonregulatory provisions addressing protection of 
drinking water supplies, such as providing incentives and assistance 
for states and public water systems to conduct water quality 
protection planning. See, e.g., SDWA § 1429, 42 U.S.C. § 300h-8 (2012). 

[152] SDWA § 1431, 42 U.S.C § 300i(a) (2012). 

[153] EPA, Fort Peck East Poplar Oil Field Safe Drinking Water Act 
Emergency Administrative Order on Consent, Docket No. SDWA-08-20 12-
0019 (Mar. 26, 2012); see also EPA, Emergency Administrative Order, 
Docket No. SDWA-08-2011-0006 to Murphy Exploration & Production Co.-
USA, Pioneer Natural Resources USA, Inc., and SGH Enterprises, Inc. 
(Dec. 16, 2010). 

[154] In the Matter of Range Resources Corporation, Administrative 
Order, EPA Docket No. SDWA-06-2011-1208 (Dec. 7, 2010). 

[155] United States v. Range Production Co., No. 3:11-cv-00116-F (N.D. 
Tex. Jan. 18, 2011). 

[156] Brief, Range Resources Corporation, et al. v. EPA, No. 11-60040 
(5th Cir. Mar. 22, 2011). 

[157] See Joint Stipulation of Dismissal Without Prejudice, United 
States v. Range Production Co., No. 3:11-CV-00116-F (N.D. Texas Mar. 
30, 2012); see also Range Resources Corporation, et al. v. EPA, No. 11-
60040 (5th Cir. Mar. 30, 2012). 

[158] Letter, Bracewell & Giuliani to EPA Office of Enforcement & 
Compliance Assurance, Mar. 30, 2012. 

[159] The Federal Water Pollution Control Act Amendments of 1972, Pub. 
L. No. 92-500, § 2, 86 Stat. 816 (amending the Act of June 30, 1948, 
ch. 758, 62 Stat. 1155) (codified as further amended at 33 U.S.C. ch. 
26, §§ 1251-1387 (2012) and commonly referred to as the Clean Water 
Act). Hereinafter, references are to CWA sections as amended. 

[160] For the purpose of this document, when we use the term "surface 
waters" in relation to federal regulation, we refer to waters of the 
United States, including jurisdictional rivers, streams, wetlands, and 
other waters. State definitions of the term "surface waters" may 
differ. EPA officials noted that some surface waters may not be 
jurisdictional for certain CWA provisions. 

[161] The U.S. Army Corps of Engineers administers the day-to-day 
program, including issuance of permits and enforcement, among other 
things. EPA has the opportunity to review and comment on individual 
permit applications, can enforce CWA section 404 provisions, and has 
authority to veto Corps permit decisions as to the discharge of 
dredged or fill material at defined sites, among other things. See CWA 
§§ 404, 404(c), 33 U.S.C. §§ 1344, 1344(c) (2012); [hyperlink, 
http://water.epa.gov/lawsregs/guidance/cwa/dredgdis/404c_index.cfm]. 

[162] 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). 

[163] 40 C.F.R. pt. 112 (2012). 

[164] Of the states in our review, EPA is the NPDES permitting 
authority for the oil and gas industry in Texas, and also administers 
the pretreatment program in Colorado, Pennsylvania, and Wyoming. 

[165] CWA also features a system of water quality standards consisting 
of designated uses and water quality criteria, expressed as 
constituent concentrations, levels, or narrative statements, 
representing a quality of water that supports the use. Water quality 
standards play a critical role in the act's framework. For example, if 
technology based limitations are insufficient to meet water quality 
standards, then more stringent water quality based limitations are to 
be added to discharge permits. EPA is currently updating chloride 
water quality criteria with a draft criteria document expected in 
2012; a more stringent chloride criteria could eventually affect 
permit limits for any facility discharging oil and gas wastewater. See 
[hyperlink, http://www.epa.gov/hydraulicfracture/]. 

[166] 76 Fed. Reg. 66,286, 66,296 (Oct. 26, 2011). 

[167] See [hyperlink, http://www.epa.gov/hydraulicfracture/] and 76 
Fed. Reg. at 66,293-97. EPA conducts annual reviews of existing 
effluent guidelines and pretreatment standards and biennially 
publishes a plan identifying the industrial categories selected for 
new or revised rules. 

[168] See [hyperlink, 
http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm]. 

[169] Water-quality based effluent limitations are imposed when 
technology-based limitations are insufficient for receiving waters to 
meet water quality standards. 

[170] See, e.g., 76 Fed. Reg. at 66,288. 

[171] 40 C.F.R. pt. 435 (2012). 

[172] See, e.g., 40 C.F.R. § 435.30 (2012). 

[173] 40 C.F.R. §§ 435.30-.32 (onshore), 435.50-.52 (agricultural and 
wildlife water use), 435.60-.61 (stripper wells) (2012). EPA also has 
developed effluent limitation guidelines for the subcategories 
offshore wells and coastal wells; because this report is focused on 
onshore wells, we do not discuss the guidelines for the offshore 
subcategory. See 40 C.F.R. §§ 435.10-.15 (offshore), 435.40-.47 
(coastal) (2012). EPA's original 1979 rule included coastal wells in 
the subcategory for onshore wells. Following a court order, EPA in 
1982 suspended the applicability of the guidelines for the onshore 
category to coastal wells. 44 Fed. Reg. 22,069 (Apr. 13, 1979), 47 
Fed. Reg. 31,554 (July 21, 1982). See also American Petroleum 
Institute v. EPA, 661 F.2d. 340 (5th Cir. 1981). 

[174] In 1976, EPA issued interim final regulations establishing 
effluent limitation guidelines for the oil and gas extraction category 
and, in 1979, EPA replaced these with final guidelines. 44 Fed. Reg. 
22,069 (Apr. 13, 1979); see also 47 Fed. Reg. 31,554 (July 21, 1982). 

[175] 41 Fed. Reg. 44,942, 44,946-47 (Oct. 13, 1976). EPA has also 
noted that the stripper subcategory may be used to exclude a well from 
other subcategories. In effect, the existence of the subcategory 
authorizes a permit writer to set case-specific permit limitations for 
a well that falls within the stripper subcategory, as it has no 
specific effluent limitations, rather than use those for the onshore 
subcategory. 44 Fed. Reg. at 22,073. 

[176] By definition, such requirements would be inapplicable to the 
agricultural and wildlife use subcategory. 

[177] 76 Fed. Reg. 66,286, 66,293 (Oct. 26, 2011). 

[178] EPA, Technical Support Document for the 2006 Effluent Guidelines 
Program Plan, EPA-821R-06-018, 6-1 (2006). 

[179] EPA has noted that permit writers are to develop technology-
based limits on a case-by-case basis using their best professional 
judgment, and considering the same statutory factors EPA would use in 
promulgating a national categorical effluent limitation guideline. See 
40 C.F.R. §§ 122.44(a)(1),125.3(d) (2012). EPA, Technical Support 
Document for the 2006 Effluent Guidelines Program Plan, EPA-821R-06-
018, 6-3 (2006). 

[180] 40 C.F.R. § 435.32 (2012) (emphasis added). 

[181] 41 Fed. Reg.44,942, 44,946 (Oct. 13, 1976). 

[182] 44 Fed. Reg. 22,069, 22,072 (Apr. 13, 1979). 

[183] 40 C.F.R. §§ 435.50-52 (2012). 

[184] 40 C.F.R. § 435.51(c) (2012). 

[185] EPA issues permits in a small number of states that do not have 
responsibility for the NPDES program, and on tribal lands. 

[186] 76 Fed. Reg. 66,286 (Oct. 26, 2011). 

[187] 76 Fed. Reg. at 66,293. See also [hyperlink, 
http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm]. 

[188] EPA, Coalbed Methane Extraction: Detailed Study Report, EPA-820-
R-10-022 (2010). 

[189] Id. at Appendix A. See also EPA, Technical Support Document for 
the 2006 Effluent Guidelines Program Plan, EPA-821R-06-018, 6-5 (2006) 
(listing numbers of coalbed methane discharge permits derived from 
state permit databases). 

[190] 76 Fed. Reg. at 66,294. 

[191] See [hyperlink, 
http://yosemite.epa.gov/opei/RuleGate.nsf/byRIN/2040-
AF35?opendocument#1], RIN 2040-AF35, docket no. EPA-HQ-OW-2011-0334. 

[192] See generally 40 C.F.R. pt. 403 (2012). 

[193] 40 C.F.R. § 403.5(a)(1) (2012). 

[194] Pass through means a discharge that exits the POTW into waters 
of the United States in quantities or concentrations which, alone or 
in conjunction with a discharge or discharges from other sources, is a 
cause of a violation of any requirement of the POTW's NPDES permit. 40 
C.F.R. § 403.3(p) (2012). Interference is a discharge which, alone or 
in conjunction with a discharge or discharges from other sources, both 
(1) inhibits or disrupts the POTW, its treatment processes or 
operations, or its sludge processes, use or disposal; and (2) 
therefore is a cause of a violation of any requirement of the POTW's 
NPDES permit or prevents sewage sludge use or disposal in compliance 
with relevant laws. 40 C.F.R. § 403.3(k) (2012). 

[195] 40 C.F.R. § 403.5(b)(2) (2012). 

[196] See also 74 Fed. Reg. 58,784, 58,803 (Nov. 13, 2009) (in the 
context of SPCC regulations, stating "Information reviewed by the 
Agency and presented in the public docket (EPA-HQ-OPA-2007-0584-0015) 
showed corrosion as a common cause of oil and produced water 
discharges at onshore oil production facilities. The higher salt 
content of produced water fluids as compared to crude oil may lead to 
the increased corrosion rate of metallic components of the produced 
water storage system"). 

[197] Memorandum from EPA Office of Wastewater Management to EPA 
Regions with answers to frequently asked questions about wastewater 
issues resulting from shale gas extraction (2012), available at 
[hyperlink, http://cfpub.epa.gov/npdes/hydrofracturing.cfm]. 

[198] NPDES permits held by POTWs do typically require monitoring for 
whole effluent toxicity, intended to measure whether the effluent is 
harmful to aquatic life. Some POTWs in Pennsylvania have previously 
accepted produced water; EPA Region 3 officials were unsure if data 
are available regarding whether these POTWs had problems with their 
whole effluent toxicity tests. 

[199] In the Matter of New Castle Sanitation Authority, Findings of 
Violation Order for Compliance and Request for Information, EPA. 
Docket No. CWA-03-2011-0272 DN. 

[200] See EPA, Introduction to the National Pretreatment Program, EPA-
833-B-11-001,3-3 (2011). 

[201] C.F.R. § 403.8(a) (2012); see also [hyperlink, 
http://cfpub.epa.gov/npdes/faqs.cfm?program_id=3]. 

[202] Memorandum from EPA Office of Wastewater Management to EPA 
Regions with Answers To Frequently Asked Questions About Wastewater 
Issues Resulting From Shale Gas Extraction, Attachment at 9 (Mar. 16, 
2011), available at [hyperlink, 
http://cfpub.epa.gov/npdes/hydrofracturing.cfm]. 

[203] 76 Fed. Reg. 66,286, 66,297 (Oct. 26, 2011). 

[204] Memorandum from EPA Office of Wastewater Management to EPA 
Regions with Answers To Frequently Asked Questions About Wastewater 
Issues Resulting From Shale Gas Extraction (Mar. 16, 2011), available 
at [hyperlink, http://cfpub.epa.gov/npdes/hydrofracturing.cfm]. 

[205] Id. at 9; see also 40 C.F.R. § 122.42(b)(1) (2012). 

[206] [hyperlink, http://www.epa.gov/hydraulicfracture/#swdischarges]. 

[207] See, e.g., 76 Fed. Reg. at 66,292, 66,295, 74 Fed. Reg. 68,599 
(Dec. 28, 2009). 

[208] 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. 

[209] Id. at 66,297. 

[210] Id. 

[211] Id. at 66,298. 

[212] See generally Water Quality Act of 1987, Pub. L. No. 100-4 § 
405, 101 Stat. 7, 69-71 (adding CWA § 402(p), codified at 33 U.S.C. § 
1342(p) (2012)). 

[213] Id., 55 Fed. Reg. 47,990, 47,992 (Nov. 16, 1990) (Phase 1 rule). 

[214] 55 Fed. Reg. at 47,990. 

[215] See Multisector General Permit at App. C. 

[216] See EPA, 2012 Construction General Permit Fact Sheet at 6-7, 36. 

[217] Subsequently, EPA added to its regulations a definition of 
overburden: "any material of any nature, consolidated or 
unconsolidated, that overlies a mineral deposit, excluding topsoil or 
similar naturally-occurring surface materials that are not disturbed 
by mining operations." 40 C.F.R. § 122.26(b)(10) (2012). 

[218] Water Quality Act of 1987, § 401, 101 Stat. 65-66 (codified at 
33 U.S.C. § 1342(l)(2) (2012)). 

[219] 55 Fed. Reg. at 48,029, 40 C.F.R. §§ 122.26(b)(14)(iii), 
(c)(1)(iii) (2012). 

[220] Id. The reporting requirements triggering a permit are listed in 
40 C.F.R. §§ 117.21, 302.6, 110.6 (2012). Note that the generally 
applicable industrial stormwater regulations also provide a 
conditional exclusion for discharges composed entirely of stormwater 
if there is no exposure of industrial materials and activities to 
rain, snow, snowmelt and runoff, and where additional conditions are 
satisfied. 40 C.F.R. § 122.26(g) (2012). 

[221] The states are Idaho, Massachusetts, Texas, Oklahoma, and Alaska. 

[222] Specifically, EPA officials identified approximately 34 
notifications from facilities with Standard Industrial Classification 
codes that could indicate that the facility is a well site for 
example, codes 1381 (drilling oil and gas) and 1389 (hydraulic 
fracturing services). 

[223] CWA §§ 402(l)(2), 502(24), 33 U.S.C. §§ 1342(l)(2), 1362(24); 55 
Fed. Reg. 47,990, 48,065 (Nov. 16, 1990) (amending 40 C.F.R. § 122.26; 
see § 122.26(a)(1)(ii), (b)(14)(x)). 

[224] In 2005, EPA revised its regulation to extend the deadline for 
permits for contaminated stormwater discharges associated with small 
construction activity--generally including clearing, grading and 
excavating that results in land disturbance more than 1 acre but less 
than 5 acres--at oil and gas sites to June 12, 2006. 70 Fed. Reg. 
11,560, 11,563 (Mar. 9, 2005) (amending 40 C.F.R. § 122.26(e)(8)). 
Other industry sites requiring permit coverage for small construction 
activity were required to comply by March 2003. [hyperlink, 
http://cfpub.epa.gov/npdes/stormwater/cgp.cfm]. 

[225] Water Quality Act of 1987 § 401 (adding 33 U.S.C. § 1342(l)(2)). 

[226] Energy Policy Act of 2005, Pub. L. No. 109-58, § 323, 119 Stat. 
594, 694 (adding 33 U.S.C. § 1362(24) (2012)). 

[227] 71 Fed. Reg. 33,628 (June 12, 2006) (amending 40 C.F.R. § 
122.26(a)(2)(ii) (2006)). As stated in EPA's fact sheet for the 2006 
revisions, permits would be required only in "very limited instances." 

[228] Natural Resources Defense Council v. EPA, 526 F.3d 591 (9th Cir. 
2008). 

[229] Id. See also [hyperlink, 
http://cfpub.epa.gov/npdes/regresult.cfm?program_id=6&type=1&sort=name&v
iew=all]. 

[230] Compare 40 C.F.R. § 122.26 (2012) with 40 C.F.R. § 122.26 (2005). 

[231] CWA § 309, 33 U.S.C. § 1319 (2012). 

[232] Id., CWA § 301(a), 33 U.S.C. § 1311(a) (2012). As explained 
above, however, discharges of pollutants via stormwater from a well 
site generally does not require a permit, and thus such discharges 
without a permit would not be considered unauthorized, except in 
limited circumstances. 

[233] CWA § 308(a), 33 U.S.C. § 1318(a) (2012). 

[234] CWA § 308(a)(B)(i), 33 U.S.C. § 1318(a)(B)(i) (2012). 

[235] American Petroleum & Environmental Consultants, Inc., Cease and 
Desist Administrative Order, EPA Docket No. CWA-06-2012-1760 (Dec. 12, 
2011). 

[236] BP America Production Company, Combined Complaint and Consent 
Agreement, EPA Docket No. CWA-08-2012-0014 (May 15, 2012). 

[237] CWA § 504, 33 U.S.C. § 1364 (2012). 

[238] 40 C.F.R. pt. 112 (2012); see also 67 Fed. Reg. 47,042 (July 17, 
2002). 

[239] Id. 

[240] 40 C.F.R. § 112.2 (2012) (For purposes of the SPCC rule, "[t]he 
term 'navigable waters' of the United States means 'navigable waters' 
as defined in section 502(7) of the FWPCA, and includes: (1) all 
navigable waters of the United States, as defined in judicial 
decisions prior to the passage of the 1972 amendments of the Federal 
Water Pollution Control Act, (FWPCA) (Pub. L. No. 92-500) also known 
as CWA and tributaries of such waters as; (2) interstate waters; (3) 
intrastate lakes, rivers, and streams that are utilized by interstate 
travelers for recreational or other purposes; and (4) intrastate 
lakes, rivers, and streams from which fish or shellfish are taken and 
sold in interstate commerce."). 

[241] 40 C.F.R. § 112.10 (2012). 

[242] Id. 

[243] 40 C.F.R. § 112.7(g) (2012). See also U.S. Chemical Safety and 
Hazard Investigation Board, Investigative Study Final Report: Public 
Safety at Oil and Gas Storage Facilities, Report No. 2011-H-1 at 8 
(September 2011). 

[244] 73 Fed. Reg. 74,236 (Dec. 5, 2008). 

[245] 74 Fed. Reg. 58,784, 58,799-803 (Nov. 13, 2009). 

[246] Id. at 58,799-803, 58,809-811. 

[247] 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 [hyperlink, http://www.regulations.gov] document 
EPA-HQ-OPA-2007-0584-0015). 

[248] See [hyperlink, www.epa.gov/osweroei/content/spcc/spcc_up.htm], 
[hyperlink, http://www.epa.gov/Region8/opa/wkshop.html] (Cross 
Reference Matrix For Drilling And Workover Facilities). 

[249] The Clean Water Act does not provide EPA with the authority to 
authorize states to implement the program in its place. 

[250] [hyperlink, http://www.gao.gov/products/GAO-08-482]. 

[251] See 40 C.F.R. § 112.3(a)(1) (2012); see generally 40 C.F.R. § 
112.3(a)(1)-(3) (2012) (establishing deadlines for SPCC plans). 

[252] 40 C.F.R. § 112.20 (2012). 

[253] Id. at (f)(1), 40 C.F.R. Pt. 112, App. C, Att. C-1. 

[254] 40 C.F.R. §§ 112.20(b)(1), (c), (f) (2012). 

[255] Id. at (e). 

[256] Id. at (f)(1), App. C, Att. C-1 (2012). For new facilities, the 
facility response plan is to be submitted before startup, for 
facilities commencing operation after Aug. 30, 1994; time frames are 
different for facilities required to submit a plan due to changes in 
operation, among other things. See 40 C.F.R. § 112.20(a)(2)(ii) (2012). 

[257] Id. at (h). 

[258] CWA § 311(b)(1), (3), 33 U.S.C. § 1321(b)(1), (3) (2012). The 
scope of jurisdiction for the section 311 oil spill program is broader 
than that for the NPDES program. The section 311 oil spill program and 
the NPDES program both have jurisdiction over navigable waters of the 
United States; Section 311 also provides jurisdiction over spills of 
oil or hazardous substances into or on adjoining shorelines or that 
may affect natural resources of the United States, among others. 

[259] Id. at (b)(3)-(5). 

[260] 40 C.F.R. § 116.4 (2012), see also CWA § 311(b)(2)(A), 33 U.S.C. 
§ 1321(b)(2)(A) (2012). 

[261] CWA § 311(b)(2)(A), (4), 33 U.S.C. § 1321(b)(2)(A), (4) (2012), 
40 C.F.R. pt. 110, pt. 116-17 (2012). 

[262] CWA § 311(b), 33 U.S.C. § 1321(b) (2012), 40 C.F.R. 110.6 
(2012). See also 33 C.F.R. § 153.203 (2012). 

[263] 40 C.F.R. §§ 110.6, 110.3, 110.1 (2012), [hyperlink, 
http://www.epa.gov/osweroe1/content/reporting/faq_subs.htm#pelist]. 

[264] 40 C.F.R. §§ 117.3; § 116.4 at table 116.4A; see also 40 C.F.R. 
§ 302.4 at table 302.4 (2012). 

[265] CWA § 311(c), 33 U.S.C. § 1321(c) (2012). 

[266] Id., 40 C.F.R. pt. 300 (2012). 

[267] CWA § 311(m)(2), 33 U.S.C. § 1321(m)(2) (2012). 

[268] Id. at (b)(6)-(7), (c), (e)(1)(B) (2012). 

[269] Id. at (m)(2) (2012). 

[270] EPA Region 8, Oil and Gas Environmental Assessment Effort 1996 - 
2002, v (2003). 

[271] Id. at 7. 

[272] Id. at 8. 

[273] Id. at 8. 

[274] EPA Region 8, Summary Report, Oil and Gas Environmental 
Assessment Activities in Wyoming during 2004-2006. 

[275] CWA § 311(e)(1), 33 U.S.C. § 1321(e)(1) (2012). EPA also may, 
through the Department of Justice, file a civil action to secure any 
relief from any person, including the facility owner or operator, as 
may be necessary to abate such endangerment. 

[276] Clean Air Act Amendments of 1970, Pub. L. No. 91-604, 84 Stat. 
1676 (1970) (codified as amended at 42 U.S.C. §§ 7401-7671q (2011)( 
(commonly referred to as the Clean Air Act). Hereinafter, references 
to CAA are as amended. 

[277] See CAA § 109, 42 U.S.C. § 7409 (2012). 

[278] CAA § 110, 42 U.S.C. § 7410 (2012). 

[278] CAA §§ 302(z), 111(a)(3), 112(a)(3), 42 U.S.C. §§ 7602(z), 
7411(a)(3), 7412(a)(3) (2012), 40 C.F.R. §§ 52.21(b)(5), 60.2, 63.3 
(2012). 

[280] 76 Fed. Reg. 52,738, 52,744 (Aug. 23, 2011). EPA's description 
of oil and gas production also includes certain facilities separate 
from the well pad, such as pipelines transporting oil and gas to 
refineries or processing plants, which are outside the scope of GAO's 
review. 

[281] NRDC, Drilling Down: Protecting Western Communities from the 
Health and Environmental Effects of Oil and Gas Production 11 (2007). 

[282] 64 Fed. Reg. 32,610 (June 17, 1999). 

[283] CAA §§ 111(b)(, (f), 112(c)(2), (d), 42 U.S.C. §§ 7411(b), (f), 
7412(c)(2), (d) (2012). 

[284] CAA §§ 165(a), 171-193, 160-169B, 42 U.S.C. §§ 7475(a), 7501-
7515, 7470-7492 (2012). 

[285] CAA § 502, 42 U.S.C. § 7661a (2012), 40 C.F.R. §§ 70.3, 71.3 
(2012). 

[286] CAA § 112(r), 42 U.S.C. § 7412(r) (2012). 

[287] Clean Air Act Amendments of 1990, Pub. L. No. 101-549, Title 
III, § 301, 104 Stat. 2399, 2531; Joint resolution to make a technical 
correction in Public Law 101-549, Pub. L. No. 102-187, 105 Stat. 1285 
(1991). Of the 189 HAPs, two have since been delisted, so the list now 
includes 187 HAPs. 

[288] The listed HAPs are also known as air toxics. 

[289] In other regulatory contexts, hydrogen sulfide is considered 
hazardous; for example, it is a hazardous substance under CERCLA. 40 
C.F.R. § 302.4 table 302.4, (2012). See also EPA, Report to Congress 
on Hydrogen Sulfide Emissions Associated with the Extraction of Oil 
and Gas, EPA-453-R-93/045 (1993) (stating that hydrogen sulfide "is 
toxic and care should be exercised in its presence;" EPA officials 
noted that the purpose of this report was not to examine whether or 
not hydrogen sulfide should included in the HAPs list.). Some have 
argued that hydrogen sulfide, of which oil and gas well emissions may 
be a significant source, should be a HAP. See NRDC, Drilling Down, at 
13. While it was on the list initially enacted in the 1990 amendments, 
by a joint resolution, Congress corrected the inadvertent addition of 
hydrogen sulfide to the list. See page 2 of GAO, Clean Air Act: EPA 
Should Improve the Management of Its Air Toxics Program, [hyperlink, 
http://www.gao.gov/products/GAO-06-669] (Washington, D.C.: Jun. 23, 
2006). Cf. Earthworks and Oil & Gas Accountability Project, The Oil 
and Gas Industry's Exclusions and Exemptions to Major Environmental 
Statutes 14 (2007). 

[290] CAA § 112(b)(2), 42 U.S.C. § 7412(b)(2) (2012). 

[291] 40 C.F.R. § 68.130 (2012). 

[292] The HAP provision also provided for EPA to submit a report to 
Congress in 1992 assessing the hazards to public health and the 
environment resulting from the emission of hydrogen sulfide associated 
with the extraction of oil and natural gas resources, and any 
recommendations, and directed EPA to, as appropriate, develop and 
implement a control strategy for such emissions using existing 
authorities. CAA § 112(n)(5), 42 U.S.C. § 7412(n)(5) (2012). 

[293] Letter from Neil J. Carman, Sierra Club, et al, to Lisa Jackson, 
Administrator, EPA (Mar. 30, 2009). The petition states, among other 
things, that "health studies support the need for EPA to list H2S 
[hydrogen sulfide] 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. 

[294] Id. at 11. 

[295] CAA § 112(d)(1), (d)(6), 42 U.S.C. §§ 7412(d)(1), (d)(6) (2012). 

[296] Id. at § 7412(a)(1)-(2). 

[297] Id. at § 7412(d)(5). 

[298] Id. at § 7412(a)(1), 76 FR 52,741 (Aug. 23, 2011). 

[299] 40 C.F.R. § 63.2 (2012) (defining major source); see also 64 
Fed. Reg. 32,610, 32,613 (June 17, 1999). 

[300] CAA § 112(n)(4)(a), 42 U.S.C. § 7412(n)(4)(a) (2012). 

[301] 40 C.F.R. § 63.760(d) (2012). 

[302] 64 Fed. Reg. at 32,619. 

[303] Id.; 40 C.F.R. § 63.761 (defining "associated equipment"). 

[304] 64 Fed. Reg. 32,610 (June 17, 1999) (the notice also announced 
final rules for the category of natural gas transmission and storage 
facilities), 72 Fed. Reg. 26 (Jan. 3, 2007); 40 C.F.R. pt. 63 Subpt. 
HH. 

[305] 77 Fed. Reg. 49,490 (Aug. 16, 2012). The notice of the final 
rule was signed by the Administrator and a prepublication copy 
released to the public in April 2012. 

[306] 40 C.F.R. §§ 63.760(a)(1), 63.761 (2012). 

[307] 77 Fed. Reg. 49,490 , 49,501, 49,569 (Aug. 16, 2012) (revising 
40 C.F.R. § 63.760, 63.761 to define major source such that "[f]or 
facilities that are production field facilities, only HAP emissions 
from glycol dehydration units and storage vessels shall be aggregated 
for a major source determination."). Storage vessels are defined as a 
tank or other vessel that is designed to contain an accumulation of 
crude oil, condensate, intermediate hydrocarbon liquids, or produced 
water and that is constructed primarily of nonearthen materials (e.g., 
wood, concrete, steel, plastic) that provide structural support. Id. 
at 49,569. 

[308] 64 Fed. Reg. 32,610, 32613 (June 17, 1999), 40 C.F.R. 63.760 
(2012) (small sources are those, prior to the point of custody 
transfer, with a facility-wide actual annual average natural gas 
throughput less than 18.4 thousand standard cubic meters per day and a 
facility-wide actual annual average hydrocarbon liquid throughput less 
than 39,700 liters per day). 

[309] In addition to interviewing EPA officials in the Clean Air 
program and in four Regions, GAO conducted sample searches on the EPA 
Air Facility System database. 

[310] 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)). 

[311] 64 Fed. Reg. 32,610, 32,613-14 (June 17, 1999). 

[312] 40 C.F.R. § 63.765 (2012). 

[313] 40 C.F.R. § 63.765 (2012), 64 Fed. Reg. 32,610, 32,613-14 (June 
17, 1999). 

[314] 40 C.F.R. § 63.766 (2012). 

[315] 77 Fed. Reg. 49,490 ,49,568-71 (Aug. 16, 2012). 

[316] Id. at 49,570-71. 

[317] Id. at 49,568-60 (amending 40 C.F.R. 63.760(f)). 

[318] Id. at 49,503; see also EPA, Summary of Requirements for 
Processes and Equipment at Natural Gas Well Sites. 

[319] 76 Fed. Reg. 52,738, 52,769 (Aug. 23, 2011). 

[320] 77 Fed. Reg. 49,490 , 49,503, 49,528-29 (Aug. 16, 2012). 

[321] Id. at 49,503. 

[322] Id. at 49,501, 49,569 (revising 40 C.F.R. § 63.761). 

[323] CAA § 112(n)(4)(B), 42 U.S.C. § 7412(n)(4)(B) (2012). 

[324] 72 Fed. Reg. 26 (Jan. 3, 2007). 

[325] 40 C.F.R §§ 63.764(d), 63.765(a) (2012). 

[326] 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). 

[327] 72 Fed. Reg. 26, 28 (Jan. 3, 2007), 40 C.F.R §§ 63.764(d), 
63.765(a) (2012). 

[328] 40 C.F.R § 63.764(d) (2012). 

[329] 40 C.F.R. § 63.775(c) (2012); see also 72 Fed. Reg. 26, 30 (Jan. 
3, 2007). 

[330] For example, GAO searched EPA's Air Facility System database to 
identify 40 C.F.R. pt. 63 Subpt. HH MACT area sources with the 
Standard Industrial Classification code for oil and gas extraction. 
Some of the facilities identified in the search results have "well" in 
the facility name, but may include other facilities downstream of the 
well pad; the database does not have information to distinguish the 
well sites among the facilities. 

[331] 40 C.F.R. pt. 63 Subpt. DDDDD, §§ 63.7480-7575 (2012). 

[332] 40 C.F.R. § 63.7485, 76 Fed. Reg. 15,608, 15,619 (Mar. 21, 2011). 

[333] 40 C.F.R. § 63.7500, pt. 63 Subpt. DDDDD Tables 1-2 (Boiler 
NESHAP); cf. 40 C.F.R. pt. 63 Subpt. HH App. Table 1, 64 Fed. Reg. 
32,610 (June 17, 1999) (Oil and Gas NESHAP for major sources). The 
NESHAP for Oil and Gas Production Facilities is focused on BTEX and n-
hexane. 

[334] 40 C.F.R. pt. 63, Subpt. ZZZZ (Stationary Reciprocating Internal 
Combustion Engines). 

[335] CAA § 111(a)(2), (4), 42 U.S.C. § 7411(a)(2), (4). (2012). 

[336] Id. at § 7411(c). 

[337] 40 C.F.R. pt. 60, subparts KKK, LLL. 

[338] 77 Fed. Reg. 49,490 , 49,542-67 (Aug. 16, 2012) (adding 40 
C.F.R. pt. 60 subpt. OOOO, consisting of §§ 60.5360 to 60.5430). 

[339] Id. 

[340] See Consent Decree, Document 25, and Third Stipulation of the 
Parties to Modify Consent Decree, Document 28, Wildearth Guardians et 
al. v. Jackson, No. 1:09-cv-00089-CKK (Dist. D.C. 2011). See also CAA 
§§ 111(b)(1)(B), 112(d)(6), (f)(2), 42 U.S.C. §§ 7411(b)(1)(B), 
7412(d)(6), (f)(2) (2012). 

[341] American Petroleum Institute, Request for Administrative 
Reconsideration and an Administrative Stay of Targeted Elements of 
EPA's Final Rule "Oil and Natural Gas Sector: New Source Performance 
Standards and National Emission Standards for Hazardous Air Pollutants 
Reviews," Aug. 16, 2012. 

[342] 77 Fed. Reg. 49,490, 49,497-98, 49,543 (Aug. 16, 2012) (adding, 
e.g., 40 C.F.R. § 60.5365). 

[343] See EPA, Regulatory Impact Analysis: Final New Source 
Performance Standards and Amendments to the National Emissions 
Standards for Hazardous Air Pollutants for the Oil and Natural Gas 
Industry at 3-12 (April 2012). EPA projected these numbers of affected 
wells for the year 2015, when the rule will be fully in effect, and 
the number of wells affected may actually vary from year to year. At 
the time of the proposed rule, EPA estimated that over 20,000 
completions and recompletions annually would be subject to the 
proposed requirements. 76 Fed. Reg. 52,738, 52,747 (Aug. 23, 2011). 

[344] For pneumatic controllers, an affected source is a single 
continuous bleed natural gas-driven pneumatic controller operating at 
a natural gas bleed rate greater than 6 standard cubic feet per hour 
located between the wellhead and the point of custody transfer to the 
natural gas transmission and storage segment and not located at a 
natural gas processing plant or oil pipeline. 77 Fed. Reg. at 49,543 
(adding 40 C.F.R. § 60.5365(d)(i)).For storage vessels, the threshold 
for coverage is 6 tons per year of VOC. 77 Fed. Reg. at 49,543, 49,556 
(adding 40 C.F.R. §§ 60.5365(e), 60.5430). 

[345] EPA, Regulatory Impact Analysis: Final New Source Performance 
Standards and Amendments to the National Emissions Standards for 
Hazardous Air Pollutants for the Oil and Natural Gas Industry (April 
2012) at 3-12. 

[346] EPA also regulated centrifugal and reciprocating compressors at 
downstream sites, but those located at a well site, or an adjacent 
well site and servicing more than one well site, are not covered. 77 
Fed. Reg. at 49,543 (adding 40 C.F.R. § 60.5365(b), (c)). 

[347] 77 Fed. Reg. at 49,543 (adding 40 C.F.R. § 60.5370(c)) (provided 
the facility is not otherwise required by law to obtain a Title V 
operating permit or new source review permit). 

[348] 40 C.F.R. pt. 60, subpt. Kb (2012). 

[349] 40 C.F.R. § 60.110b(d)(3) (2012). 

[350] 40 C.F.R. pt. 60, subpt. D to Dc (2012). See also EPA, Sector 
Notebook Project: Oil and Gas Extraction, at 100 (2000). 

[351] CAA §§ 165(a), 173(a), 42 U.S.C. §§ 7475(a), 7503(a) (2012); see 
generally CAA §§ 160-169, 171-189, 42 U.S.C. §§ 7470-7479 (Prevention 
of Significant Deterioration), 7501-7513 (NSR nonattainment) (2012). 

[352] Potential to emit generally means the maximum capacity of a 
stationary source to emit any air pollutant under its physical and 
operational design, taking into account any federally enforceable 
limitations. 

[353] CAA §§ 169(1), 165(a), 42 U.S.C. §§ 7479(1), 7475(a) (2012). 

[354] 40 C.F.R. § 52.21(b)(5)-(6) (2012). 

[355] EPA, Report to Congress on Hydrogen Sulfide Emissions Associated 
with the Extraction of Oil and Gas, EPA-453-R-93/045 at IV-37 (1993). 

[356] Gina McCarthy, AA Office of Air and Radiation, Memorandum, 
"Withdrawal of Source Determinations for Oil and Gas Industries" 
(Sept. 22, 2009). 

[357] 40 C.F.R. § 51.165 (2012). 

[358] 40 C.F.R. § 51.165 (2012). 

[359] Major source for Title V purposes is defined more broadly than 
for NESHAP purposes. Cf. CAA § 501(2) to § 112(a)(1), 42 U.S.C. § 
7661(2) to § 7412(a)(1) (2012). 

[360] CAA § 501(2), 42 U.S.C. § 7661(2) (2012), 40 C.F.R. §§ 70.3(a), 
70.5(a)(1)(ii), 71.3(a), 71.5(a)(1)(ii) (2012). 

[361] EPA has the authority to exempt through rulemaking area sources 
or non-major sources from the Title V permit requirement if they are 
not otherwise subject to Title V. CAA § 502(a), 42 U.S.C. §7661a(a) 
(2012). Major sources under Title V may not be exempted. 

[362] 40 C.F.R. §§ 70.3(c)(1), 71.3(c)(1) (2012). 

[363] 40 C.F.R. §§ 70.3(c)(2) 71.3(c)(2) (2012). 

[364] All oil and gas emission units are in the same major industrial 
grouping. 

[365] 40 C.F.R. §§ 71.2, 70.2 (2012) (definition of major source for 
Title V permitting), §§ 51.165(a)(1)(i)-(ii), (iv) (definition of 
major stationary source for NSR), 51.166(b)(5)-(6), 52.21(b)(5)-(6) 
(definitions of stationary source for NSR) (2012). 

[366] See, e.g., Letter, Cheryl L. Newton, EPA Air and Radiation 
Division, to Scott Huber, Summit Petroleum Corporation (Oct. 18, 2010) 
(aggregating gas wells, a sweetening plant, and associated flares as 
constituting a single source for purpose of Title V permitting). 

[367] Gina McCarthy, AA Office of Air and Radiation, Memorandum, 
"Withdrawal of Source Determinations for Oil and Gas Industries" at 2 
(Sept. 22, 2009). 

[368] See, e.g., Roger Martella et al, Aggregation of Oil and Gas 
Wells Under the Clean Air Act: New Horizons from EPA and the Courts, 
Natural Resources and Environment (Fall 2011); [hyperlink, 
http://www.natlawreview.com/article/oil-gas-activities-agencies-are-
air-air-regulations]. 

[369] See Id.; William Wehrum, Memorandum, "Source Determinations for 
Oil and Gas Industries" (Jan. 12, 2007). 

[370] Gina McCarthy, AA Office of Air and Radiation, Memorandum, 
"Withdrawal of Source Determinations for Oil and Gas Industries" 
(Sept. 22, 2009). 

[371] See Summit Petroleum Corp. v. EPA, Nos. 09-4348, 10-4572, slip 
op. (6th Cir. August 7, 2012). 

[372] See EPA, Order Responding To Petitioners' Request That The 
Administrator Object To Issuance Of A State Operating Permit, Petition 
Number: VIII-2010-4 (Feb. 2, 2011). 

[373] WildEarth Guardians et al. v. Jackson, No.11-9527 (10th Cir). 

[374] In re BP America Production Co., Florida River Compression 
Facility, Environmental Appeals Board Appeal No. CAA 10-04. 

[375] Wildearth Guardians v. EPA, Settlement Agreement at 2-3, Docket 
No. 11-9527 (10thCircuit 2011). See also 76 Fed. Reg. 71,027 (Nov. 16, 
2011). 

[376] 74 Fed. Reg. 56,260 (Oct. 30, 2009), 40 C.F.R. pt. 98. 

[377] See, e.g., EPA, Economic Impact Analysis for the Mandatory 
Reporting of Greenhouse Gas Emissions Under Subpart W Supplemental 
Rule (GHG Reporting), Final Report 2-1 - 2-2 (2009). 

[378] 75 Fed. Reg. 74,458 (Nov. 30, 2010), 76 Fed. Reg. 59,533 (Sept. 
27, 2011), 76 Fed. Reg. 73,886 (Nov. 29, 2011), 76 Fed. Reg. 80,554 
(Dec. 23, 2011); 40 C.F.R. pt. 98 Subpt. W. See also [hyperlink, 
http://www.epa.gov/climatechange/emissions/subpart/w.html]. 

[379] EPA, Quantifying Greenhouse Gas Emissions from Key Industrial 
Sectors in the United States 12-2 (Working Draft May 2008). 

[380] EPA, Economic Impact Analysis for the Mandatory Reporting of 
Greenhouse Gas Emissions Under Subpart W Supplemental Rule (GHG 
Reporting), Final Report 1-10 (2009). 

[381] Carbon dioxide equivalent measures the total greenhouse gases, 
accounting for the relative ability of each greenhouse gas to trap 
heat in the atmosphere, known as the global warming potential. 

[382] 40 C.F.R. § 98.232(c), (c)(12)-(13) (well flaring during testing 
and production), (c)(21) (leaks), (c)(22) (combustion) (2012). 

[383] 76 Fed. Reg. 73,886, 73,889, 73,899 (Nov. 29, 2011) (amending 40 
C.F.R. § 98.3). 

[384] 75 Fed. Reg. 74,458, 74,461 (Nov. 30, 2010), 40 C.F.R. § 
98.230(a)(2) (2012). 

[385] 40 C.F.R. §§ 98.238, 98.236(c)(10)-(11) (2012) ( "Facility with 
respect to onshore petroleum and natural gas production for purposes 
of reporting under this subpart and for the corresponding subpart A 
requirements means all petroleum or natural gas equipment on a single 
well-pad or associated with a single well-pad and CO2EOR operations 
that are under common ownership or common control including leased, 
rented, or contracted activities by an onshore petroleum and natural 
gas production owner or operator and that are located in a single 
hydrocarbon basin as defined in §98.238. Where a person or entity owns 
or operates more than one well in a basin, then all onshore petroleum 
and natural gas production equipment associated with all wells that 
the person or entity owns or operates in the basin would be considered 
one facility."). 

[386] 75 Fed. Reg. 74,458, 74,467 (Nov. 30, 2010). 

[387] 75 Fed. Reg. 74,458, 74,479 (Nov. 30, 2010). 

[388] CAA § 112(r)(7), (r)(2)(A), 42 U.S.C. § 7412(r)(7), (r)(2)(A) 
(2012) (defining accidental release as "an unanticipated emission of a 
regulated substance or other extremely hazardous substance into the 
ambient air from a stationary source."). 

[389] Id. at § 7412(r)(3). 

[390] 40 C.F.R. § 68.130 (2012). 

[391] CAA § 112(r)(6), 42 U.S.C. § 7412(r)(6), (6)(C) (2012). 

[392] Id. at § 7412(r)(1). 

[393] 40 C.F.R. § 68.12 (2012). 

[394] 63 Fed. Reg. 640 (Jan. 6, 1998); 65 Fed. Reg. 13,243, 13,244 
(Mar. 13, 2000). 

[395] 40 C.F.R § 68.115(b)(2)(iii), 68.3 (2012); 63 Fed. Reg. 640, 641 
(Jan. 6, 1998). 

[396] 40 C.F.R § 68.115(b)(2)(ii) (2012); 63 Fed. Reg. 640, 641 (Jan. 
6, 1998). 

[397] 40 C.F.R § 68.126 (2012). 

[398] 63 Fed. Reg. 640, 641 (Jan. 6, 1998). 

[399] 65 Fed. Reg. 13,243, 13,245 (Mar. 13, 2000). 

[400] Pub. L. No. 106-40 § 2,113 Stat. 207 (1999) (Section 2 of the 
Act immediately removed EPA's authority to "list a flammable substance 
when used as a fuel or held for sale as a fuel at a retail facility * 
* * solely because of the explosive or flammable properties of the 
substance, unless a fire or explosion caused by the substance will 
result in acute adverse health effects from human exposure to the 
substance, including the unburned fuel or its combustion byproducts, 
other than those caused by the heat of the fire or impact of the 
explosion." 

[401] 65 Fed. Reg. at 13,247. 

[402] 40 C.F.R. § 68.115(b)(2)(iii) (2012). 

[403] CAA § 112(r)(1), 42 U.S.C. § 7412(r)(1) (2012). 

[404] EPA, Report to Congress on Hydrogen Sulfide Emissions Associated 
with the Extraction of Oil and Gas, EPA-453-R-93/045 at IV-35 (1993). 

[405] See [hyperlink, http://www.epa.gov/oem/publications.htm#alerts]. 

[406] CAA § 112(r)(9)(A), 42 U.S.C. § 7412(r)(9)(A) (2012). 

[407] U.S. Chemical Safety and Hazard Investigation Board, 
Investigative Study Final Report: Public Safety at Oil and Gas Storage 
Facilities, Report No. 2011-H-1 (September 2011) [hereinafter Chemical 
Safety Board Report]. 

[408] Note that the Clean Water Act spill prevention control, and 
countermeasure (SPCC) rule requires oil and gas production facilities 
meeting applicability thresholds to prepare SPCC plans generally by 
November 2011, or before commencing operation. 40 C.F.R. pt. 112 
(2012). However, oil production facilities are excluded from the SPCC 
regulations' security provisions. Id. at § 112.7(g). 

[409] Chemical Safety Board Report at 8. See 40 C.F.R. § 112.7(g) 
(2012). 

[410] Chemical Safety Board Report at 52. 

[411] See CAA § 112(r)(6)(I), 42 U.S.C. § 7412(r)(6)(I) (2012). See 
also [hyperlink, 
http://www.csb.gov/recommendations/details.aspx?SID=95&pg=1&F_Investigat
ionId=95]. 

[412] Regarding the four specific items the Board recommended for 
inclusion, EPA stated that it will address three, but the fourth item 
is under the jurisdiction of another agency. 

[413] Chemical Safety Board Report at 52-54. 

[414] CAA § 113(a)(1) and (3), 42 U.S.C. § 7413(a)(1) and (3) (2012); 
see generally CAA § 113, 42 U.S.C. § 7413 (2012). 

[415] CAA § 114(a), 42 U.S.C. § 7414(a) (2012). 

[416] CAA § 303, 42 U.S.C. § 7603 (2012). 

[417] Pub. L. No. 94-580, 90 Stat. 2795 (1976) (codified as amended at 
42 U.S.C. §§6901-6992k (2012)). Although RCRA amended the Solid Waste 
Disposal Act, Pub. L. No. 89-272, Title II, 79 Stat. 997 (1965), the 
amended law is nonetheless sometimes referred to as RCRA, a convention 
we follow here. Subtitle C of RCRA, 42 U.S.C. ch. 82, subch. III (§§ 
6921-6939f), governs hazardous waste management. Hereinafter, 
references are to RCRA sections as amended. 

[418] RCRA Subtitle D, 42 U.S.C. ch. 82, subch. IV (§§ 6941-6949a) 
(2012). 

[419] RCRA § 3006(b), 42 U.S.C. § 6926(b) (2012). 

[420] RCRA §§ 4006-09, 4004(a), 4005(a), 42 U.S.C. §§ 6946-49, 
6944(a), 6945(a) (2012). 

[421] RCRA § 1004(5), 42 U.S.C. § 6903(5) (2012). 

[422] 40 C.F.R. §§ 261.3 (2012). Some wastes otherwise meeting the 
definition are excluded from regulation as a hazardous waste; see 40 
C.F.R. § 261.4 (2012). 

[423] See, e.g., RCRA §§ 3002, 3003, 3004, 42 U.S.C. §§ 6922, 6923, 
6924 (2012). 

[424] Pub. L. No. 96-482 § 7, 94 Stat. 2334, 2336 (1980), 42 U.S.C. § 
6921(b)(2) (2012). 

[425] Pub. L. No. 96-482 § 29(2), 94 Stat., 2350 (1980), amending RCRA 
§ 8002(m), 42 U.S.C. § 6982(m) (2012). 

[426] Id. 

[427] 42 U.S.C. § 6921(b)(2)(B)-(C) (2012). 

[428] 53 Fed. Reg. 25,446, 25,447 (July 6, 1988). The study, titled 
"Management of Wastes from the Exploration, Development, and 
Production of Crude Oil, Natural Gas, and Geothermal Energy " was 
submitted to Congress in December 1987. See also Clarification of the 
Regulatory Determination for Wastes From the Exploration, Development 
and Production of Crude Oil, Natural Gas and Geothermal Energy, 58 
Fed. Reg. 15,284 (Mar. 22, 1993). 

[429] 53 Fed. Reg. at 25,450. 

[430] Id. at 25,446. 

[431] Id. at 25,447. 

[432] Id. 

[433] Id. 

[434] Id. at 25,457. 

[435] EPA, Exploration & Production Waste and RCRA, presented at 
ASTSWMO Annual Meeting (Oct. 26, 2011). 

[436] The STRONGER program is conducted through the Ground Water 
Protection Council and brings together stakeholders to examine state 
oil and gas regulations and make recommendations for improvement. 

[437] 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). 

[438] See RCRA § 7004(a), 42 U.S.C. § 6974(a) (2012) (requiring only 
that EPA shall take action on a petition to promulgate regulations 
"within a reasonable time following receipt" of the petition.) 

[439] EPA, Exploration & Production Waste and RCRA, presented at 
ASTSWMO Annual Meeting (Oct. 26, 2011). 

[440] 40 C.F.R. § 261.5, pt. 262 (2012). 

[441] Id. at § 261.5(a). 

[442] Id. at (g)(2). 

[443] Id. at § 262.11. 

[444] Id. at § 261.5(g)(3). If the facility generates a subset of 
hazardous waste known as acute hazardous waste, it is subject to 
additional requirements for that waste. Id. at § 261.5(f)(3). 

[445] Id. at §§ 261.5(b), 262.12. 

[446] Id. at § 261.34. 

[447] Id. at § 262.11. 

[448] Id. at g)(3). If the facilities generate a subset of hazardous 
waste known as acute hazardous waste, it is subject to additional 
requirements for that waste. Id. at § 261.5(f)(3). 

[449] Id. at §§ 262.12, 262.20. 

[450] 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.). 

[451] See EPA Form 8700-12. 

[452] Biennial reports are only required of large quantity generators. 
The reports are to include, among other things, a description of the 
generated hazardous wastes and the quantities shipped off-site to a 
U.S. treatment, storage, or disposal facility. 40 C.F.R. § 262.41 
(2012). 

[453] NAICS code 211111, Crude Petroleum and Natural Gas Extraction. A 
further complication in the context of this report is our scope is 
focused on unconventional resources produced using land-based wells, 
where the NAICS code at the six-digit level does not reflect these 
distinctions and includes other resources and offshore wells. 

[454] EPA officials from one Region believed some well sites may be 
small quantity generators of hazardous waste. 

[455] See, e.g., RCRA §§ 1003(a)(1)-(3), 4001, 42 U.S.C. §§ 6902(a)(1)-
(3), 6941 (2012). 

[456] See, e.g., RCRA § 1008, 42 U.S.C. § 6907 (2012), 40 C.F.R. pt. 
243 (2012) (Guidelines for the Storage and Collection of Residential, 
Commercial, and Institutional Solid Waste, containing guidelines that 
are recommended but not required for states). 

[457] In addition, for two types of solid waste disposal facilities 
(those receiving conditionally exempt small quantity generator waste 
and household hazardous wastes), RCRA provided that states must 
implement an EPA-approved system to assure the facilities comply with 
EPA criteria, or the facilities would be subject to EPA hazardous 
waste enforcement authorities. RCRA § 4005(c)(1)(A)-(B), 42 U.S.C. § 
6945(c)(1)(A)-(B) (2012) (providing that each State shall adopt and 
implement a permit program or other system of prior approval and 
conditions to assure that each solid waste management facility within 
such State which may receive hazardous household waste or hazardous 
waste [from small quantity generators] will comply with," 
respectively, the applicable initial and revised criteria established 
by EPA), RCRA § 4005(c)(1)(C), 42 U.S.C. § 6945(c)(1)(C) (2012) (EPA 
shall determine if each program is adequate); see 40 C.F.R. pts. 239, 
257 subpt. B; 258 (2012). 

[458] RCRA §§ 1008(a)(3), 4004, 42 U.S.C. §§ 6907(a)(3), 6944, 40 
C.F.R. § 257.1, pt. 257, § 258.1(g), pt. 258 (2012). See also 53 Fed. 
Reg. 25,446 (July 6, 1988) (noting that "[t]he existing Federal 
standards under Subtitle D of RCRA provide general environmental 
performance standards for disposal of solid wastes, including oil, 
gas, and geothermal wastes, but these standards do not fully address 
the specific concerns posed by oil and gas wastes. Nevertheless, EPA 
has authority under Subtitle D to promulgate more tailored criteria."). 

[459] RCRA § 4005(a), 42 U.S.C. §§ 6945(a) (2012). 

[460] RCRA §§ 3007, 3008, 3013, 42 U.S.C. §§ 6927, 6928, 6934 (2012). 

[461] Cf. RCRA § 1004(5), 42 U.S.C. § 6903(5) (2012) with 40 C.F.R. §§ 
261.3,-4 (2012). 

[462] RCRA § 3008, 42 U.S.C. § 6928 (2012). 

[463] EPA also has authorities to require corrective action or such 
other response measure as necessary to protect human health or the 
environment from past and present contamination, at RCRA permitted or 
interim status facilities--that is, where the facility is a storage, 
treatment, or disposal facility and has or should have a Subtitle C 
hazardous waste permit. EPA can use this corrective action authority 
only at facilities that are RCRA permitted or interim status 
facilities, and cannot require a corrective action at a generator-only 
facility. Interim status facilities are facilities that treat, store, 
or dispose of hazardous waste and have begun the process of applying 
for a RCRA permit. See RCRA §§ 3004(u)-(v), 3008(h), 42 U.S.C. §§ 
6924(u)-(v), 6928(h) (2012). 

[464] RCRA § 3007(a), 42 U.S.C. § 6927(a) (2012). 

[465] Id. at § 6927(e) (2012). 

[466] See, e.g., 53 Fed. Reg. 25,446, 25,457 (1988) ("EPA believes 
this [section 3007] authority does not limit information collection to 
"hazardous" waste identified under Subtitle C, but also authorizes the 
collection of information on any solid waste that the Agency 
reasonably believes may pose a hazard when improperly managed. (EPA 
may also use this authority in preparing enforcement actions.)"). 

[467] RCRA § 3013(a), 42 U.S.C. § 6934(a) (2012). 

[468] Id. at § 6934(d) (2012). 

[469] RCRA § 7002, 42 U.S.C. § 6972 (2012). RCRA section 7002 
authorizes citizen and state suits including against any person who is 
alleged to be in violation of any permit, standard, regulation, 
condition, requirement, prohibition, or order which has become 
effective pursuant to RCRA, or who has contributed or is contributing 
to the past or present handling, storage, treatment, transportation, 
or disposal of any solid or hazardous waste which may present an 
imminent and substantial endangerment to health or the environment. 
Citizen suits are subject to various conditions, such as a requirement 
for advance notice to EPA and the state, and that neither EPA nor the 
state is taking certain actions to address the problem. 

[470] RCRA § 7003, 42 U.S.C. § 6973 (2012). 

[471] Id. at § 6973(a). 

[472] Id. at § 6973(b). 

[473] RCRA § 1004(5), (27), 42 U.S.C. § 6903(5), (27) (2012). 

[474] See EPA. Office of Enforcement and Compliance Assurance, 
Guidance on the Use of Section 7003 of RCRA (October 1997). 

[475] EPA Region 8, Oil and Gas Environmental Assessment Effort 1996 - 
2002, at v (2003). 

[476] Id. at 8. 

[477] Id. 

[478] In the Matter of Jim's Water Service, Initial Administrative 
Order, EPA Docket No. RCRA-08-2011-0002 (June 23, 2011); In the Matter 
of Pure Petroleum LLC, Administrative Order, EPA Docket No. RCRA-08-
2011-0003 (Sept. 16, 2011). See also Consent Decree, United States of 
America v. High Plains Resources, Inc., No. 2:09-cv-00087 (Wy. Nov. 3, 
2010). 

[479] West Bay Exploration, Agreement and Remediation Plan, EPA Docket 
No. RCRA-06-2005-0913 (Sept. 14, 2005). 

[480] CERCLA, Pub. L. No. 96-510, 94 Stat. 2767 (1980) (codified as 
amended at 42 U.S.C. §§ 9601-9675 (2012)). Hereinafter, references to 
CERCLA sections are as amended. 

[481] CERCLA § 104, 42 U.S.C. § 9604 (2012). 

[482] CERCLA § 103(a), 42 U.S.C. § 9603(a) (2012). 

[483] Parties may also be held liable under CERCLA for damages related 
to the loss, injury or destruction of natural resources. 

[484] CERCLA § 101(14), 42 U.S.C. § 9601(14) (2012) (defining 
hazardous substance to exclude "petroleum, including crude oil or any 
fraction thereof which is not otherwise specifically listed or 
designated as a hazardous substance under [specified provisions of 
CWA, RCRA, CAA, and 15 U.S.C. § 2606], and the term does not include 
natural gas, natural gas liquids, liquefied natural gas, or synthetic 
gas usable for fuel (or mixtures of natural gas and such synthetic 
gas)."); CERCLA § 101(33), 42 U.S.C. § 9601(33) (with similar 
language, excluding petroleum from the definition of "pollutant or 
contaminant"). See also [hyperlink, 
http://www.epa.gov/superfund/policy/release/rq/index.htm#exclude]. 
Such releases may be reportable under provisions of other laws, such 
as the Oil Pollution Act of 1990 and Clean Water Act; see CWA § 
311(b)(3)-(5), 33 U.S.C. § 1321(b)(3)-(5) (2012); 40 C.F.R. § 
300.300(b) (2012). 

[485] See [hyperlink, 
http://www.epa.gov/superfund/policy/release/rq/index.htm#exclude]. 
Releases of certain waste oils are also regulated under CERCLA. 40 
C.F.R. § 302.4 (2012). 

[486] CERCLA § 101(10), 42 U.S.C. § 9601(10) (2012). See also 
exclusions at id. § 9601(22) (2012). 

[487] Id. at § 9601(10)(I) (2012). This provision was included in 
CERCLA as enacted in 1980. Pub. L. No. 96-510 § 101, 94 Stat. 2768 
(1980). See also 53 Fed. Reg. 27,268 (July 19, 1988). 

[488] 53 Fed. Reg. at 27,275. 

[489] CERCLA § 103(a), 42 U.S.C. § 9603(a) (2012). The National 
Response Center is the sole federal point of contact for reporting all 
hazardous substances and oil spills that trigger federal notification 
requirements under several laws. Information reported to the Center is 
disseminated to other agencies, such as EPA, as well as to states. 

[490] 40 C.F.R. pt. 302, § 302.4 at table 302.4 (2012). 

[491] See [hyperlink, 
http://www.epa.gov/superfund/policy/release/rq/index.htm#exclude]. 
Releases of certain waste oils are also regulated under CERCLA. 40 
C.F.R. § 302.4 (2012). 

[492] Through Executive Order 12580, Superfund Implementation (1987), 
EPA was delegated key regulatory and enforcement authorities CERCLA 
granted to the President. In addition, CERCLA, as amended, granted 
certain authorities directly to the EPA Administrator. 

[493] Under CERCLA, potentially responsible parties generally include 
current or former owners and operators of a site or the generators or 
transporters of the hazardous substances. 

[494] 40 C.F.R. § 300.5 (2012) (defining removal as including 
containment and removal of hazardous substances or other actions as 
may be necessary to minimize or mitigate damage to the public health 
or welfare of the United States or to the environment, and defining 
remedial action as including actions consistent with permanent remedy 
to prevent or minimize the release so that they do not migrate to 
cause substantial danger to present or future public health or welfare 
or the environment.) For more information, see 40 C.F.R. § 300.415 
(removals), 300.430, 300.435 (remedial actions). 

[495] EPA, Memorandum, "Use of Non-Time Critical Removal Authority in 
Superfund Response Actions" (2000). 

[496] CERCLA § 104(a)(1), (b), 42 U.S.C. § 9604(a)(1), (b) (2012). 

[497] Id. 

[498] Id. at § 9604(e). 

[499] Id. at § 9604(e)(1)-(2). 

[500] Id. at § 9604(e)(3)-(4). 

[501] Id. at § 9604(e)(4)-(5). 

[502] Id. at § 9604(e)(5). 

[503] Id. at § 9604(a). In addition to removal actions, EPA may also 
conduct remedial actions at nonfederal sites which are listed on the 
National Priorities List, but it is somewhat unlikely an oil and gas 
well site would be listed on the National Priorities List in light of 
the petroleum exclusion, among other factors. CERCLA §§ 104(a), 
(c)(1), 111(e), 42 U.S.C. §§ 9604(a), (c)(1), 9611(e) (2012). The 
National Priorities List includes sites that EPA determines are among 
the nation's most seriously contaminated hazardous waste sites to 
receive attention under the federal Superfund program. 

[504] CERCLA § 101(23), 42 U.S.C. § 9601(23) (2012). 

[505] See id. at § 9601(33) . EPA cannot, however, recover its 
response costs associated with these releases. 

[506] EPA has promulgated regulations comprising the National Oil and 
Hazardous Substances Pollution Contingency Plan. 40 C.F.R. pt. 300 
(2012). This plan outlines procedures and standards for implementing 
the Superfund program. 

[507] CERCLA § 106(a), 42 U.S.C. § 9606(a) (2012). 

[508] Id. at § 9606(a). 

[509] See, e.g., CERCLA §§ 107, 122, 42 U.S.C. §§ 9607, 9622 (2012). 

[510] See DOJ, news release (Sept. 23, 1999). 

[511] See DOJ, news release (Sept. 23, 1999). See also, United States 
of America v. BP Exploration (Alaska) Inc., Plea Agreement (Sept. 23, 
1999), Stipulation of Settlement and Order (Sept. 23, 1999), Docket 
no. 3:99-cv-00549-JKS (D. Alaska). 

[512] 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. 

[513] See EPA, Draft Report, Investigation of Ground Water 
Contamination near Pavillion, Wyoming, EPA 600/R-00/000 (December 
2011) at xi, 1. 

[514] Agency for Toxic Substances and Disease Registry, Health 
Consultation, Chesapeake ATGAS 2H Well Site, Leroy Hill Road, Leroy 
Township, Bradford County, PA (2011). 

[515] Pub. L. No. 99-499, Title III, 100 Stat. 1728 (1986) (codified 
at 42 U.S.C. ch. 116 (2012)). Hereinafter, references to EPCRA 
sections are as amended. 

[516] In addition to EPCRA sections 304, 311, and 312, 42 U.S.C. §§ 
11004, 11021, 11022 (2012), provisions discussed herein, section 302, 
42 U.S.C. § 11002 (2012) requires the owner or operator of a facility 
to provide notification to the state and local emergency planning 
authorities with jurisdiction over the facility within 60 days if any 
extremely hazardous substances--including ammonia, hydrofluoric acid, 
and others--are present at or above its threshold planning quantity. 
See generally 40 C.F.R. pt. 355 (2012). 

[517] EPCRA § 304(a), 42 U.S.C. §§ 11004(a) (2012). See also EPA, List 
of Lists (2011) available at [hyperlink, 
http://www.epa.gov/emergencies/docs/chem/list_of_lists_revised_7_26_2011
.pdf] The reporting requirement does not apply, however, to releases 
which results in exposure to persons solely at the site where the 
facility is located, nor to federally permitted releases under the 
CERCLA definition. Id. at § 11004(a)(2), (4). 

[518] Pub. L. No. 96-510, 94 Stat. 2767 (1980) (codified at 42 U.S.C. 
ch. 103 (2012)). 

[519] See 40 C.F.R. § 355.60 (2012). Three types of releases must be 
reported: (1) release of extremely hazardous substances for which 
notification is also required under CERCLA § 103(c), (2) release of 
extremely hazardous substances for which notification is not required 
under CERCLA § 103(c), but above reporting thresholds and subject to 
additional conditions, and (3) release of other hazardous substances 
for which notification is also required under CERCLA § 103(c), subject 
to CERCLA reporting thresholds or 1 pound default threshold. 

[520] EPCRA §§ 302(b)(1), 304(a), 42 U.S.C. §§ 11002(b)(1), 11004(a) 
(2012); 40 C.F.R. § 370.10(a) (2012). Hazardous chemicals are defined 
as any chemical which is a physical hazard or a health hazard. EPCRA § 
311(e), 42 U.S.C. § 11021(e) (2012), 40 C.F.R. § 355.61, 370.66 
(2012), 29 C.F.R. § 1910.1200(c) (2012). 

[521] EPCRA § 302(b)(1), 311(a)-(b), 312(a)-(b), 42 U.S.C. §§ 
11002(b)(1), 11021, 11022 (2012), and 40 C.F.R. § 370.44 (2012). 

[522] The reporting trigger for Section 304--that a facility produce, 
use, or store any hazardous chemical--does not require that the 
chemicals be present or stored on the site for any minimum period of 
time. 

[523] 40 C.F.R. § 370.10(a)(2)(i) (2012). 

[524] FracFocus is the national hydraulic fracturing chemical registry 
managed by the Ground Water Protection Council and Interstate Oil and 
Gas Compact Commission. The Ground Water Protection Council is a 
national association of state groundwater and underground injection 
control agencies whose mission is to promote the protection and 
conservation of groundwater resources for all beneficial uses, 
recognizing groundwater as a critical component of the ecosystem. The 
Interstate Oil and Gas Compact Commission is a multistate government 
agency that promotes the conservation and efficient recovery of 
domestic oil and natural gas resources while protecting health, 
safety, and the environment. 

[525] Cf. [hyperlink, http://fracfocus.org/chemical-use/what-chemicals-
are-used] and 40 C.F.R. § 302.4 (2012). 

[526] EPCRA sections 311 and 312, 42 U.S.C. §§ 11021, 11022 (2012), 
require reporting to the state and local emergency planning 
authorities and to the local fire department with jurisdiction over 
the facility; EPA does not receive these reports. 

[527] EPA also provided information from an example of a section 312 
form from a field service provider for the provider's facility where 
larger quantities of chemicals are stored and then loaded on trucks to 
service the wells. 

[528] The Pollution Prevention Act of 1990, Pub. L. No. 101-508 , 
Title VI, 104 Stat. 1388-321 (1990) (codified at 42 U.S.C. ch. 133 
(2012)) requires facilities subject to EPCRA section 313 to also 
report annually toxic chemical source reduction and recycling 
activities. 42 U.S.C. § 13106(a)-(b) (2012). 

[529] EPCRA § 313(g)(1)(C), 42 U.S.C. § 11023(g)(1)(C) (2012). 

[530] Id. at (i). 

[531] Pollution Prevention Act, § 6607, 42 U.S.C. § 13106 (2012). 

[532] EPCRA § 313(h), 42 U.S.C. § 11023(h) (2012). 

[533] 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). 

[534] Community Right-to-Know; Toxic Chemical Release Reporting Using 
NAICS, 71 Fed. Reg. 32,464, 32,465 (June 6, 2006); see generally 
[hyperlink, http://www.epa.gov/tri/lawsandregs/naic/ncodes.htm].  

[535] 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). 

[536] 53 Fed. Reg. 4500 (Feb. 16, 1988). 

[537] Id. at 4503 (stating "EPA has discretionary authority to modify 
the coverage of facilities under section 313(b)(1)(B). The report of 
the congressional conference committee for Title III states that any 
such modifications are limited "* * * to adding [Standard Industrial 
Classification] codes for facilities which, like facilities within the 
manufacturing sectors Standard Industrial Classification codes 20 
through 39, manufacture, process or use toxic chemicals in a manner 
such that reporting by these facilities is relevant to the purposes of 
this section… The Agency is choosing not to modify the facility 
coverage of the rule at this time...The Agency must carefully evaluate 
additional types of facilities that may be manufacturing, processing, 
or using listed toxic chemicals as well as facilities in [Standard 
Industrial Classification] codes 20 through 39 that do not handle such 
chemicals."). 

[538] See [hyperlink, 
http://www.epa.gov/tri/lawsandregs/naic/ncodes.htm]. 

[539] EPA Office of Compliance, Sector Notebook Project: Profile of 
the Oil and Gas Extraction Industry 114 (October 2000). 

[540] These industries included metal mining, coal mining, electrical 
utilities that combust coal and/or oil for the purpose of generating 
power for distribution in commerce, certain hazardous waste processing 
or destruction facilities regulated by EPA, chemical wholesalers, 
petroleum terminals and bulk stations and solvent recovery services. 

[541] Addition of Facilities in Certain Industry Sectors; Revised 
Interpretation of Otherwise Use; Toxic Release Inventory Reporting; 
Community Right-to-Know, 62 Fed. Reg. 23,834 (May 1, 1997) (known as 
the Industry Expansion Rule). In announcing the rule, EPA stated, "EPA 
believes that [section 313(b)(1)(B)] grants the Agency broad, but not 
unlimited, discretion to add industry groups to the facilities subject 
to EPCRA section 313 reporting requirements where EPA finds that 
reporting by these industries would be relevant to the purposes of 
EPCRA section 313." See also 71 Fed. Reg. 32,464, 32,465 (June 6, 
2006). 

[542] 61 Fed. Reg. 33,588, 33,592 (June 27,1996). 

[543] 62 Fed. Reg. 23,834, 23,855 (1997). 

[544] [hyperlink, 
http://exchange.regulations.gov/exchange/topic/trisectorsrule/agencyintr
o/tri-exchange]. 

[545] In July 2012, EPA officials stated that if the sector is not 
proposed to be added to the TRI, the agency does not anticipate 
placing documents related to EPA's consideration of the oil and gas 
production sector in the docket for any possible TRI rulemaking. 

[546] See, e.g., 75 Fed. Reg. 72,727 (Nov. 6, 2010) (EPA's most recent 
addition to the TRI list of chemicals, adding 16 chemicals reasonably 
expected to be carcinogenic). 

[547] 61 Fed. Reg. 33,588, 33,592 (June 27,1996). 

[548] 76 Fed. Reg. 64,022 (Oct. 17, 2011). 

[549] Id. at 64,025. 

[550] EPCRA § 325, 42 U.S.C. § 11046 (2012). 

[551] Id. at § 11046(c)(1), (2), (4). 

[552] Id. at § 11046( b). 

[553] Pub. L. No. 94-469, 90 Stat. 2003 (1976) (codified as amended at 
15 U.S.C. §§ 2601 -2692 (2012)). Hereinafter, references to TSCA are 
as amended. TSCA addresses those chemicals manufactured or imported 
into the United States, but it generally excludes certain substances, 
such as pesticides that are regulated under the Federal Insecticide, 
Fungicide, and Rodenticide Act, and any food, food additive, drug, 
cosmetic, or device regulated under the Federal Food, Drug, and 
Cosmetics Act. 

[554] For example, prior to requiring testing under section 4, the act 
requires EPA to either make findings regarding the risk of injury to 
health or the environment or findings regarding human exposure, as 
well as findings regarding the sufficiency of existing data and that 
testing with respect to such effects is necessary to develop needed 
data. TSCA § 4(a), 15 U.S.C. § 2603(a) (2012). 

[555] See [hyperlink, 
http://www.epa.gov/oppt/existingchemicals/pubs/tscainventory/basic.html#
background]; GAO, Chemical Regulation: Options for Enhancing the 
Effectiveness of the Toxic Substances Control Act, [hyperlink, 
http://www.gao.gov/products/GAO-09-428T] (Feb. 26, 2009). 

[556] See, e.g., TSCA § 8(a), (c), (d), 15 U.S.C. § 2607(a), (c), (d) 
(2012). Regulations also require users to take actions under the 
hazard communication provisions for certain substances in the 
workplace. See 40 C.F.R. §§ 721.3, 721.72 (2012). 

[557] FracFocus is the national hydraulic fracturing chemical registry 
managed by the Ground Water Protection Council and Interstate Oil and 
Gas Compact Commission. The Ground Water Protection Council is a 
national association of state groundwater and underground injection 
control agencies whose mission is to promote the protection and 
conservation of groundwater resources for all beneficial uses, 
recognizing groundwater as a critical component of the ecosystem. The 
Interstate Oil and Gas Compact Commission is a multi-state government 
agency that promotes the conservation and efficient recovery of 
domestic oil and natural gas resources while protecting health, 
safety, and the environment. [hyperlink, http://www.fracfocus.org].  

[558] See [hyperlink, 
http://www.epa.gov/oppt/existingchemicals/pubs/tscainventory, 
http://fracfocus.org/chemical-use/what-chemicals-are-used]. 

[559] Earthjustice et al., Letter to Lisa P. Jackson, EPA 
Administrator, re: Citizen Petition under Toxic Substances Control Act 
Regarding the Chemical Substances and Mixtures Used in Oil and Gas 
Exploration or Production, Aug. 4, 2011. See also [hyperlink, 
http://www.epa.gov/oppt/chemtest/pubs/petitions.html#petition10].  

[560] Earthjustice et al., Letter to Lisa P. Jackson, EPA 
Administrator, re: Citizen Petition under Toxic Substances Control Act 
Regarding the Chemical Substances and Mixtures Used in Oil and Gas 
Exploration or Production, 2, Aug. 4, 2011. 

[561] Stephen A. Owens, Assistant Administrator EPA, Letter to Deborah 
Goldberg, Earthjustice, Re: TSCA Section 21 Petition Concerning 
Chemical Substances and Mixtures Used in Oil and Gas Exploration or 
Production, Nov. 2, 2011. 

[562] Earthjustice et al., Letter to Lisa P. Jackson, EPA 
Administrator, re: Citizen Petition under Toxic Substances Control Act 
Regarding the Chemical Substances and Mixtures Used in Oil and Gas 
Exploration or Production, Aug. 4, 2011. 

[563] Stephen A. Owens, Assistant Administrator EPA, Letter to Deborah 
Goldberg, Earthjustice, Re: TSCA Section 21 Petition Concerning 
Chemical Substances and Mixtures Used in Oil and Gas Exploration or 
Production, Nov. 23, 2011. 

[564] TSCA § 8(a)(1)-(2), 15 U.S.C. § 2607(a)(1)-(2) (2012). 

[565] TSCA § 8(d), 15 U.S.C. § 2607(d) (2012). 

[566] TSCA §§ 16(a)(1), 15, 15 U.S.C. §§ 2615(a)(1), 2614 (2012). 

[567] TSCA § 5(a)(1), 15 U.S.C. § 2604(a)(1) (2012). See also 40 
C.F.R. pt. 720 (2012). 

[568] TSCA § 15(2), 15 U.S.C. § 2614(2) (2012). 

[569] References to state laws are included where no state regulation, 
or no detailed state regulation, exists; where the law was cross-
referenced by a state regulation; or where interviews with state 
officials drew our attention to requirements in state law. These 
tables do not include state policy or practice; in some cases, states 
may address topic areas covered in these tables through processes that 
are not formally noted or comprehensively described in their 
regulations, such as the permitting process. The absence of a 
requirement in a particular state does not reflect any judgment on our 
part that a state should have such a requirement. 

[570] In summarizing state rules, references to specific state 
officials and forms have been omitted except where those details are 
crucial for understanding the provision. In many cases, the 
requirements presented are default requirements that may be varied 
with state approval. Not all such options are noted in these tables. 
Unless otherwise noted, requirements are those that apply to new 
operations. 

[571] State regulations on oil and gas development contain a variety 
of technical terms that are often not defined in the regulations 
themselves or may be differently defined across states. We have 
attempted to provide standard definitions for such terms for ease of 
reading; unless otherwise noted, however, such definitions are 
dictionary or industry glossary definitions rather than regulatory 
definitions. 

[End of section] 

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