UNCONVENTIONAL 

OIL AND GAS 

DEVELOPMENT

Key Environmental 

and Public Health 

Requirements

Report to Congressional Requesters

September 2012

GAO-12-874

United States Government Accountability Office

GAO
United States Government Accountability Office

Highlights of GAO-12-874, a report to 

congressional requesters 

September 2012

UNCONVENTIONAL OIL AND GAS 

DEVELOPMENT 

Key Environmental and Public Health Requirements

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.

GAO is not making recommendations. 

In commenting on the report, agencies 

provided information on recent 

regulatory activities and technical 

comments.

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.

View GAO-12-874. For more information, 

contact David C. Trimble at (202) 512-3841 or 

trimbled@gao.gov. 
Page i GAO-12-874 Unconventional Oil and Gas Development 

Letter 1 

Background 5

Federal Environmental and Public Health Laws Apply to 

Unconventional Oil and Gas Development but with Key 

Exemptions 17

States in Our Review Implement Additional Requirements and 

Recently Updated Some Requirements 47

Additional Requirements Apply on Federal Lands 68

Federal and State Agencies Reported Several Challenges 

Regulating Unconventional Oil and Gas Development 77

Agency Comments and Our Evaluation 81

Appendix I Objectives, Scope, and Methodology 84 

Appendix II Key Requirements and Authorities under the Safe Drinking Water Act 88

Underground Injection Control Program 88

Imminent and Substantial Endangerment Authorities 97 

Appendix III Key Requirements and Authorities under the Clean Water Act 99

National Pollutant Discharge Elimination System Program 100

Oil and Hazardous Substances Spill Prevention, Reporting, and 

Response 117 

Appendix IV Key Requirements and Authorities under the Clean Air Act 126

National Emission Standards for Hazardous Air Pollutants 129

New Source Performance Standards 137

New Source Review 142

Title V Operating Permits 143

Source Determinations and Aggregation Issues for Title V and NSR 145

Greenhouse Gas Reporting Rule 147

Accidental Releases 149

EPA Enforcement Authorities 155

Imminent and Substantial Endangerment Authority 155 

Contents 
Page ii GAO-12-874 Unconventional Oil and Gas Development

Appendix V Key Requirements and Authorities under the Resource Conservation 

and Recovery Act 156

Subtitle C – Hazardous Waste 156

Subtitle D – Solid Waste 165

Enforcement 166

Imminent and Substantial Endangerment Authority 168

Appendix VI Key Requirements and Authorities under the Comprehensive 

Environmental Response, Compensation, and Liability Act 171

Appendix VII Key Requirements and Authorities under the Emergency Planning 

and Community Right-to-Know Act 179

Appendix VIII Key Requirements and Authorities under the Toxic Substances 

Control Act 188

Appendix IX Selected State Requirements 192

Appendix X Crosswalk between Selected Requirements from EPA, States, and 

Federal Lands 225

Appendix XI Comments from the Department of Agriculture 229

Appendix XII Comments from the Department of the Interior 230

Appendix XIII GAO Contact and Staff Acknowledgments 233
Page iii GAO-12-874 Unconventional Oil and Gas Development

Tables

Table 1: Potential Waste Management and Disposal Optionsa 14

Table 2: Exemptions or Limitations in Regulatory Coverage for the 

Oil and Gas Exploration and Production Industry in Six 

Environmental Laws 44

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

Well Sites 46

Table 4: Key Federal Environmental and Public Health Requirements 

and State Requirements for Oil and Gas Production Wells 48

Table 5: Chemical Disclosure Requirements in Six Selected States 54

Table 6: Surface Agency Roles in Leasing and Permitting Federal 

Minerals 70

Table 7: Agencies and Organizations Contacted 85

Table 8: Summary of Effluent Limitations Guidelines for 

Wastewater Discharges from Selected Subcategories of Oil 

and Gas Wells Located on Land 103

Table 9: Summary of CAA Programs That May Apply to Emissions 

from Oil and Gas Well Sites 128

Table 10: NSPS for Natural Gas Wells, by Well Subcategory 139

Table 11: Primary State Agencies Responsible for Regulating Oil 

and Gas Development in Six States 192

Table 12: Selected State Requirements—Siting and Site Preparation 193

Table 13: Selected State Requirements—Drilling, Casing, and 

Cementing 196

Table 14: Selected State Requirements—Hydraulic Fracturing 202

Table 15: Selected State Requirements—Well Plugging 208

Table 16: Selected State Requirements—Site Reclamation 209

Table 17: Selected State Requirements—Waste Management in Pits 211

Table 18: Selected State Requirements—Waste Management 

through Underground Injection 216

Table 19: Selected State Requirements—Managing Air Emissions 222

Table 20: Crosswalk between Selected Requirements from EPA, 

Six States, and Federal Minerals 225

Figures

Figure 1: Conventional and Unconventional Oil and Gas Reservoirs 6

Figure 2: Locations of Unconventional Reservoirs in the United 

States 7

Figure 3: Well Pad and Freshwater Storage Tanks 9
Page iv GAO-12-874 Unconventional Oil and Gas Development

Figure 4: Horizontal Drilling and Hydraulic Fracturing in an 

Unconventional Shale Formation 11

Figure 5: Hydraulic Fracturing in a Coalbed Methane Formation 12

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

and Gas Development 16

Figure 7: Enhanced Recovery and Disposal Wells 19
Page v GAO-12-874 Unconventional Oil and Gas Development

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

This is a work of the U.S. government and is not subject to copyright protection in the 

United States. The published product may be reproduced and distributed in its entirety 

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Page 1 GAO-12-874 Unconventional Oil and Gas Development

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,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,2 oil production from shale formations (shale oil)3

 

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.

has 

increased significantly in several areas of the country, including the 

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, GAO-11-35 (Washington, D.C.: 

Oct. 29, 2010). 

 
 

Page 2 GAO-12-874 Unconventional Oil and Gas Development

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.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.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.6

 

4

Department of Energy, Secretary of Energy Advisory Board, Shale Gas Production 

Subcommittee 90-Day Report (Washington, D.C.: 2011)

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 

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.
 

Page 3 GAO-12-874 Unconventional Oil and Gas Development

manage federal lands and have responsibilities for oil and gas 

development.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 

 

7

BLM also manages oil and gas development on American Indian lands, but American 

Indian lands are outside the scope of this review.
 

Page 4 GAO-12-874 Unconventional Oil and Gas Development

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.
 

Page 5 GAO-12-874 Unconventional Oil and Gas Development

Oil and gas reservoirs vary in their geological makeup, location, and size. 

Regardless of the reservoir, unconventional oil and gas development 

involves a number of activities, many of which are also conducted in 

conventional oil and gas drilling. This section describes the types and 

locations of oil and gas reservoirs and the key stages of oil and gas 

development.

Oil and natural gas are found in a variety of geologic formations. In 

conventional reservoirs, oil and gas can flow relatively easily through a 

series of pores in the rock to the well. Shale and tight sandstone 

formations generally have low permeability and therefore do not allow oil 

and gas to easily flow to the well. Shale and tight sandstone formations 

can occur at varying depths, including thousands of feet beneath the 

surface. For example, the Bakken shale formation in North Dakota and 

Montana ranges from 4,500 to 11,000 feet beneath the surface. Coalbed 

methane formations, often located at shallow depths of several hundred 

to 3,000 feet, are generally formations through which gas can flow more 

freely; however, capturing the gas requires operators to pump water out 

of the coal formation to reduce the pressure and allow the gas to flow. 

Shale, tight sandstone, and coalbed methane formations are located 

within basins, which are large-scale geological depressions, often 

hundreds of miles across, which also may contain other oil and gas 

resources. There is no clear and consistently agreed upon distinction 

between conventional and unconventional oil and gas, but unconventional 

sources generally require more complex and expensive technologies for 

production, such as the combination of horizontal drilling and multiple 

hydraulic fractures. See figure 1 for a depiction of conventional and 

unconventional reservoirs.

Background

Types and Locations of Oil 

and Gas Reservoirs
 

Page 6 GAO-12-874 Unconventional Oil and Gas Development

Figure 1: Conventional and Unconventional Oil and Gas Reservoirs

Unconventional reservoirs are located throughout the continental United 

States on both private lands and federal lands that are administered by 

BLM, Forest Service, Park Service, and FWS (see fig. 2).8

 

8

Unconventional reservoirs may also be located on tribal lands, but these were outside the 

scope of our review.
 

Page 7 GAO-12-874 Unconventional Oil and Gas Development

Figure 2: Locations of Unconventional Reservoirs in the United States

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. 
 

Page 8 GAO-12-874 Unconventional Oil and Gas Development

Developing unconventional reservoirs involves a variety of activities, 

many of which are also conducted in conventional oil and gas drilling.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 fig. 3). In 

some cases, multiple wells will be located on a single well pad.

 

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.

Activities Associated With 

Oil and Gas Development
 

Page 9 GAO-12-874 Unconventional Oil and Gas Development

Figure 3: Well Pad and Freshwater Storage Tanks

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 
 

Page 10 GAO-12-874 Unconventional Oil and Gas Development

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.

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.

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),12

 

10In 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.

after which production can begin, and the well 

is said to have been completed. Operators use hydraulic fracturing in 

many shale and tight sandstone formations (see fig. 4). Some coalbed 

methane wells are hydraulically fractured (see fig. 5), but operators may 

use different combinations of water, sand, and chemicals than with other 

unconventional wells. In addition, operators must “dewater” coalbed 

methane formations in order to get the natural gas to begin flowing—a 

process that can generate large amounts of water.

11The 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.

12Not all the fluids injected into the well during hydraulic fracturing necessarily flow back to 

the surface. 
 

Page 11 GAO-12-874 Unconventional Oil and Gas Development

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

Formation

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. 
 

Page 12 GAO-12-874 Unconventional Oil and Gas Development

Figure 5: Hydraulic Fracturing in a Coalbed Methane Formation

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. 
 

Page 13 GAO-12-874 Unconventional Oil and Gas Development

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.13

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.

Sometimes, 

when a well starts production, operators reclaim the portions of a site 

affected by the initial drilling activity.

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.

 

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

14We recently issued a report on the quantity, quality, and management of water produced 

during oil and gas production. See GAO, Energy-Water Nexus: Information on the 

Quantity, Quality, and Management of Water Produced during Oil and Gas Production, 

GAO-12-156 (Washington, D.C.: Jan. 9, 2012).
 

Page 14 GAO-12-874 Unconventional Oil and Gas Development

Table 1: Potential Waste Management and Disposal Optionsa

Liquid wasteb Solid waste Hazardous waste

Primary types of 

waste

• Produced water

• Drilling mud

• Drill cuttings

• Trash 

• Unused hydraulic fracturing 

chemicals being discarded

• Certain other chemical and 

oily wastes

Options for temporary 

storage

• Tanks or pits • Tanks or pits • Tanks

Options for reuse • Recycle for use in future 

hydraulic fracturing

• Irrigation

• Roadspreading (used for dust or 

ice suppression)

• Reuse of drilling mud

• Roadspreading of drill 

cuttings

N/A

Options for 

permanent disposal

• Underground injection well

• Discharge to surface water

• Commercial treatment facilities

• Publicly-owned treatment works 

• Solid waste landfill

• Bury drill cuttings on or near 

well pad

• 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. 

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.

15

 

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

development.

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 
 

Page 15 GAO-12-874 Unconventional Oil and Gas Development

respiratory causes.16

• 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.

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).

• 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 fig. 6). Stationary sources include wells, 

pumps, storage vessels, pneumatic controllers, dehydrators, pits, and 

flaring.17

 

16Volatile 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.

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.

17Flaring 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, 

GAO-11-34 (Washington, D.C.: Oct. 29, 2010).
 

Page 16 GAO-12-874 Unconventional Oil and Gas Development

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

Page 17 GAO-12-874 Unconventional Oil and Gas Development

Requirements from eight federal laws apply to the development of oil and 

gas from unconventional sources. In large part, the same requirements 

apply to conventional and unconventional oil and gas development. There 

are exemptions or limitations in regulatory coverage for preventive 

programs authorized by six of these laws, though EPA generally retains 

its authorities under federal environmental and public health laws to 

respond to environmental contamination. States may have regulatory 

programs related to some of these exemptions or limitations in federal 

regulatory coverage; state requirements are discussed later in this report.

Parts of the following eight federal environmental and public health laws 

apply to unconventional oil and gas development:

• Safe Drinking Water Act (SDWA)

• Clean Water Act (CWA)

• Clean Air Act (CAA) 

• Resource Conservation and Recovery Act (RCRA)

• Comprehensive Environmental Response, Compensation, and 

Liability Act (CERCLA)

• Emergency Planning and Community Right-to-Know Act (EPCRA)

• Toxic Substances Control Act (TSCA)

• Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA)

There are exemptions or limitations in regulatory coverage related to the 

first six laws listed above. In large part, the same requirements apply to 

conventional and unconventional oil and gas development. This section 

discusses each of these laws in brief;18

 

18The National Environmental Policy Act may also apply and is discussed later in this 

report.

for more details about seven of 

these laws, please see appendixes II through VIII.

Federal 

Environmental and 

Public Health Laws 

Apply to 

Unconventional Oil 

and Gas Development 

but with Key 

Exemptions

Eight Federal 

Environmental and Public 

Health Laws Apply to 

Unconventional Oil and 

Gas Development
 

Page 18 GAO-12-874 Unconventional Oil and Gas Development

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

UIC Program

Two key aspects of SDWA that are part of the regulatory framework 

governing unconventional oil and gas development are the Underground 

Injection Control (UIC) program and the imminent and substantial 

endangerment provision.

Under SDWA, EPA regulates the injection of fluids underground through 

its UIC program, including the injection of produced water from oil and 

gas development. The UIC program protects underground sources of 

drinking water by setting and enforcing standards for siting, constructing, 

and operating injection wells. Injection wells in the UIC program fall into 

six different categories based on the types of fluids being injected. The 

wells used to manage fluids associated with oil and gas production, 

including produced water, are Class II wells.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 fig. 7), as 

follows:

• Enhanced recovery wells inject produced water or other fluids or 

gases into oil- or gas-producing formations to increase the pressure in 

the formation and force additional oil or gas out of nearby producing 

wells. EPA documents estimate that about 80 percent of Class II wells 

are enhanced recovery wells.

• Disposal wells inject produced water or other fluids associated with oil 

and gas production into formations that are intended to hold the fluids 

permanently. EPA documents estimate that about 20 percent of Class 

II wells are disposal wells.21

 

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

20Other 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.

21A 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.

Safe Drinking Water Act
 

Page 19 GAO-12-874 Unconventional Oil and Gas Development

Figure 7: Enhanced Recovery and Disposal Wells
 

Page 20 GAO-12-874 Unconventional Oil and Gas Development

UIC regulations include minimum federal requirements for most Class II 

UIC wells; these requirements are generally applicable only where EPA 

implements the program.22 For example, for most new Class II UIC wells, 

an operator23

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.

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.

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 

 

22See discussion below. According to EPA, some states’ UIC requirements for Class II 

wells are very similar or identical to EPA requirements.

23For simplicity, throughout this report we refer to requirements on well operators. In some 

cases requirements may also apply to well owners.
 

Page 21 GAO-12-874 Unconventional Oil and Gas Development

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.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.25 EPA 

officials told us that they do not have data about how frequently 

companies currently use diesel in hydraulic fracturing.26 According to EPA 

officials, EPA recently identified wells for which publicly available data 

suggest diesel was used in hydraulic fracturing.27

 

24The 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).

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 

25UIC regulations at the time and now provide that ‘‘[a]ny underground injection, except 

into a well authorized by rule or except as authorized by permit issued under the UIC 

program, is prohibited.’’ 40 C.F.R. 144.11 (2005) (2011). The Energy Policy Act provision 

did not exempt injections of diesel fuel during hydraulic fracturing from the definition of 

underground injection. EPA’s position is that underground injection of diesel fuel as part of 

hydraulic fracturing requires a UIC permit or authorization by rule.

26In 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.

27According 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.
 

Page 22 GAO-12-874 Unconventional Oil and Gas Development

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.
 

Page 23 GAO-12-874 Unconventional Oil and Gas Development

For more details about SDWA, please see appendix II.

To restore and maintain the nation’s waters, CWA authorizes EPA to, 

among other things, regulate pollutant discharges and respond to spills 

affecting rivers and streams.

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).29 Second, spill 

reporting and spill prevention and response planning requirements pertain 

to certain threats to U.S. navigable waters and adjoining shorelines.

30

NPDES

In 

addition, under certain circumstances, EPA has response authorities; for 

example, it can generally bring suit or take other actions to protect the 

public health and welfare from actual or threatened discharges of oil or 

hazardous substances to U.S. navigable waters and adjoining shorelines. 

EPA’s NPDES program limits the types and amounts of pollutants that 

industrial sites, industrial wastewater treatment facilities, and municipal 

wastewater treatment facilities (often called publicly-owned treatment works 

or POTWs) can discharge into the nation’s surface waters by requiring 

these facilities to have and comply with permits listing pollutants and their

discharge limits. As required by CWA, EPA develops effluent limitations for 

certain industrial categories based on available control technologies and 

other factors to prevent or treat the discharge. EPA established multiple 

 

28The 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).

29For 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.

30The 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.

Clean Water Act
 

Page 24 GAO-12-874 Unconventional Oil and Gas Development

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.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 west32

 

31EPA 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.

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 

32Specifically, 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.
 

Page 25 GAO-12-874 Unconventional Oil and Gas Development

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 
 

Page 26 GAO-12-874 Unconventional Oil and Gas Development

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 2014.33

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.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.35

Spill Reporting and Spill Prevention and Response Planning

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.

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 

 

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

34The 1987 Water Quality Act also exempted oil and gas processing, treatment, and 

transmission facilities from permit requirements for stormwater discharges. 

35EPA 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). 
 

Page 27 GAO-12-874 Unconventional Oil and Gas Development

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.

36

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 

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.

 

36In 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.
 

Page 28 GAO-12-874 Unconventional Oil and Gas Development

SPCC-regulated facilities.37

Imminent and Substantial Endangerment and Release Response 

Authorities 

To ensure that regulated facilities are meeting 

SPCC requirements, EPA Regional personnel may inspect these facilities 

to evaluate their compliance. EPA officials said that some of these 

inspections were conducted as follow-up after spills were reported and 

that most inspections are conducted during the production phase, since 

drilling and hydraulic fracturing are of much shorter durations, making it 

difficult for inspectors to visit these sites during those times. According to 

EPA officials, Regional personnel inspected 120 oil and gas well sites 

nationwide in fiscal year 2011 and found noncompliance at 105 of these 

sites. These violations ranged from paperwork inconsistencies to more 

serious violations, such as a lack of secondary containment around 

stored oil or failure to implement an SPCC plan (though EPA officials 

were unable to specifically quantify the number of more serious 

violations). EPA officials said that EPA has addressed some of the 105 

violations through enforcement actions.

CWA also provides EPA with authorities to address the discharge of 

pollutants and to address actual or threatened discharges of oil or 

hazardous substances in certain circumstances. For example, under one 

provision, EPA has the authority to address actual or threatened 

discharges of oil or hazardous substances into U.S. navigable waters or 

on adjoining shorelines upon a determination that there may be an 

imminent and substantial threat to the public health or welfare of the 

United States, by bringing suit or taking other action, including issuing 

administrative orders that may be necessary to protect public health and 

welfare. Under another provision, EPA has authority to obtain records and 

access to facilities, among other things, in order to determine if a person 

is violating certain CWA requirements. For example, EPA conducted 

initial investigations in Bradford County, Pennsylvania, following a 2011 

spill of hydraulic fracturing and other fluids that entered a stream. Citing 

 

37See GAO, Aboveground Oil Storage Tanks: More Complete Facility Data Could Improve 

Implementation of EPA’s Spill Prevention Program, 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.
 

Page 29 GAO-12-874 Unconventional Oil and Gas Development

its authority under CWA and other laws,38

For more details about CWA, please see appendix III.

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.

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.39

Mobile Sources–Criteria Air Pollutants

Under CAA, EPA sets national ambient air quality standards for the 

six criteria pollutants––ground level ozone, carbon monoxide, particulate 

matter, sulfur dioxide, nitrogen oxides, and lead––at levels it determines 

are necessary to protect public health and welfare. States then develop 

state implementation plans (SIP) to establish how the state will attain air 

quality standards, through regulation, permits, policies, and other means. 

States must obtain EPA approval for SIPs; if a SIP is not acceptable, EPA 

may assume responsibility for implementing and enforcing CAA in that 

state. CAA also authorizes EPA to regulate emissions of hazardous air 

pollutants, such as benzene. In addition, under CAA, EPA requires 

reporting of greenhouse gas emissions from a variety of sources, 

including oil and gas wells.

In accordance with CAA, EPA has progressively implemented more 

stringent diesel emissions standards to lower the amount of key pollutants 

from mobile diesel-powered engines since 1984.40

 

38Specifically, EPA cited authorities under CWA section 308, as well as under CERCLA 

and RCRA. 

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 

39Clean 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). 

40See GAO, Diesel Pollution: Fragmented Federal Programs That Reduce Mobile Source 

Emissions Could Be Improved, GAO-12-261 (Washington, D.C.: Feb. 7, 2012). 

Clean Air Act
 

Page 30 GAO-12-874 Unconventional Oil and Gas Development

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.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 sites42

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.

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.

43

 

41For example, precursors to ground level ozone are nitrogen oxides and volatile organic 

compounds.

Specifically, these new 

42EPA 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.

43EPA’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.
 

Page 31 GAO-12-874 Unconventional Oil and Gas Development

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.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 

 

44This 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. 
 

Page 32 GAO-12-874 Unconventional Oil and Gas Development

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 
 

Page 33 GAO-12-874 Unconventional Oil and Gas Development

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.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.46

 

45In 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.

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.

46EPA Region 6 includes the states of Arkansas, Louisiana, New Mexico, Oklahoma, and 

Texas.
 

Page 34 GAO-12-874 Unconventional Oil and Gas Development

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.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 2010.48

 

47In 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).

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 

48The 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).
 

Page 35 GAO-12-874 Unconventional Oil and Gas Development

production facilities with flammable storage tanks advising them of their 

CAA general duty clause responsibilities, and encouraging specific 

measures to reduce these risks.49

Stationary Sources–Greenhouse Gas Reporting

The Chemical Safety Board requested 

that EPA provide a response stating how EPA will address the 

recommendation. EPA responded in June 2012, stating its intent to 

comply with the recommendation.

As of 2012, oil and natural gas production facilities are required to report 

their greenhouse gas emissions to EPA on an annual basis as described 

in EPA’s greenhouse gas reporting rule. According to EPA documents, oil 

and gas well sites may emit greenhouse gases, including methane and 

carbon dioxide, from sources including: (1) combustion sources, such as 

engines used on site, which typically burn natural gas or diesel fuel, and 

(2) indirect sources, such as equipment leaks and venting.50

For more details about CAA, please see appendix IV.

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.

RCRA, passed in 1976, established EPA’s authority to regulate the 

generation, transportation, treatment, storage, and disposal of hazardous 

wastes.51

 

49The Chemical Safety Board also noted that exploration and production storage tanks are 

exempt from the security requirements of CWA’s spill prevention program.

Subsequently, the Solid Waste Disposal Act Amendments of 

1980 created a separate process by which oil and gas exploration and 

50Other major greenhouse gases covered by EPA’s greenhouse gas reporting rule include 

hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.

51Pub. 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.

Resource Conservation and 

Recovery Act 
 

Page 36 GAO-12-874 Unconventional Oil and Gas Development

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.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.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.54 Facilities generating smaller 

quantities of hazardous waste are not subject to these requirements.55

 

52Specifically, 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.

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, 

53Field operations include, for example, water separation, demulsifying, degassing, and 

storage at well sites.

54Small 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. 

55These 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.
 

Page 37 GAO-12-874 Unconventional Oil and Gas Development

we asked state officials responsible for waste programs whether they 

were aware of well sites being classified as small-quantity hazardous 

waste generators, and officials in all six states we reviewed indicated that 

they were unaware of well sites having sufficient quantities of hazardous 

wastes to be subject to those regulations.

In September 2010, the Natural Resources Defense Council submitted a 

petition to EPA requesting that the agency regulate waste associated with 

oil and gas exploration and production as hazardous. The petition asserts 

that EPA should revisit the 1988 determination not to regulate these 

wastes as hazardous because, among other things, EPA’s underlying 

assumptions concerning the availability of alternative disposal practices, 

the adequacy of state regulations, and the potential for economic harm to 

the oil industry are no longer valid. According to EPA officials, the agency 

is currently reviewing the information provided in the petition but does not 

have a time frame for responding.

RCRA also authorizes EPA to issue administrative orders, among other 

things, in cases where handling, treatment, or storage of hazardous or 

solid waste may present an imminent and substantial endangerment to 

health or the environment. EPA has used RCRA’s imminent and 

substantial endangerment authorities related to oil and gas well sites. For 

example, EPA Region 8 issued RCRA imminent and substantial 

endangerment orders to operators in Wyoming after discovering that pits 

near oil production sites were covered with oil and posed a hazard to 

birds.

For more details about RCRA, please see appendix V.

Congress passed CERCLA in 1980 to protect public health and the 

environment by addressing the cleanup of hazardous substance 

releases.56

 

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

9675 (2012).

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 

Comprehensive Environmental 

Response, Compensation, and 

Liability Act 
 

Page 38 GAO-12-874 Unconventional Oil and Gas Development

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 
 

Page 39 GAO-12-874 Unconventional Oil and Gas Development

the agency used this authority to issue an administrative order at a 

well site, but EPA used the response authority to conduct sampling 

and to provide temporary drinking water to residents with 

contaminated wells in Dimock, Pennsylvania.

For more details about CERCLA, please see appendix VI.

Among other things, EPCRA provides individuals and their communities 

with access to information regarding storage or release of certain 

chemicals in their communities.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.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.59

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 

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.

 

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

(2012).

58Three 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).

59Specifically, 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. 

Emergency Planning and 

Community Right-to-Know Act
 

Page 40 GAO-12-874 Unconventional Oil and Gas Development

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.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.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.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.63

 

60In 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.

EPA officials said that 

adding oil and gas well sites would likely provide an incomplete picture of 

61The 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. 

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

63Officials 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.
 

Page 41 GAO-12-874 Unconventional Oil and Gas Development

the chemical uses and releases at these sites and would, therefore, be of 

limited utility in providing information to communities.

For more details about EPCRA, please see appendix VII.

TSCA authorizes EPA to regulate the manufacture, processing, use, 

distribution in commerce, and disposal of chemical substances and 

mixtures.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.65

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 

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.

 

64Pub. 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.

65These 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.

Toxic Substances Control Act
 

Page 42 GAO-12-874 Unconventional Oil and Gas Development

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.66

For more details about TSCA, please see appendix VIII.

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.

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 

 

66Earthjustice 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.

Federal Insecticide, Fungicide, 

and Rodenticide Act
 

Page 43 GAO-12-874 Unconventional Oil and Gas Development

environment.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,

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 2007.69

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 

 

67The 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).

68Ground 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.

69Glutaraldehyde is also used as a disinfectant for medical and dental equipment, in water 

treatment systems, and as a preservative.

Exemptions Are Related to 

Preventive Programs
 

Page 44 GAO-12-874 Unconventional Oil and Gas Development

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 Description of exemption or limitation in regulatory coverage Source

Type of program related to 

exemption or limitation in 

regulatory coverage

Preventive Response

SDWA Hydraulic fracturing with fluids other than diesel fuel does not require a 

UIC permit.

Statutory (2005) X 

CWA Federal stormwater permits are not required for uncontaminated 

stormwater at oil and gas construction sites or at oil and gas well sites.

Statutory (1987, 

2005) X 

CAA 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.

Statutory (1990)

X 

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.

Regulatory/EPA 

decision (1988) X 

RCRA Oil and gas exploration and production wastes are not regulated as 

hazardous waste.

Regulatory/EPA 

decision (1988) X 

CERCLA Liability and reporting provisions do not apply to injections of fluids 

authorized by state law for production, enhanced recovery, or 

produced water.

Statutory (1980)

X 

EPCRA Oil and gas well operations are not required to report releases of listed 

chemicals to the TRI.

Regulatory/EPA 

decision (1997) X 

Source: GAO.

Note: In some cases, states may have requirements in these areas. State requirements are 

discussed in the next section of this report. 

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.
 

Page 45 GAO-12-874 Unconventional Oil and Gas Development

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.70

 

70See EPA, Memorandum, Use of CERCLA § 106 To Address Endangerments that May 

Also Be Addressed Under Other Environmental Statutes, App. A (2001). 

See appendixes II through VI for a more detailed discussion of 

these authorities.
 

Page 46 GAO-12-874 Unconventional Oil and Gas Development

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

Law Key response authorities Situation to which authority may apply

Imminent and substantial endangerment and general response authorities 

SDWA Imminent and substantial endangerment (§ 1431) Contaminant present in or likely to enter a public water system or 

an underground source of drinking water

CWA Imminent and substantial endangerment (§ 504) Source(s) of pollution, including discharge of pollutant to surface 

waters

Response authority; imminent and substantial threat 

(§ 311)

Actual or threatened discharge of oil or hazardous substances into 

U.S navigable waters or on adjoining shorelines

CAAb Imminent and substantial endangerment 

(§ 112(r)(9))

Accidental release to the air of regulated substance

RCRA Imminent and substantial endangerment (§ 7003) Past or present handling, storage, treatment, transportation, or 

disposal of any solid waste or hazardous waste

CERCLA Response authority (§ 104(a)) Actual or threatened release of any hazardous substance 

Imminent and substantial endangerment (§ 104(a)) Actual or threatened release of any hazardous substance or 

pollutant or contaminant (other than petroleum)

Imminent and substantial endangerment (§ 106(a)) Actual or threatened release of a hazardous substance from a facilityc

Access, information, and inspection authorities 

SDWA Access to records and to inspect facilities (§ 

1445(b)) 

Persons and facilities subject to UIC program requirements

CWA Access to records and to inspect facilities; require 

reports (§ 308(a))

Location of effluent source

Access to records and to inspect facilities; ability to 

require provision of information (§ 311(m)(2))

Persons and facilities subject to section 311, such as SPCC 

program requirements

CAA Access to records; ability to require provision of 

information (§ 114(a))

Person who owns or operates any emission source, among others

RCRA Access to records and to inspect facilities (§ 3007) Persons that have generated, stored, treated, transported, disposed 

of, or otherwise handled hazardous wastesd

CERCLA Access to records and to inspect facilities; ability to 

require provision of information (§ 104(e))

Location of actual or threatened release, generation, storage, 

treatment, or disposal of any hazardous substance or pollutant or 

contaminant (other than petroleum)

TSCA Access to inspect facilities and onsite records (§ 11) 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. 
 

Page 47 GAO-12-874 Unconventional Oil and Gas Development

The six states in our review implement additional requirements governing 

a number of activities associated with oil and gas development. One of 

the states—Pennsylvania—is also part of the Delaware River Basin 

Commission—a regional commission that implements additional 

requirements. All six states have updated some aspects of their 

requirements in recent years.

In addition to implementing and enforcing certain aspects of federal 

requirements with EPA approval and oversight, the six states in our 

review implement additional requirements governing a number of 

activities associated with oil and gas development. State requirements 

often do not explicitly differentiate between conventional and 

unconventional development but, in recent years, states have begun to 

promulgate some requirements that apply specifically to unconventional 

development. States have regulatory requirements related to a variety of 

activities involved in developing unconventional reservoirs, including 

siting and site preparation; drilling, casing, and cementing; hydraulic 

fracturing; well plugging; site reclamation; waste management and 

disposal; and managing air emissions. Table 4 compares selected state 

requirements and related federal environmental and public health 

requirements; a more comprehensive table is available in appendix X. 

Several studies noted that development practices and state requirements 

may vary based on a number of factors, including geology, climate, and 

the type of resource being developed.71 We did not assess whether all 

requirements are appropriate for all states as part of this review.

 

71Charles 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. 

States in Our Review 

Implement Additional 

Requirements and 

Recently Updated 

Some Requirements

States in Our Review 

Implement Additional 

Requirements and Certain 

Federal Requirements
 

Page 48 GAO-12-874 Unconventional Oil and Gas Development

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

Area of regulation

EPA environmental and public health 

requirements Requirements of six states reviewed

Siting and site preparation

Identification or testing of water wells prior 

to drilling of production wells

No 1 of 6 (Wyoming) [identification alone]

2 of 6 (Colorado, Ohio) [identification and 

testing]a

Required setbacks from water sources No 5 of 6 (Colorado, North Dakota, 

Pennsylvania, Ohio, Wyoming)

Stormwater permitting Effectively nob 4 of 6 (Colorado, North Dakota, 

Pennsylvania, Wyoming)

Drilling, casing, and cementing

Requirements relating to cementing/casing 

plans

Noc 6 of 6

Prescribed placement of surface casing 

relative to groundwater zones

Noc 6 of 6

Hydraulic fracturing

Requirements to disclose information on 

fracturing fluids

Nod 6 of 6

Well plugging

Requirements for notification, plugging plan 

or method, witnessing, and reporting

No 6 of 6

Programs to plug wells that are not properly 

plugged and have been abandoned

No 6 of 6

Site reclamation

Requirements for backfilling, regrading, 

recontouring, and alleviating compaction of 

soil

No 6 of 6

Revegetation requirements No 5 of 6 (Colorado, North Dakota, Ohio, 

Pennsylvania, Wyoming)

Waste management

Pit lining requirements No 5 of 6 (Colorado, North Dakota, 

Pennsylvania, Texas, Wyoming)

Options for waste disposal:

Underground injection Yes (SDWA) 5 states have their own requirements 

(Colorado, North Dakota, Ohio, Texas, 

Wyoming); EPA implements the program in 

Pennsylvania

Direct discharge to surface water Yes (CWA – certain discharges prohibited, 

others subject to conditions and permit)

Surface discharges are allowed in certain 

cases in 3 western states (Colorado, 

Texas, and Wyoming)
 

Page 49 GAO-12-874 Unconventional Oil and Gas Development

Area of regulation

EPA environmental and public health 

requirements Requirements of six states reviewed

Requirements for discharge to POTWs 

or Centralized Waste Treatment (CWT) 

facilities

Pretreatment standards for shale gas 

wastewater under development (CWA)

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)

Recycling or other reuse Yes (CWA – certain produced water 

discharges)

6 of 6 states allow recycling or other reuse

Solid waste disposal Effectively nof Yes

Hazardous waste disposal Effectively nog No

Managing air emissions

Requirements for criteria pollutants Certain CAA provisions apply 5 of 6 states have permitting or registration 

programs (Colorado, North Dakota, Ohio, 

Texas, Wyoming)

Requirements for hazardous air pollutants Certain CAA provisions apply State permitting or registration programs 

may address hazardous air pollutants

Requirements related to hydrogen sulfide 

gas 

No specific requirements but CAA general 

duty clause requires prevention of 

accidental releases

6 of 6 

Requirements related to flaring Under new NSPS regulation, most 

hydraulically fractured gas wells must do 

green completions 

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. 
 

Page 50 GAO-12-874 Unconventional Oil and Gas Development

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. 

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.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.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.74

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 

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.

 

72An 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.

73In 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.

74Pennsylvania 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.

Siting and Site Preparation
 

Page 51 GAO-12-874 Unconventional Oil and Gas Development

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.75

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.

In Pennsylvania, there are also setbacks from public water 

supplies and certain other bodies of water such as springs and wetlands.

States have additional requirements relating to erosion control, site 

preparation, and surface disturbance minimization. For more details about 

state siting and site preparation requirements, see appendix IX.

All of the six states in our review have requirements related to how wells 

are to be drilled and casing should be installed and cemented in place, 

 

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

Drilling, Casing, and Cementing
 

Page 52 GAO-12-874 Unconventional Oil and Gas Development

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.76

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 

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.

 

76According to state regulators, this maximum surface casing depth requirement prevents 

fresh and brackish groundwater from commingling behind the same casing, among other 

things.
 

Page 53 GAO-12-874 Unconventional Oil and Gas Development

horizontal drilling paths. For example, an application for a permit to drill a 

horizontal well in Wyoming must include information about the vertical 

and horizontal paths of the well, and operators must provide notice to 

owners within a half-mile of any point on the entire length of the well. In 

addition, operators must (1) provide notification and obtain approval from 

the Wyoming Oil and Gas Conservation Commission before beginning 

horizontal drilling and (2) file a description of the exact path of the well, 

known as a directional survey, within 30 days of well completion. North 

Dakota requires a different permit to drill a horizontal well than it does for 

a vertical well, and the horizontal permit contains information about the 

horizontal path of the well.

For more details about state drilling, casing, and cementing requirements, 

see appendix IX.

All six states we reviewed have requirements for disclosing the chemicals 

used in hydraulic fracturing, but the specific requirements vary (see table 

5). Four states—Colorado, North Dakota, Pennsylvania, and Texas—

require disclosure through the website FracFocus, which is a joint project 

of the Ground Water Protection Council and the Interstate Oil and Gas 

Compact Commission.77

 

77FracFocus 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.

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 

Hydraulic Fracturing
 

Page 54 GAO-12-874 Unconventional Oil and Gas Development

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 Colorado North Dakota Ohio Pennsylvania Texas Wyoming

Reporting 

mechanism

FracFocus 

website

FracFocus 

website

State website, 

FracFocus 

website, or other 

state approved 

method

FracFocus 

website

FracFocus 

website; state 

website if 

FracFocus is 

unavailable

State agency

Timing of 

disclosure

requirement

Information must 

be disclosed 

within 60 days 

following 

completion of 

hydraulic 

fracturing and not 

later than 120 

days after the 

commencement 

of hydraulic 

fracturing.

No timing 

requirement 

specified.

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.

Information must 

be disclosed 

within 60 days 

following the 

conclusion of 

hydraulic 

fracturing.

Information must 

be disclosed 

within 30 days 

after completion 

of the well or 

within 90 days 

after drilling is 

completed, 

whichever is 

earlier.

Information must 

be disclosed 

before hydraulic 

fracturing and 

within 30 days of 

completion 

Protections for 

confidential 

information or 

trade secrets

Yes None identifieda Yes Yes Yes Yes

Provisions to 

challenge trade 

secrets 

None identifieda None identifieda Yes None identifieda Yes Yes

Provisions for 

disclosure to 

health 

professionals

Yes None identifieda Yes Yes Yes None identifieda

Provisions for 

disclosure to 

emergency 

responders

Yes None identifieda Yes Yes Yes None identifieda

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. 

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 
 

Page 55 GAO-12-874 Unconventional Oil and Gas Development

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 
 

Page 56 GAO-12-874 Unconventional Oil and Gas Development

blowout preventers to be used when drilling into an unconventional 

formation.78

For more details about state hydraulic fracturing requirements, see 

appendix IX.

All six states in our review have requirements regarding well plugging, 

such as notifying the state prior to plugging or using specific materials or 

methods to do so. For example, operators in Colorado must obtain prior 

approval from state regulators for the plugging method and provide notice 

of the estimated time and date of plugging. Colorado regulations specify 

that the material used for plugging must be placed in the well in a manner 

that permanently prevents migration of oil, gas, water, or other 

substances out of the formation in which it originated. Cement plugs must 

be a minimum of 50 feet in length and must extend a minimum of 50 feet 

above each zone to be protected. After plugging the well, operators must 

submit reports of plugging and abandonment to the Colorado Oil and Gas 

Conservation Commission and include information specifying the fluid 

used to fill the wellbore, information about the cement used, date of work, 

and depth of plugs. In Pennsylvania, operators must follow (1) specific 

provisions for well plugging based on whether the well is located in a coal 

area or noncoal area or (2) an alternate approved method. Prior to 

plugging a well in an area underlain by a workable coal seam, the oil and 

gas operator must notify the state and the coal company to permit 

representatives to be present at the plugging.

In addition, all six states have programs to plug wells that were improperly 

plugged and have been abandoned, though their level of activity varies. 

For example, state regulators in Texas said that the primary objective of 

their program, which began in 1983, is to plug abandoned oil and gas 

wells that are causing pollution or threatening to cause pollution for which 

a responsible operator does not exist; the responsible operator failed to 

plug the well; or the responsible operator failed to otherwise bring the 

wells into compliance. As of 2009, Texas state regulators had plugged 

30,000 wells, and approximately 8,000 potentially abandoned wells 

remained throughout the state. Officials stated, however, that many of 

 

78Pennsylvania 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).

Well Plugging
 

Page 57 GAO-12-874 Unconventional Oil and Gas Development

these abandoned wells may be re-used for development of previously 

overlooked reservoirs. State regulators in North Dakota said that the 

number of abandoned wells in the state is very low compared with other 

states because the state was fairly late to oil and gas development—with 

major development starting in the 1950s—and that the state had a good 

tracking system in place during the early days of development. State 

regulators in North Dakota used funds from its well plugging program to 

plug two wells in the last year.

For more details about state well plugging requirements, see appendix IX.

All six states in our review have requirements for site reclamation, though 

the extent of the requirements varies. Five states—Colorado, Ohio, North 

Dakota, Pennsylvania, and Wyoming—have requirements both for 

backfilling soil and for revegetating areas. For example, in Colorado, final 

reclamation must generally be complete within 3 months of plugging a 

well on crop land and within 12 months on noncrop land. Reclamation in 

Colorado involves returning segregated soil horizons to their original 

relative positions;79

For more details about state site reclamation requirements, see 

appendix IX.

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.

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 

 

79A soil horizon is a layer roughly parallel to the soil surface whose properties and 

characteristics differ from the layers above and beneath.

Site Reclamation

Waste Management and 

Disposal
 

Page 58 GAO-12-874 Unconventional Oil and Gas Development

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.80

 

80Pennsylvania 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.

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 
 

Page 59 GAO-12-874 Unconventional Oil and Gas Development

their program is effective in preventing endangerment of underground 

sources of drinking water, in lieu of adopting all Class II UIC requirements 

in EPA regulations. All states have requirements for Class II UIC wells 

relating to casing and cementing, operating pressure, mechanical integrity 

testing, well plugging, and the monitoring and reporting of certain 

information, among other requirements. For example, North Dakota 

requires the operators of all new Class II UIC wells to demonstrate the 

mechanical integrity of the well and requires existing Class II UIC wells to 

demonstrate continued mechanical integrity at least once every 5 years. 

In North Dakota, mechanical integrity is demonstrated by showing that 

there is no significant leak in, for example, the casing; and there is no 

significant fluid movement into an underground source of drinking water 

through vertical channels adjacent to the injection well. Texas also 

requires operators to demonstrate the mechanical integrity of Class II UIC 

wells generally by conducting specified pressure tests before 

commencing injection, after conducting maintenance, and every 5 years. 

With regard to monitoring and reporting, Ohio requires operators to 

monitor injection pressures and volumes for each disposal well on a daily 

basis and to report annually on maximum and monthly average pressure 

and volumes.

Aside from underground injection, there are several other options for 

disposal of produced water, though the specifics vary across and within 

states. For example, regulatory agencies issue NPDES permits in 

Colorado, Texas, and Wyoming for direct discharges to surface waters in 

certain cases;81

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 

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.

 

81Texas 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.
 

Page 60 GAO-12-874 Unconventional Oil and Gas Development

Pennsylvania, but there have been some recent efforts to restrict such 

disposal.

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.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.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.

85

 

82As 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. 

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 

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

84Ohio 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. 

85Patriot Water Treatment, LLC v. Korleski, ERAC case Nos. 156477, 156588, 786501, 

and 786589 (2012).
 

Page 61 GAO-12-874 Unconventional Oil and Gas Development

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.86

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 

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.

 

86State Review of Oil and Natural Gas Environmental Regulations, Inc., Colorado 

Hydraulic Fracturing State Review (Oklahoma City, OK: 2011).
 

Page 62 GAO-12-874 Unconventional Oil and Gas Development

surface owner of the site if they were obtained using drilling fluids with a 

chloride concentration of 3,000 milligrams per liter or less.

87

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.

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.

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 

 

87Landfarming 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.
 

Page 63 GAO-12-874 Unconventional Oil and Gas Development

radioactive material (NORM) or technologically-enhanced NORM.88

For more details about states waste management and disposal 

requirements, see appendix IX.

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.

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 

 

88Technologically-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.

Managing Air Emissions
 

Page 64 GAO-12-874 Unconventional Oil and Gas Development

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 
 

Page 65 GAO-12-874 Unconventional Oil and Gas Development

protective breathing equipment at the well site, installing a flare line and a 

suitable method for lighting the flare, and conducting training. In some 

cases, hydrogen sulfide requirements overlap with flaring requirements. 

For example, flares used for treating gas containing hydrogen sulfide in 

North Dakota must be equipped and operated with an automatic ignitor or 

a continuous burning pilot, which must be maintained in good working 

order, including flares that are used for emergency purposes only.

For more details about state requirements for managing air emissions, 

see appendix IX.

One of the states in our review—Pennsylvania—is also part of a regional 

commission that implements additional requirements governing several 

aspects of natural gas development. Specifically, the Delaware River 

Basin Commission is a regional body whose members include the 

governors of Delaware, New Jersey, New York, Pennsylvania, as well as 

the U.S. Army Corps of Engineers’ Division Engineer for the North 

Atlantic Division. The commission regulates water quantity and quality 

within the basin, which spans approximately 13,500 square miles.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 

 

89The 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.

Regional Commission 

Implements Additional 

Requirements
 

Page 66 GAO-12-874 Unconventional Oil and Gas Development

commission to consider the cumulative impacts of development from 

numerous well pads, associated roads, and pipeline infrastructure, and to 

minimize and mitigate disturbance on lands most critical to water 

resources, such as core forests and steep slopes. The plans will also help 

protect water resources for approximately 15 million people, including 

residents of New York City and Philadelphia.

All six states in our review have updated some aspects of their 

requirements in recent years. Key examples include the following:

• Colorado made extensive amendments to its oil and gas regulations 

in 2008, which included, among other things, restrictions on locating 

wells near drinking water sources, measures to manage stormwater, 

and requirements to consult with the Colorado Division of Wildlife in 

certain cases to minimize adverse impacts on wildlife. According to 

state officials, these regulatory updates served three primary 

purposes: (1) address the growing impacts of increased oil and gas 

development; (2) implement state legislation passed in 2007 directing 

the Colorado Oil and Gas Conservation Commission to work with the 

Colorado Department of Public Health and Environment and the 

Colorado Division of Wildlife to update its regulations; and (3) update 

existing rules to enhance clarity, respond to new information, and 

reflect current practices and procedures.

• In 2012, North Dakota implemented 26 rule changes, including the 

requirement for operators to drain pits and properly dispose of their 

contents within 72 hours after well completion, servicing, or plugging 

operations have ceased. According to state officials, this change was 

implemented in response to a number of pit overflows that occurred 

during the spring melt in 2010 and 2011.

• In 2012, Ohio adopted new oil and gas well construction regulations to 

implement state legislation passed in 2010. The new regulations 

include casing and cementing requirements and requirements to 

disclose the chemicals used in hydraulic fracturing.

• Pennsylvania passed legislation in 2012 which, among other things, 

requires unconventional wells to be sited at greater setback distances 

from existing buildings and water wells than was previously required 

for all wells and requires chemical disclosure through FracFocus. In 

addition, the new legislation increases the distance from which an 

States Have Recently 

Updated Some 

Requirements
 

Page 67 GAO-12-874 Unconventional Oil and Gas Development

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. 
 

Page 68 GAO-12-874 Unconventional Oil and Gas Development

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.90 State regulators are also considering additional 

regulatory changes in response to the remaining recommendations of the 

Governor’s Marcellus Shale Advisory Board.

Federal land management agencies, including the Bureau of Land 

Management (BLM), Forest Service, National Park Service, and Fish and 

Wildlife Service (FWS) manage federal lands for a variety of purposes. 

Specifically, both the Forest Service and BLM manage their lands for 

multiple uses, including oil and gas development; recreation; and provision 

of a sustained yield of renewable resources, such as timber, fish and 

wildlife, and forage for livestock. By contrast, the Park Service manages its 

lands to conserve the scenery, natural and historical objects, and wildlife so 

they remain unimpaired for the enjoyment of present and future 

generations. Similarly, FWS manages national wildlife refuges for the 

benefit of current and future generations, seeking to conserve and, where 

appropriate, restore fish, wildlife, plant resources, and their habitats.

Each of these agencies imposes additional requirements for oil and gas 

development on its lands to meet its obligations with respect to its 

mission. These additional federal requirements are the same for 

conventional and unconventional oil and gas development. In some 

cases, the surface rights to a piece of land and the right to extract oil and 

gas—called mineral rights—are owned by different parties. For example, 

private mineral rights might underlie lands where the surface is managed 

by a federal agency. Requirements for developing mineral rights vary 

based on whether the mineral rights are owned by the federal 

government or by a private entity.

 

90The 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. 

Additional 

Requirements Apply 

on Federal Lands
 

Page 69 GAO-12-874 Unconventional Oil and Gas Development

Requirements for operators developing federally owned mineral rights are 

imposed by federal agencies during planning and leasing processes 

carried out by federal agencies. Operators must also meet specific 

requirements during several of the activities involved in oil and gas 

development.

BLM has primary authority for issuing leases and permits for federal oil 

and gas resources even in cases when surface lands are managed by 

other federal agencies or owned by private landowners. The majority of 

federal oil and gas leases underlie lands managed by BLM or the Forest 

Service, but there are some federal oil and gas resources available for 

leasing under lands managed by other federal agencies or private 

landowners.91

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.

Altogether, BLM oversees oil and gas development on 

approximately 700 million subsurface acres.

92

 

91BLM 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.

Regulations implementing NEPA generally require an agency to prepare 

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

Requirements for 

Federally Owned Mineral 

Rights

Planning and Leasing Processes
 

Page 70 GAO-12-874 Unconventional Oil and Gas Development

either an environmental assessment or environmental impact statement.93

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

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.

Surface land 

management agency

Availability for oil and gas 

development Role in approving leases Role in approving drilling permits

BLM Generally availablea BLM is primary authority for 

approving leases

BLM is primary authority for 

approving drilling permits

Forest Service Generally availableb Coordinates with BLM regarding 

surface issues and must authorize 

the lease

Forest Service must approve all 

surface disturbing activities before 

BLM approves the drilling permit.

Private Landowner Generally available No specific role; may participate in 

public comment process

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. 

 

93Agencies 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).
 

Page 71 GAO-12-874 Unconventional Oil and Gas Development

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. 

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 
 

Page 72 GAO-12-874 Unconventional Oil and Gas Development

Service personnel note possible noncompliance related to drilling or 

production operations, they notify and coordinate with BLM. Similarly, 

officials said that, if BLM conducts an inspection and notices potential 

violations of the surface use plan of operations, they contact the Forest 

Service. 

Operators of wells accessing federal oil and gas also face requirements 

related to activities involved in oil and gas development. Specifically, 

these requirements are related to siting and site preparation; drilling, 

casing, and cementing; well plugging; site reclamation; waste 

management and disposal; and managing air emissions. Requirements 

are as follows:

• Siting and site preparation. BLM requires an operator to identify all 

known oil and gas wells within a 1-mile radius of the proposed 

location. BLM does not require baseline testing of groundwater near 

the proposed well site. BLM generally prohibits an operator from 

conducting operations in areas highly susceptible to erosion, such as 

floodplains or wetlands, and recommends that operators avoid steep 

slopes and consider temporarily suspending operations when 

weather-related conditions, such as freezing or thawing ground, would 

cause excessive impacts.

• Drilling, casing, and cementing. As discussed above, operators must 

submit detailed drilling plans as part of their APD. The drilling plan must 

be sufficiently detailed for BLM to appraise the technical adequacy of 

the proposed project and must include, among other things: (1) 

geologic information about the formations that the operator expects to 

encounter while drilling; (2) whether these formations contain oil, gas, 

or useable water and, if so, how the operator plans to protect such 

resources; (3) a proposed casing plan, including details about the size 

of the casing and the depths at which each layer of casing will be set; 

(4) the estimated amount and type of cement to be used in the well; 

and (5) a description of any horizontal drilling that is planned.

• Well plugging. Operators are required to provide notice to and get 

approval from BLM prior to plugging a well and to comply with specific 

technical standards in plugging the well.

• Site reclamation. Operators describe their plans for reclamation in the 

surface use plan of operations submitted as part of the APD. BLM 

requires operators to return the disturbed land to productive use. All 

well pads, pits, and roads must be reclaimed and revegetated. Interim 

Requirements Related to Oil 

and Gas Development 

Activities
 

Page 73 GAO-12-874 Unconventional Oil and Gas Development

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.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 

 

94BLM and the Forest Service also include air quality impacts in the NEPA analysis 

conducted for leasing and permitting actions.
 

Page 74 GAO-12-874 Unconventional Oil and Gas Development

hydraulic fracturing on public lands. According to BLM officials, a final rule 

is expected in the fall of 2012.

Subject to some restriction, owners of mineral rights that underlie federal 

lands have the legal authority to explore for oil and gas and, if such 

resources are found, to develop them.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.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 BLMmanaged 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 

 

95In 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).

96In 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.

Requirements for Privately 

Owned Mineral Rights 

under Federal Surface 

Lands
 

Page 75 GAO-12-874 Unconventional Oil and Gas Development

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 threefourths are producing privately owned minerals.97

Regarding lands managed by FWS, we reported in August 2003 that 

oversight and management of oil and gas activities varies widely among 

wildlife refuges.

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.

98

 

97According 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, 

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, 

GAO/RCED-84-101 (Washington, D.C.: July 

26, 1984).

98See GAO, National Wildlife Refuges: Opportunities to Improve the Management and 

Oversight of Oil and Gas Activities on Federal Lands, GAO-03-517 (Washington, D.C.: 

Aug. 28, 2003).
 

Page 76 GAO-12-874 Unconventional Oil and Gas Development

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.99

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.

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.

 

99Officials said that these other federal authorities could include, for example, CWA, 

Endangered Species Act, or Migratory Bird Conservation Act.
 

Page 77 GAO-12-874 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.

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.100

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.

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.

101

 

100As 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.

However, it is difficult for EPA to assess operators’ compliance because 

101As 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.

Federal and State 

Agencies Reported 

Several Challenges 

Regulating 

Unconventional Oil 

and Gas Development

Conducting Inspection and 

Enforcement Activities
 

Page 78 GAO-12-874 Unconventional Oil and Gas Development

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.102

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 

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.

 

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

Page 79 GAO-12-874 Unconventional Oil and Gas Development

those aspects of state UIC regulations that have been approved by 

federal regulation.

EPA officials also reported that the scope of their legal authorities for 

regulating oil and gas development is a challenge. For example, EPA 

officials in headquarters and Regional offices told us that the exclusion of 

exploration and production waste from hazardous waste regulations 

under RCRA significantly limits EPA’s role in regulating these wastes. For 

example, if a hazardous waste permit was required, then EPA would 

obtain information on the location of well sites, how much hazardous 

waste is generated at each site, and how the waste is disposed of; 

however, operators are not required to obtain hazardous waste permits 

for oil and gas exploration and production wastes, limiting EPA’s role.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.104 

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 

 

103EPA officials said that, at present, they could specifically request this type of 

information, but do not receive it automatically. 

104EPA Region 8 includes Colorado, Montana, North Dakota, South Dakota, Utah, and 

Wyoming.

Limited Legal Authorities

Hiring and Retaining Staff
 

Page 80 GAO-12-874 Unconventional Oil and Gas Development

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.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.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. 

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 

 

105GAO, Oil and Gas Management: Interior’s Oil and Gas Production Verification Efforts 

Do Not Provide Reasonable Assurance of Accurate Measurement of Production Volumes, 

GAO-10-313 (Washington, D.C.: Mar. 15, 2010).

106GAO, Oil and Gas Leasing: Past Work Identifies Numerous Challenges with Interior’s 

Oversight, GAO-11-487T (Washington, D.C.: Mar. 17, 2011).

Public Education
 

Page 81 GAO-12-874 Unconventional Oil and Gas Development

and that BLM has been fielding many information requests about its use in 

oil and gas development. In addition, officials in five of the six states—

Colorado, Ohio, Pennsylvania, Texas, and Wyoming—reported challenges 

related to public education. For example, regulators in Ohio said that their 

agency has conducted more public outreach in the last year than in the 

past 20 years and, in response to this public interest in shale drilling and 

hydraulic fracturing, they will be adding more communications staff. 

Similarly, oil and gas development is moving into areas of Colorado that 

are not accustomed to this development, and state officials in both the 

Department of Public Health and Environment and the Oil and Gas 

Conservation Commission said that they have spent a lot of time providing 

the public with information on topics including hydraulic fracturing. State 

regulators in Wyoming said that educating the public has been a challenge 

since coalbed methane and tight sandstone development in Wyoming is 

very different than, for example, shale gas development in Pennsylvania, 

but the media do not always make this clear. State regulators in North 

Dakota did not report public education as a challenge.

We provided a draft of this report to EPA and to the Departments of 

Agriculture and the Interior for review and comment. The Departments of 

Agriculture and Interior provided written comments on the draft, which are 

summarized below and appear in their entirety in appendixes XI and XII, 

respectively. In addition, both Departments and EPA provided technical 

comments, which we incorporated as appropriate.

In its written comments, the Department of Agriculture agreed with our 

findings and noted that the Forest Service also faces challenges hiring 

and retaining qualified staff. In response, we added this information to the 

report.

In its written comments, the Department of the Interior provided additional 

clarifying information on its efforts concerning BLM’s proposed rule on 

hydraulic fracturing and steps BLM is taking to hire and retain skilled 

technical staff. In response, we included additional information in the 

report about BLM’s proposed rule on hydraulic fracturing.

Agency Comments 

and Our Evaluation
 

Page 82 GAO-12-874 Unconventional Oil and Gas Development

As agreed with your offices, unless you publicly announce the contents of 

this report earlier, we plan no further distribution until 30 days from the 

report date. At that time, we will send copies of this report to the 

appropriate congressional committees, the EPA Administrator, the 

Secretaries of Agriculture and the Interior, the Director of the Bureau of 

Land Management, and other interested parties. In addition, this report 

will be available at no charge on the GAO website at http://www.gao.gov. 

If you or your staff members have any questions about this report, please 

contact me at (202) 512-3841 or trimbled@gao.gov. Contact points for 

our Offices of Congressional Relations and Public Affairs may be found 

on the last page of this report. GAO staff who made major contributions to 

this report are listed in appendix XIII.

David C. Trimble

Director

Natural Resources and Environment
 

Page 83 GAO-12-874 Unconventional Oil and Gas Development

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
Appendix I: Objectives, Scope, and 

Methodology

Page 84 GAO-12-874 Unconventional Oil and Gas Development

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 

Appendix I: Objectives, Scope, and 

Methodology 
Appendix I: Objectives, Scope, and 

Methodology

Page 85 GAO-12-874 Unconventional Oil and Gas Development

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
Appendix I: Objectives, Scope, and 

Methodology

Page 86 GAO-12-874 Unconventional Oil and Gas Development

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.

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 
Appendix I: Objectives, Scope, and 

Methodology

Page 87 GAO-12-874 Unconventional Oil and Gas Development

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.1

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.

We also collected testimonial evidence, as 

described above, from knowledgeable federal and state officials, as well 

as industry, environmental, and public health organizations.

 

1

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.
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 88 GAO-12-874 Unconventional Oil and Gas Development

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.1 Under the act, EPA is authorized to set standards for 

certain naturally-occurring and man-made contaminants in public drinking 

water systems, among other things. Key aspects of SDWA for 

unconventional oil and gas development include provisions regarding 

underground injection and EPA’s imminent and substantial endangerment 

authority.

SDWA also regulates the placement of wastewater and other fluids 

underground through the Underground Injection Control (UIC) program.2

1) (i) Which supplies any public water system; or

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:

(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.3

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.4

 

1

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.

In particular, 

the regulations establish that the criterion that an aquifer “cannot now and 

2

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

3

40 C.F.R. § 146.3 (2012). 

4

40 C.F.R. § 146.4 (2012).

Appendix II: Key Requirements and 

Authorities under the Safe Drinking Water 

Act 

Underground 

Injection Control 

Program 
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 89 GAO-12-874 Unconventional Oil and Gas Development

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.5 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.6

There are six classes or categories of wells regulated through the UIC 

program.

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).

7 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.8

The EPA Administrator may approve by rule a state to have primary 

enforcement responsibility for the UIC program.

 

9

 

5

40 C.F.R. § 146.4 (2012). 

A state with an approved 

program assumes responsibility for implementing the program, including 

6

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.

7

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

8

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.

9

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).
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 90 GAO-12-874 Unconventional Oil and Gas Development

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.10

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 

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.

 

10SDWA § 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 

“[r]egulations 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).
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 91 GAO-12-874 Unconventional Oil and Gas Development

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.11 The Environmental Appeals Board 

denied all other claims against EPA.

12 Under the remand, EPA may take 

further action consistent with the decision, which could include such 

actions as additions or revisions to the record and reconsideration of the 

permits. With respect to applications, according to Region 3 officials, until 

recently EPA did not receive many applications for new Class II brine 

disposal wells in Pennsylvania. EPA officials said that they have received 

five permit applications for such wells in the last 4 months and expect 

continued interest in the future.

Under SDWA, UIC programs are to prohibit underground injection, other 

than into a well that is authorized by rule or permitted.13 Class II UIC wells 

must meet requirements contained in either EPA regulations,14 or relevant 

state regulations. Federal regulations for Class II wells include 

construction, operating, monitoring and testing, reporting, and closure 

requirements.15 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.16 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.17

 

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

Permits may be conditioned upon a compliance schedule for such 

corrective actions. According to EPA, in Pennsylvania many old wells 

12Id.

13SDWA §§ 1421(b)(1)(A), 1422(c), 42 U.S.C. §§ 300h(b)(1)(A) (state programs), 300h1(c) (EPA direct implementation programs); 40 C.F.R. § 144.11 (2012).

14See 40 C.F.R. pt. 144 (2012).

1540 C.F.R. §§ 146.21 – 146.24 (2012).

1640 C.F.R. §§ 146.24, 146.6 (2012).

1740 C.F.R. §§ 144.55(a), (b)(2)-(3); 146.7 (2012).

Class II UIC Requirements
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 92 GAO-12-874 Unconventional Oil and Gas Development

have had to be replugged in order to ensure they cannot present a 

potential pathway for migration.18

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.19 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.20 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.21 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.22

For additional information on the Class II UIC requirements applicable 

under EPA’s program in Pennsylvania, see appendix IX.

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.

 

18See Karen Johnson, Chief, Ground Water & Enforcement Branch, EPA Region 3, 

Marcellus Shale Educational Webinar, Feb. 18, 2010 (written Q&A).

1940 C.F.R. §§ 146.24, 146.24(a)(2) (2012).

2040 C.F.R. § 146.22(a) (2012).

21See 40 C.F.R. §§ 144.27(a), 144.51(h), 144.52(a)(9), 144.52(b)(1) (2012).

22 40 C.F.R. §§ 144.12(a), 144.1(b), (f) (2012).
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 93 GAO-12-874 Unconventional Oil and Gas Development

Historically, UIC programs did not include hydraulic fracturing injections as 

among those subject to their requirements.23 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.24 Subsequently, 

Alabama revised its program to include injection of hydraulic fracturing 

fluids,25 and EPA approved it pursuant to SDWA section 1425 in 2000.26

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.27 Alabama amended its regulations in 2001 and 

2003.28 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.29

EPA initiated a study in 2000 to further examine the issue of fracturing in 

coalbed methane in areas of underground sources of drinking water.30

 

23See, e.g., Legal Envtl. Assistance Found. Inc. v. EPA, 118 F.3d 1467, 1471 (11th 

Cir.1997).

EPA officials said the study showed diesel fuel was the primary risk. 

Subsequently, in 2003, EPA entered into a memorandum of agreement 

24Id.

25Ala. Admin. Code r. 400-4-5-.04 (filed July 9, 1999; amended Nov. 9, 1999; repealed 

Apr. 11, 2000).

2665 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.

27Legal Envtl. Assistance Found. Inc. v. EPA, 276 F.3d 1253 (11th Cir. 2001).

28See Ala. Admin. Code r. 400 -3-8-.03.

2969 Fed. Reg. 42,341 (July 15, 2004) (referencing Alabama rule 400 -3-8-.03).

30EPA, Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic 

Fracturing of Coalbed Methane Reservoirs, EPA 816-R-04-003 (2004).

Class II UIC Programs and 

Hydraulic Fracturing
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 94 GAO-12-874 Unconventional Oil and Gas Development

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.31

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.

According to EPA officials, the agreement is still in effect 

insofar as the agency has not received any termination notices.

On December 7, 2004, EPA’s Assistant Administrator for Water 

responded to a congressional request for information on EPA’s actions on 

this issue.32 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.33

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 200534

 

31Memorandum 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).

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 

32151 Cong. Rec. S7277 (daily ed. June 23, 2005) (letter of Benjamin Grumbles, Assistant 

Administrator, Office of Water, EPA, to Senator Jeffords).

33Id.

34Pub. L. No. 109–58 § 322, 119 Stat. 594 (2005) (modifying SDWA § 1421(d)(1), 42 

U.S.C. § 300h(d)(1) (2012)).
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 95 GAO-12-874 Unconventional Oil and Gas Development

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.

35 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.

36

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.

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.

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 

 

35EPA, 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). 

3677 Fed. Reg. at 27,452.

Enforcement
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 96 GAO-12-874 Unconventional Oil and Gas Development

provision.37 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.38

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.39 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.40 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.41

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.42

 

37SDWA 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).

In another 

38For federal regulations setting forth EPA-approved state programs, see 40 C.F.R. pt. 

147 (2012).

39SDWA § 1423(a), 42 U.S.C. § 300h-2(a) (2012).

40SDWA § 1423(a)(1), 42 U.S.C. § 300h-2(a)(1) (2012).

41SDWA § 1445(b)(1), 42 U.S.C. § 300j-4(b)(1) (2012).

42Titusville 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.
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 97 GAO-12-874 Unconventional Oil and Gas Development

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.43 According to officials, EPA was able to 

confirm during well rework that there was no fluid movement outside the 

well’s casing and no endangerment to an aquifer. 

While SDWA generally does not directly regulate land use activities that 

may pose risk to drinking water supplies,44 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.”45

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. 

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.

 

43In the Matter of EXCO Resources (PA) LLC, Consent Agreement, EPA Docket No. 

SDWA-03-2012-0061 (Mar. 30, 2012).

44SDWA 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).

45SDWA § 1431, 42 U.S.C § 300i(a) (2012).

Imminent and 

Substantial 

Endangerment 

Authorities
Appendix II: Key Requirements and Authorities 

under the Safe Drinking Water Act

Page 98 GAO-12-874 Unconventional Oil and Gas Development

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.46

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.47 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.48 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.49 On March 29, 2012, EPA withdrew its administrative order, 

and the parties moved for voluntary dismissal of both cases.50 In a letter 

to EPA, the operator agreed to conduct sampling of 20 private water wells 

for 1 year.51

 

46EPA, 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).

47In the Matter of Range Resources Corporation, Administrative Order, EPA Docket No. 

SDWA-06-2011-1208 (Dec. 7, 2010).

48United States v. Range Production Co., No. 3:11-cv-00116-F (N.D. Tex. Jan. 18, 2011).

49Brief, Range Resources Corporation, et al. v. EPA, No. 11-60040 (5th Cir. Mar. 22, 

2011).

50See 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).

51Letter, Bracewell & Giuliani to EPA Office of Enforcement & Compliance Assurance, 

Mar. 30, 2012.
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 99 GAO-12-874 Unconventional Oil and Gas Development

Under the Clean Water Act (CWA),1 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.2

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.3

Under CWA section 311 and the Oil Pollution Act,4 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.5

This review focuses on EPA regulatory activities under these programs

relevant to unconventional oil and gas development activities.

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. 

 

1

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.

2

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.

3

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); 

http://water.epa.gov/lawsregs/guidance/cwa/dredgdis/404c_index.cfm

4

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).

5

40 C.F.R. pt. 112 (2012).

Appendix III: Key Requirements and 

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

Authorities under the Clean Water Act 

Page 100 GAO-12-874 Unconventional Oil and Gas Development

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 states6 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.7 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 publiclyowned or other wastewater treatment plants, particularly in some 

locations where brine disposal wells are unavailable.8 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,9 and some 

produced water is discharged to surface water in certain geographical 

areas.10

 

6

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.

7

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 www.epa.gov/hydraulicfracture/. 

8

76 Fed. Reg. 66,286, 66,296 (Oct. 26, 2011).

9

See 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.

10See http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm

National Pollutant 

Discharge Elimination 

System Program
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 101 GAO-12-874 Unconventional Oil and Gas Development

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.11 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).12

EPA has developed effluent limitations guidelines for several 

subcategories of the oil and gas extraction industry.13 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.14 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.15 The 

guidelines for these subcategories were finalized in 1979.16

 

11Water-quality based effluent limitations are imposed when technology-based limitations 

are insufficient for receiving waters to meet water quality standards. 

12See, e.g., 76 Fed. Reg. at 66,288.

1340 C.F.R. pt. 435 (2012).

14See, e.g., 40 C.F.R. § 435.30 (2012).

1540 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). 

16In 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). 

Existing Effluent 

Limitations Guidelines for 

Oil and Gas Extraction
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 102 GAO-12-874 Unconventional Oil and Gas Development

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 thenevaluated technologies, and that the agency could revisit this decision at 

a later date.17 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.18

Existing effluent limitations guidelines do not apply to wastewater 

discharges from coalbed methane extraction.19 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.20

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 

 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.

 

1741 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.

18By definition, such requirements would be inapplicable to the agricultural and wildlife use 

subcategory.

1976 Fed. Reg. 66,286, 66,293 (Oct. 26, 2011).

20EPA, Technical Support Document for the 2006 Effluent Guidelines Program Plan, EPA821R-06-018, 6-1 (2006).
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 103 GAO-12-874 Unconventional Oil and Gas Development

relevant permitting authority, using best professional judgment21

Table 8 summarizes the coverage and key requirements of the existing 

guidelines.

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: Summary of Effluent Limitations Guidelines for Wastewater Discharges from Selected Subcategories of Oil and Gas

Wells Located on Land

Subcategory of oil or gas well

Covered by existing effluent limitations 

guideline Permit requirement

Wells included in an existing segment subcategory 

Onshore wells that do not fit into any of the 

other subcategories

Yes – direct dischargers

No – indirect dischargers (no pretreatment 

requirements established)

No discharge

Agricultural and Wildlife Water Use 

subcategory

Yes Discharge of produced water allowed 

where conditions met, and subject to max 

daily limit for oil and grease

Stripper wells Subcategory created, but no effluent 

limitations or pretreatment requirements 

established

Case-by-case

Wells that are not included in any existing segment subcategory 

Coalbed methane extraction wells No 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). 

The effluent limitations guideline for the Oil and Gas Extraction point 

source category, onshore subcategory establishes the best practicable 

control technology currently available as

 

21EPA has noted that permit writers are to develop technology-based limits on a case-bycase 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).

Onshore Subcategory
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 104 GAO-12-874 Unconventional Oil and Gas Development

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).22

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.23

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 “[i]t is intended as a relatively restrictive subcategorization based on 

the unique factors of prior usage in the Region, arid conditions and the 

existence of low salinity, potable water.”

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.

24

For this subcategory, the guideline establishes the best practicable 

control technology currently available as

 

2240 C.F.R. § 435.32 (2012) (emphasis added).

2341 Fed. Reg.44,942, 44,946 (Oct. 13, 1976). 

2444 Fed. Reg. 22,069, 22,072 (Apr. 13, 1979).

Agricultural and Wildlife Water 

Use Subcategory 
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 105 GAO-12-874 Unconventional Oil and Gas Development

“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.25

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,26 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.27

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.

EPA is responsible for oversight and has not issued 

guidance on this topic.

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.

 

2540 C.F.R. §§ 435.50-52 (2012).

2640 C.F.R. § 435.51(c) (2012).

27EPA issues permits in a small number of states that do not have responsibility for the 

NPDES program, and on tribal lands.
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 106 GAO-12-874 Unconventional Oil and Gas Development

According to EPA, 349 discharge permits in the Agricultural and Wildlife 

Water Use subcategory have been issued. Most of these permitted 

discharges are located in Wyoming, Montana, and Colorado.

On October 26, 2011, EPA announced in its Final 2010 Effluent 

Limitations Program Plan that the agency will develop effluent limitations 

guidelines and standards for wastewater discharges from the coalbed 

methane extraction industry.28

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 2007.29 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.30 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.31

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 

According to EPA officials, 

most coalbed methane wastewater discharges have NPDES permits.

 

2876 Fed. Reg. 66,286 (Oct. 26, 2011).

2976 Fed. Reg. at 66,293. See also 

http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm

30EPA, Coalbed Methane Extraction: Detailed Study Report, EPA-820-R-10-022 (2010).

31Id. 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).

Anticipated Rulemaking to 

Develop Effluent 

Limitations Guidelines for 

Oil and Gas Extraction 

from Coalbed Methane 

Formations
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 107 GAO-12-874 Unconventional Oil and Gas Development

initiate rulemaking.32 EPA is in the preproposal stage of rulemaking for 

the coalbed methane effluent guidelines and standards.33 EPA’s website 

indicates the projected date for publication of the proposed rule is June 

2013.

Facilities discharging industrial wastewater to publicly-owned treatment 

works (POTW) treatment plants are subject to general pretreatment 

requirements. In addition, the POTW receiving such industrial 

wastewaters also has responsibilities related to its own permit and to 

receiving these wastewaters.

EPA has issued general pretreatment requirements applicable to all 

existing and new indirect dischargers of pollutants (other than of purely 

domestic, or sanitary, sewage) to a POTW, including any dischargers of 

wastewaters associated with oil and gas wells.34 Notably, such 

discharges are subject to a general requirement that the pollutants do not 

cause pass through or interference with the POTW.35 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.36

Other standard provisions for indirect discharges involve a prohibition on 

corrosive discharges.37

 

3276 Fed. Reg. at 66,294.

According to EPA officials, in produced water, 

33See http://yosemite.epa.gov/opei/RuleGate.nsf/byRIN/2040-AF35?opendocument#1, 

RIN 2040-AF35, docket no. EPA-HQ-OW-2011-0334.

34See generally 40 C.F.R. pt. 403 (2012).

3540 C.F.R. § 403.5(a)(1) (2012). 

36Pass 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).

3740 C.F.R. § 403.5(b)(2) (2012).

Generally Applicable 

Pretreatment Standards 

and POTW Obligations

General standards
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 108 GAO-12-874 Unconventional Oil and Gas Development

concerns for corrosivity would be related to high chlorides and sulfides

which could adversely affect pipes and gaskets in the POTW.38

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.39 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.40

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.41

 

38See 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.”).

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 

39Memorandum 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 http://cfpub.epa.gov/npdes/hydrofracturing.cfm

40NPDES 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.

41In 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. 
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 109 GAO-12-874 Unconventional Oil and Gas Development

production wastewater until completing an evaluation and sampling, and 

to eliminate and prevent recurrence of the violations.

Generally, local governments operating POTWs are responsible for 

ensuring that indirect dischargers comply with any applicable national 

pretreatment standards.42 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.43

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.

EPA or states may be responsible for 

ensuring these POTWs meet their obligations and for approving the 

POTW’s pretreatment plans.

44

 

42See EPA, Introduction to the National Pretreatment Program, EPA-833-B-11-001,3-3 

(2011).

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 

43C.F.R. § 403.8(a) (2012); see also http://cfpub.epa.gov/npdes/faqs.cfm?program_id=3

44Memorandum 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 

http://cfpub.epa.gov/npdes/hydrofracturing.cfm

POTW Obligations
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 110 GAO-12-874 Unconventional Oil and Gas Development

fishkill attributed to a spill of diluted produced water in Hopewell 

Township, PA.45

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.46 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.47

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.

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.

48 Specifically, EPA plans to issue two 

guidance documents, one for permit writers and another for POTWs.

 

4576 Fed. Reg. 66,286, 66,297 (Oct. 26, 2011).

46Memorandum 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 

http://cfpub.epa.gov/npdes/hydrofracturing.cfm

47Id. at 9; see also 40 C.F.R. § 122.42(b)(1) (2012).

48http://www.epa.gov/hydraulicfracture/#swdischarges
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 111 GAO-12-874 Unconventional Oil and Gas Development

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.49

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.50 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.51 EPA intends to conduct a survey, 

among other things, to collect information on management of produced 

water to support the rulemaking.52 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.53

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. 

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.

 

49See, e.g., 76 Fed. Reg. at 66,292, 66,295, 74 Fed. Reg. 68,599 (Dec. 28, 2009).

5076 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. 

5151Id. at 66,297.

52Id. 

53Id. at 66,298.

Anticipated Rulemaking to 

Develop Pretreatment 

Standards for Gas 

Extraction from Shale 

Formations
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 112 GAO-12-874 Unconventional Oil and Gas Development

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.54 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.55 EPA subsequently issued 

regulations that address stormwater discharges from several source 

categories, including certain industrial activities and construction 

activities.56

Generally, industrial sites obtain coverage for stormater through a general 

permit, such as the multisector general permit or construction general 

permit.57 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.58

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,59

 

54See 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)).

raw material, 

55Id., 55 Fed. Reg. 47,990, 47,992 (Nov. 16, 1990) (Phase 1 rule).

5655 Fed. Reg. at 47,990.

57See Multisector General Permit at App. C.

58See EPA, 2012 Construction General Permit Fact Sheet at 6-7, 36.

59Subsequently, 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).

NPDES for Stormwater 

Discharges

Stormwater from Industrial 

Activities
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 113 GAO-12-874 Unconventional Oil and Gas Development

intermediate products, finished product, byproduct, or waste products located on the 

site of such operations.60

Interpreting the provision exempting oil and gas facilities, EPA issued 

regulations requiring permits for contaminated stormwater from oil and 

gas facilities.61 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.62

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,63

 

60Water Quality Act of 1987, § 401, 101 Stat. 65-66 (codified at 33 U.S.C. § 1342(l)(2) 

(2012)).

including Texas, and 

6155 Fed. Reg. at 48,029, 40 C.F.R. §§ 122.26(b)(14)(iii), (c)(1)(iii) (2012).

62Id. 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).

63The states are Idaho, Massachusetts, Texas, Oklahoma, and Alaska.
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 114 GAO-12-874 Unconventional Oil and Gas Development

identified some stormwater general permit notifications for facilities that 

could be well sites.64

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.65 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 2006.66

 

64Specifically, 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). 

65CWA §§ 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)). 

66In 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. 

http://cfpub.epa.gov/npdes/stormwater/cgp.cfm

Stormwater from 

Construction Activity
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 115 GAO-12-874 Unconventional Oil and Gas Development

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,”67 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.”68

In response to these amendments, in 2006, EPA revised a key provision 

of the regulations concerning oil and gas stormwater discharges.69 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 2008.70 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.71 EPA officials said the agency intends to revise its 

regulations to address the court’s vacatur in an upcoming stormwater 

rulemaking,

72

According to EPA officials, during construction, oil and gas well sites 

would have no permit requirement because of the statutory exemption.

with the proposal expected in 2013.

 

67Water Quality Act of 1987 § 401 (adding 33 U.S.C. § 1342(l)(2)).

68 Energy Policy Act of 2005, Pub. L. No. 109–58, § 323, 119 Stat. 594, 694 (adding 33 

U.S.C. § 1362(24) (2012)).

6971 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.” 

70Natural Resources Defense Council v. EPA, 526 F.3d 591 (9th Cir. 2008).

71Id. See also 

http://cfpub.epa.gov/npdes/regresult.cfm?program_id=6&type=1&sort=name&view=all

72Compare 40 C.F.R. § 122.26 (2012) with 40 C.F.R. § 122.26 (2005).
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 116 GAO-12-874 Unconventional Oil and Gas Development

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.73 Among other 

things, EPA can take such actions if a well operator violates the CWA 

prohibition on unauthorized discharges of pollutants to surface waters.74

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.75 For example, EPA has authority to inspect facilities 

where an effluent source is located.76

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.77 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.78 The produced water travelled overland for 333 feet, then 

entered a stream tributary to an interstate river. The company agreed to 

pay a civil penalty and to conduct a macroinvertebrate study for the 

affected watershed.

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 

 

73CWA § 309, 33 U.S.C. § 1319 (2012).

74Id., 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.

75CWA § 308(a), 33 U.S.C. § 1318(a) (2012).

76CWA § 308(a)(B)(i), 33 U.S.C. § 1318(a)(B)(i) (2012).

77American Petroleum & Environmental Consultants, Inc., Cease and Desist 

Administrative Order, EPA Docket No. CWA-06-2012-1760 (Dec. 12, 2011).

78BP America Production Company, Combined Complaint and Consent Agreement, EPA 

Docket No. CWA-08-2012-0014 (May 15, 2012).

NPDES Enforcement

Imminent and Substantial 

Endangerment Authorities
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 117 GAO-12-874 Unconventional Oil and Gas Development

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.79 Unlike the analogous provisions of several other major 

environmental laws, however, CWA section 504 does not expressly 

mention administrative orders.

EPA’s Oil Pollution Prevention regulations, promulgated and amended 

pursuant to CWA and the Oil Pollution Act, impose spill prevention and 

response planning requirements on oil and gas well sites that meet 

thresholds.80 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.81

 

79CWA § 504, 33 U.S.C. § 1364 (2012).

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 

8040 C.F.R. pt. 112 (2012); see also 67 Fed. Reg. 47,042 (July 17, 2002).

81Id.

Oil and Hazardous 

Substances Spill 

Prevention, 

Reporting, and 

Response

Spill Prevention and 

Response Plans
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 118 GAO-12-874 Unconventional Oil and Gas Development

quantities of oil into or upon U.S. navigable waters or adjoining 

shorelines.82

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.83 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.84 Oil production facilities 

are exempt from the SPCC security provisions.85

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 2010.86

 

8240 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.”).

These amendments included several 

provisions easing requirements for oil production sites, such as excluding 

them from loading/unloading rack requirements, providing alternative 

8340 C.F.R. § 112.10 (2012).

84Id.

8540 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).

8673 Fed. Reg. 74,236 (Dec. 5, 2008).
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 119 GAO-12-874 Unconventional Oil and Gas Development

qualified facility eligibility criteria (for streamlined compliance with selfcertification of SPCC plans), and exempting certain produced water 

containers.87 In November 2009, EPA revised the amendments, 

eliminating these three provisions before they became effective.88

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.

 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

89

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.

 

8774 Fed. Reg. 58,784, 58,799-803 (Nov. 13, 2009).

88Id. at 58,799-803, 58,809-811.

89Id. at 58,802. See also Considerations for the Regulation of Onshore Oil Exploration 

and Production Facilities Under the Spill Prevention, Control, and Countermeasure 

Regulation (40 C.F.R. part 112)) (available at www.regulations.gov document EPA–HQ–

OPA–2007–0584–0015).
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 120 GAO-12-874 Unconventional Oil and Gas Development

EPA has developed guidance related to SPCC applicability and 

compliance for oil production, drilling, and workovers.90

EPA directly administers the SPCC program.

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.

91 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.92 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 2011.93

 

90See 

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). 

www.epa.gov/osweroei/content/spcc/spcc_up.htm, 

http://www.epa.gov/Region8/opa/wkshop.html (Cross Reference Matrix For Drilling And 

Workover Facilities).

91The Clean Water Act does not provide EPA with the authority to authorize states to 

implement the program in its place.

92GAO-08-482. 

93See 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).
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

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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.94 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,95 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.96 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.97 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.98 The plan is to provide, in essence, an emergency response 

action plan for the worst-case discharge and other relevant information.99

 

9440 C.F.R. § 112.20 (2012).

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.

95Id. at (f)(1), 40 C.F.R. Pt. 112, App. C, Att. C-1. 

9640 C.F.R. §§ 112.20(b)(1), (c), (f) (2012).

97Id. at (e).

98Id. 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). 

99Id. at (h).
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

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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.100 Relevant provisions require 

reporting of certain discharges of oil or a hazardous substance to these

waters.101

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.102

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.103 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.104 The 

National Response Center subsequently sends reports to EPA Regions 

and headquarters. With respect to oil, discharges of oil must be reported 

if they “(c)ause a film or sheen upon or discoloration of the surface of the 

water or adjoining shorelines or cause a sludge or emulsion to be 

deposited beneath the surface of the water or upon adjoining shorelines,” 

or if they violate applicable water quality standards.105

 

100CWA § 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.

With respect to 

101Id. at (b)(3)-(5). 

10240 C.F.R. § 116.4 (2012), see also CWA § 311(b)(2)(A), 33 U.S.C. § 1321(b)(2)(A) 

(2012).

103CWA § 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).

104CWA § 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).

10540 C.F.R. §§ 110.6, 110.3, 110.1 (2012), 

http://www.epa.gov/osweroe1/content/reporting/faq_subs.htm#pelist

Spill Prohibition and 

Reporting
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 123 GAO-12-874 Unconventional Oil and Gas Development

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.106

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.

107 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.108

Under CWA section 311, as required to carry out its purposes including 

spill prevention and response, EPA also has authority to require the 

owner or operator of a facility subject to the Oil Pollution Prevention 

Regulation, among other provisions, to establish and maintain such 

records; make such reports; install, use, and maintain such monitoring 

equipment and methods; provide such other information deemed 

necessary; and for entry and inspection of such facilities.

For 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.

109

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.110

 

10640 C.F.R. §§ 117.3; § 116.4 at table 116.4A; see also 40 C.F.R. § 302.4 at table 302.4 

(2012).

Section 311 also gives 

EPA the authority to access records and inspect facilities, and the ability 

107CWA § 311(c), 33 U.S.C. § 1321(c) (2012).

108Id., 40 C.F.R. pt. 300 (2012).

109CWA § 311(m)(2), 33 U.S.C. § 1321(m)(2) (2012). 

110Id. at (b)(6)-(7), (c), (e)(1)(B) (2012).

Spill Response Authority

Enforcement of SPCC and 

Spill Prohibition and 

Reporting Requirements
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 124 GAO-12-874 Unconventional Oil and Gas Development

to require provision of information, with respect to persons and facilities 

subject to section 311, including SPCC program requirements.111

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.112 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.113 EPA’s report 

stated that “[n]on-compliance with SPCC requirements was more 

pervasive than anticipated. Although the SPCC program has been the 

focus of outreach and compliance assistance nationally for more than 25

years, there remains a strong need to communicate its requirements, 

inspect regulated facilities, and conduct appropriate technical assistance 

or enforcement to ensure improved compliance.”114 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.115

Region 8 reported identifying 22 sites with documented SPCC violations 

as a result of subsequent efforts in 2004-2005.116 Information on the 

nature or resolution of these violations was not readily available.

 

111Id. at (m)(2) (2012).

112EPA Region 8, Oil and Gas Environmental Assessment Effort 1996 – 2002, v (2003).

113Id. at 7.

114Id. at 8.

115Id. at 8.

116EPA Region 8, Summary Report, Oil and Gas Environmental Assessment Activities in 

Wyoming during 2004-2006.
Appendix III: Key Requirements and 

Authorities under the Clean Water Act 

Page 125 GAO-12-874 Unconventional Oil and Gas Development

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.117

 

117CWA § 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.

Imminent and Substantial 

Endangerment Authority 

for Spills
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 126 GAO-12-874 Unconventional Oil and Gas Development

The Clean Air Act (CAA or the Act) is the primary law with the purpose to 

protect and enhance the nation’s air quality.1 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.2 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.3 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.4

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.

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:

5

 

1

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.

2

See CAA § 109, 42 U.S.C. § 7409 (2012).

3

CAA § 110, 42 U.S.C. § 7410 (2012).

4

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).

5

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. 

Appendix IV: Key Requirements and 

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

Authorities under the Clean Air Act 

Page 127 GAO-12-874 Unconventional Oil and Gas Development

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.6 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.7

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.8 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.9 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.10

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.

Each of these key 

programs is described below as it may apply to oil and gas well sites.

Finally, the Act includes provisions addressing accidental releases of 

dangerous pollutants to the air.11

 

6

NRDC, Drilling Down: Protecting Western Communities from the Health and 

Environmental Effects of Oil and Gas Production 11 (2007).

Oil and gas wells are unlikely to trigger 

the planning aspects of these provisions, according to EPA; however, the 

7

64 Fed. Reg. 32,610 (June 17, 1999).

8

CAA §§ 111(b)(, (f), 112(c)(2), (d), 42 U.S.C. §§ 7411(b), (f), 7412(c)(2), (d) (2012).

9

CAA §§ 165(a), 171-193, 160-169B, 42 U.S.C. §§ 7475(a), 7501-7515, 7470-7492 (2012). 

10CAA § 502, 42 U.S.C. § 7661a (2012), 40 C.F.R. §§ 70.3, 71.3 (2012).

11CAA § 112(r), 42 U.S.C. § 7412(r) (2012).
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 128 GAO-12-874 Unconventional Oil and Gas Development

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

Specific rule for oil and gas production sector, 

applicable to well sites?

Likely applicability to emissions at oil and gas 

well sites

National Emission 

Standards for 

Hazardous Air 

Pollutants 

(NESHAP)

Yes, addressing glycol dehydrators and storage 

vessels with potential for flash emissions at major 

sources and only triethylene glycol dehydrators at 

area sourcesa

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.

New Source 

Performance 

Standards (NSPS)

Yes, addressing gas well completions, pneumatic 

controllers, and some storage vessels

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.

New Source Review 

(NSR)

No (generally applicable) 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.

Title V Operating 

Permits 

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.

Unknown. 

Accidental Releases: 

Risk Management 

Program 

No (generally applicable) 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.

Accidental Releases: 

General Duty Clause

No (generally applicable) Applies; no threshold; EPA has used provision to 

conduct inspections and require control of leaks.

Greenhouse Gas 

Reporting

Yes 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.
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 129 GAO-12-874 Unconventional Oil and Gas Development

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.12 The list of HAPs includes several 

potentially found in oil and gas well emissions.13 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.14 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.15 The prevention of accidental releases regulation includes 

accidental releases of hydrogen sulfide.16

 

12Clean 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.

In a 1993 report to Congress, 

13The listed HAPs are also known as air toxics.

14In 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, 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).

15CAA § 112(b)(2), 42 U.S.C. § 7412(b)(2) (2012). 

1640 C.F.R. § 68.130 (2012).

National Emission 

Standards for 

Hazardous Air 

Pollutants

Hazardous Air Pollutants
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 130 GAO-12-874 Unconventional Oil and Gas Development

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.17

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).18 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.19 EPA 

officials told us they are considering the petition but have no specific 

timeline for acting upon it.

EPA is required to promulgate and periodically revise NESHAPs for 

source categories the agency has identified.20 NESHAPs may include 

standards for major sources and for area sources, which are any sources 

not major.21 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.22

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 

 

17The 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).

18Letter from Neil J. Carman, Sierra Club, et al, to Lisa Jackson, Administrator, EPA (Mar. 

30, 2009). The petition states, among other things, that “[h]ealth 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.

19Id. at 11.

20CAA § 112(d)(1), (d)(6), 42 U.S.C. §§ 7412(d)(1), (d)(6) (2012).

21Id. at § 7412(a)(1)-(2). 

22Id. at § 7412(d)(5).

NESHAPs Overview and 

Statutory Provisions 

Restricting Aggregation of 

Oil and Gas Production 

Sources
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 131 GAO-12-874 Unconventional Oil and Gas Development

combination of HAPs.23 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.24 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).25 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.26

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.27

EPA has defined “associated equipment” in the regulations.28 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.

 

23Id. at § 7412(a)(1), 76 FR 52,741 (Aug. 23, 2011).

2440 C.F.R. § 63.2 (2012) (defining major source); see also 64 Fed. Reg. 32,610, 32,613 

(June 17, 1999). 

25CAA § 112(n)(4)(a), 42 U.S.C. § 7412(n)(4)(a) (2012).

2640 C.F.R. § 63.760(d) (2012).

2764 Fed. Reg. at 32,619.

28Id.; 40 C.F.R. § 63.761 (defining “associated equipment”).
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 132 GAO-12-874 Unconventional Oil and Gas Development

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 2007.29

In April 2012, EPA promulgated amendments to the NESHAPs for major 

sources.30

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.31

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.

32 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.33

 

2964 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.

EPA documents do not indicate the extent to 

which these exemptions have the effect of cancelling MACT requirements 

that would otherwise apply to oil and gas wells from unconventional 

deposits.

3077 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. 

3140 C.F.R. §§ 63.760(a)(1), 63.761 (2012).

3277 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.

3364 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).

NESHAPs for Oil and 

Natural Gas Production 

Facilities

Major Sources
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 133 GAO-12-874 Unconventional Oil and Gas Development

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.34

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.35 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.36 The standards 

require that all process vents on new and existing large glycol 

dehydration units that are located at major HAPs sources be controlled.37

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.38

 

34In 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.

For existing and new storage vessels with 

the potential for flash emissions, the standard is to be equipped with a 

35Large 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)).

3664 Fed. Reg. 32,610, 32,613-14 (June 17, 1999).

3740 C.F.R. § 63.765 (2012).

3840 C.F.R. § 63.765 (2012), 64 Fed. Reg. 32,610, 32,613-14 (June 17, 1999).
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 134 GAO-12-874 Unconventional Oil and Gas Development

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.39

The April 2012 amendments added one more emission source to the 

NESHAP major source rule: small glycol dehydrators.

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.

40 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.41 Existing dehydrators have 3 years to comply, while 

new dehydrators must comply upon start-up.42

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.”43 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.

44 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.

45

 

3940 C.F.R. § 63.766 (2012).

EPA stated “[i]n response to 

such comments, we have re-evaluated the proposed MACT standards 

and concluded that we need (and intend to gather) additional data on 

4077 Fed. Reg. 49,490 ,49,568-71 (Aug. 16, 2012).

41Id. at 49,570-71.

42Id. at 49,568-60 (amending 40 C.F.R. 63.760(f)).

43Id. at 49,503; see also EPA, Summary of Requirements for Processes and Equipment 

at Natural Gas Well Sites.

4476 Fed. Reg. 52,738, 52,769 (Aug. 23, 2011).

4577 Fed. Reg. 49,490 , 49,503, 49,528-29 (Aug. 16, 2012).
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 135 GAO-12-874 Unconventional Oil and Gas Development

these sources in order to analyze and establish MACT emission 

standards for this subcategory of storage vessels.”46

In addition, the April 2012 amendments changed a key definition in the 

NESHAPs for determining major source status.47

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.

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.

48

In 2007, EPA issued a NESHAP for oil and gas production facilities—

which may include wells—that are area sources.49 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.50 For area sources within defined control areas (areas 

of higher population density),51

 

46Id. at 49,503.

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 

47Id. at 49,501, 49,569 (revising 40 C.F.R. § 63.761).

48CAA § 112(n)(4)(B), 42 U.S.C. § 7412(n)(4)(B) (2012).

4972 Fed. Reg. 26 (Jan. 3, 2007).

5040 C.F.R §§ 63.764(d), 63.765(a) (2012).

51EPA 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).

Area Sources
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 136 GAO-12-874 Unconventional Oil and Gas Development

limit for benzene.52 For area sources outside of these control areas, an 

operational standard is required instead of an add-on control.53

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.54 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.55

Regarding EPA’s authority to establish an area source category for oil 

and gas wells in metropolitan statistical areas, if certain conditions are 

met, officials said that EPA has not considered doing so. They said that 

they have not analyzed well emissions in relation to location in or outside 

a metropolitan statistical area, and that if the agency were to consider 

developing an area source within metropolitan statistical areas, they 

would need to conduct a new data collection effort.

In addition, EPA has promulgated other NESHAPs, the applicability of 

which to oil and gas well sites depends upon the particular equipment—

and factors such as capacity or emission rate—used at a well site. 

Although some published materials suggest several NESHAPs may 

apply, based on discussions with EPA, the primary NESHAP that officials 

believe could apply at oil and gas well sites is the Boilers and Process 

Heaters NESHAP for major sources.56

 

5272 Fed. Reg. 26, 28 (Jan. 3, 2007), 40 C.F.R §§ 63.764(d), 63.765(a) (2012).

5340 C.F.R § 63.764(d) (2012).

5440 C.F.R. § 63.775(c) (2012); see also 72 Fed. Reg. 26, 30 (Jan. 3, 2007).

55For 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.

5640 C.F.R. pt. 63 Subpt. DDDDD, §§ 63.7480-7575 (2012).

Other NESHAPs
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

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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).57 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.58

Where a gas well has a compressor, the compressor engine may be 

subject to standards for stationary engines.

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.

59 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. 

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.60

 

5740 C.F.R. § 63.7485, 76 Fed. Reg. 15,608, 15,619 (Mar. 21, 2011).

These rules are implemented by EPA 

5840 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.

5940 C.F.R. pt. 63, Subpt. ZZZZ (Stationary Reciprocating Internal Combustion Engines).

60CAA § 111(a)(2), (4), 42 U.S.C. § 7411(a)(2), (4). (2012).

New Source 

Performance 

Standards
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 138 GAO-12-874 Unconventional Oil and Gas Development

or by states through delegation.

61

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.

For the oil and gas production industry, 

the NSPS primarily regulates VOCs (as an ozone precursor).

62 EPA has recently 

promulgated such standards for some production emissions, notably 

completion and recompletion of certain hydraulically fractured gas wells.63

In addition, some other generally applicable standards for certain 

equipment may apply at oil and gas well sites.

In April 2012, EPA promulgated amendments to the NSPS for the Oil and 

Gas sector, including new standards applicable to the production source 

category.64 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.65 

Following publication of the new rules in August 2012, an industry group

petitioned EPA to reconsider certain aspects of the new rules.66

The new standards include, for the first time, standards to reduce 

emissions from certain activities at natural gas wells.67

 

61Id. at § 7411(c). 

In particular, the 

new standards establish operational standards applicable to selected 

6240 C.F.R. pt. 60, subparts KKK, LLL.

6377 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).

64Id. 

65See 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).

66American 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.

6777 Fed. Reg. 49,490, 49,497-98, 49,543 (Aug. 16, 2012) (adding, e.g., 40 C.F.R. § 

60.5365).

April 2012 Amendments to 

NSPS
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

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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.68 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 Completion date 

Green completions 

(routing gas to the 

flow line) 

Combustion of 

flowback emissions 

Duty to minimize 

releases to the air 

(flowback and 

recovery) 

Well logs, 

compliance 

demonstration, 

records and 

reporting 

Provisionsb 40 C.F.R. § 

60.5375(a)(1)-(2) 

 40 C.F.R. § 

60.5375(a)(3) 

40 C.F.R. § 

60.5375(a)(4) 

40 C.F.R. § 

60.5375(b)-(e) 

New wells 

constructed after 

Aug. 23, 2011 

Completions with 

hydraulic fracturing 

before Jan. 1, 2015 

√ √ √

 Completions with 

hydraulic fracturing 

after Jan. 1, 2015 

√ √ (only for emissions 

that cannot be directed 

to the flow line) 

√ √

Wells existing as of 

Aug. 23, 2011 

Completions with 

hydraulic fracturing 

before Jan. 1, 2015 

√ √ √ 

 Completions with 

hydraulic fracturing 

after Jan. 1, 2015 

√ √ (only for emissions 

that cannot be directed 

to the flow line) 

√ √

Alternative to avoid 

new source status 

before Jan. 1, 2015a

√ √ (only for emissions 

that cannot be directed 

to the flow line) 

√ √

 

68See 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). 
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 140 GAO-12-874 Unconventional Oil and Gas Development

Natural gas well 

subcategory Completion date

Green completions 

(routing gas to the 

flow line) 

Combustion of 

flowback emissions 

Duty to minimize 

releases to the air 

(flowback and 

recovery) 

Well logs, 

compliance 

demonstration, 

records and 

reporting 

Wildcat and 

delineation wells

√ √ √

Other low pressure 

wells

√ √ √

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. 

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.69

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.70 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.

71

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 

 

69For pneumatic controllers, an affected source is a single continuous bleed natural gasdriven 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).

70EPA, 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.

71EPA 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)).
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

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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.72

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).73

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.74

Other NSPS that have been identified as potentially relevant include 

those for gas turbines and steam generators.

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.

75 EPA officials said, 

however, that typical activity at well sites is not enough to trigger 

thresholds for coverage under this rule, either.

 

7277 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). 

7340 C.F.R. pt. 60, subpt. Kb (2012).

7440 C.F.R. § 60.110b(d)(3) (2012).

7540 C.F.R. pt. 60, subpt. D to Dc (2012). See also EPA, Sector Notebook Project: Oil and 

Gas Extraction, at 100 (2000).

Other NSPS
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 142 GAO-12-874 Unconventional Oil and Gas Development

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.

76 However, NSR only applies if the construction project 

results in actual emissions or the potential to emit regulated air 

contaminants77

The major NSR program is actually composed of the following two 

separate programs:

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.

• 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.

78 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.79

 

76CAA §§ 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).

While a 

77Potential 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.

78CAA §§ 169(1), 165(a), 42 U.S.C. §§ 7479(1), 7475(a) (2012).

7940 C.F.R. § 52.21(b)(5)-(6) (2012).

New Source Review
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

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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,80 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.81 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.82

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.83 With respect to nonattainment NSR, EPA officials stated 

that some large wells in nonattainment zones could be major sources 

standing alone because of low emission thresholds in certain areas; as 

noted above, such thresholds could be as low as 10 tons per year in the 

most severe nonattainment areas, versus 250 tons per year in attainment 

areas. 

Relevant to oil and gas production, CAA generally requires Title V permits 

for the operation of

• any major source84

• any source, including a nonmajor source, subject to a NSPS;

determined based on the facility’s actual 

emissions or “potential to emit;”

• any source, including an area source, subject to a NESHAP, among 

others; and

• any source required to obtain a PSD or NSR permit.85

 

80EPA, Report to Congress on Hydrogen Sulfide Emissions Associated with the Extraction 

of Oil and Gas, EPA-453-R-93/045 at IV-37 (1993).

81Gina McCarthy, AA Office of Air and Radiation, Memorandum, “Withdrawal of Source 

Determinations for Oil and Gas Industries” (Sept. 22, 2009).

8240 C.F.R. § 51.165 (2012).

8340 C.F.R. § 51.165 (2012).

84Major 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).

Title V Operating 

Permits 
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act

Page 144 GAO-12-874 Unconventional Oil and Gas Development

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,86 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.87 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.88

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.

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.

 

85CAA § 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). 

86EPA 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.

8740 C.F.R. §§ 70.3(c)(1), 71.3(c)(1) (2012). 

8840 C.F.R. §§ 70.3(c)(2) 71.3(c)(2) (2012). 
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 145 GAO-12-874 Unconventional Oil and Gas Development

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,89 and are located on 

contiguous or adjacent properties.90 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.91

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.92

Aggregation of emissions from the oil and gas industry generally, 

including production facilities, has received recent attention.

In addition, 

EPA Regions may be responsible for source determinations in areas where 

they are responsible for permitting. 

93

 

89All oil and gas emission units are in the same major industrial grouping.

For 

9040 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).

91See, 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).

92Gina McCarthy, AA Office of Air and Radiation, Memorandum, “Withdrawal of Source 

Determinations for Oil and Gas Industries” at 2 (Sept. 22, 2009).

93See, 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); http://www.natlawreview.com/article/oil-gas-activities-agencies-are-air-airregulations

Source 

Determinations and 

Aggregation Issues for 

Title V and NSR
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 146 GAO-12-874 Unconventional Oil and Gas Development

example, in 2007, EPA provided guidance on how to evaluate 

aggregation in source determinations for the oil and gas industry.94 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.95

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.

96 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 8.97 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.

98

 

94See Id.; William Wehrum, Memorandum, “Source Determinations for Oil and Gas 

Industries” (Jan. 12, 2007).

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 

95Gina McCarthy, AA Office of Air and Radiation, Memorandum, “Withdrawal of Source 

Determinations for Oil and Gas Industries” (Sept. 22, 2009).

96See Summit Petroleum Corp. v. EPA, Nos. 09-4348, 10-4572, slip op. (6th Cir. August 

7, 2012). 

97See 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).

98WildEarth Guardians et al. v. Jackson, No.11-9527 (10th Cir).
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

Page 147 GAO-12-874 Unconventional Oil and Gas Development

oil and gas activities with the compressor station in determining the 

source. A citizen group appealed this decision to the Environmental 

Appeals Board.99 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.100

In sum, several recent disputes over aggregation of oil and gas facilities 

involve whether or not well emissions should be aggregated; however, 

whether or not well emissions are aggregated for Title V or PSD purposes 

generally would not affect other federal requirements for emission 

controls at well sites.

In 2009, EPA promulgated the Greenhouse Gas Reporting Rule, 

providing a framework for the greenhouse gas reporting program and 

establishing requirements for some source categories.101 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.102

EPA subsequently issued and amended a rule to implement the program 

for the category of Petroleum and Natural Gas Systems, including oil and 

 

99In re BP America Production Co., Florida River Compression Facility, Environmental 

Appeals Board Appeal No. CAA 10–04.

100Wildearth Guardians v. EPA, Settlement Agreement at 2-3, Docket No. 11-9527 (10th

Circuit 2011). See also 76 Fed. Reg. 71,027 (Nov. 16, 2011).

10174 Fed. Reg. 56,260 (Oct. 30, 2009), 40 C.F.R. pt. 98. 

102See, 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). 

Greenhouse Gas 

Reporting Rule
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Authorities under the Clean Air Act 

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gas wells.103 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.104 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.105

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 

equivalent106

• equipment leaks and venting,

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

• gas flaring, and

• stationary and portable combustion.107

Reporting is to begin in September 2012, for calendar year 2011.108

 

10375 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 http://www.epa.gov/climatechange/emissions/subpart/w.html 

104EPA, Quantifying Greenhouse Gas Emissions from Key Industrial Sectors in the United 

States 12-2 (Working Draft May 2008).

105EPA, Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas 

Emissions Under Subpart W Supplemental Rule (GHG Reporting), Final Report 1-10 

(2009). 

106Carbon 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.

10740 C.F.R. § 98.232(c), (c)(12)-(13) (well flaring during testing and production), (c)(21) 

(leaks), (c)(22) (combustion) (2012).

10876 Fed. Reg. 73,886, 73,889, 73,899 (Nov. 29, 2011) (amending 40 C.F.R. § 98.3).
Appendix IV: Key Requirements and 

Authorities under the Clean Air Act 

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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-transportationrelated 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).109 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.110

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,111 and EPA documents estimate that emissions 

from approximately 467,000 onshore wells are covered under the rule.112

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 

 

10975 Fed. Reg. 74,458, 74,461 (Nov. 30, 2010), 40 C.F.R. § 98.230(a)(2) (2012).

11040 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.”).

11175 Fed. Reg. 74,458, 74,467 (Nov. 30, 2010).

11275 Fed. Reg. 74,458, 74,479 (Nov. 30, 2010).

Accidental Releases
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Authorities under the Clean Air Act 

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that pose the greatest risk of harm from accidental releases;113 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.114 Among others, hydrogen sulfide is included 

on the list of regulated substances.115 Section 112(r) also established the 

Chemical Safety Board;116 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.117

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.118

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.119

 

113CAA § 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.”).

As amended, the following chemicals that may 

be found at oil and gas sites are excluded from threshold determinations:

114Id. at § 7412(r)(3).

11540 C.F.R. § 68.130 (2012).

116CAA § 112(r)(6), 42 U.S.C. § 7412(r)(6), (6)(C) (2012).

117Id. at § 7412(r)(1).

11840 C.F.R. § 68.12 (2012).

11963 Fed. Reg. 640 (Jan. 6, 1998); 65 Fed. Reg. 13,243, 13,244 (Mar. 13, 2000).

Accidental Release 

Prevention (Risk 

Management Program)
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Authorities under the Clean Air Act 

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• 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),120

• regulated substances in gasoline, when in distribution or related 

storage for use as fuel for internal combustion engines,121

• a flammable substance when the substance is used as a fuel.

and

122

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.123 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.124

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 

 

12040 C.F.R § 68.115(b)(2)(iii), 68.3 (2012); 63 Fed. Reg. 640, 641 (Jan. 6, 1998).

12140 C.F.R § 68.115(b)(2)(ii) (2012); 63 Fed. Reg. 640, 641 (Jan. 6, 1998).

12240 C.F.R § 68.126 (2012).

12363 Fed. Reg. 640, 641 (Jan. 6, 1998).

12465 Fed. Reg. 13,243, 13,245 (Mar. 13, 2000).
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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.125 EPA then revised the regulation, adding the exemption to 

comply with the act.126

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.”127 If an oil or gas well site 

nonetheless uses or stores some of the regulated chemicals not 

encompassed by the exemptions, it could trigger the risk management 

requirements. 

Section 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.128

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, 

 

125Pub. 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.’’

12665 Fed. Reg. at 13,247.

12740 C.F.R. § 68.115(b)(2)(iii) (2012).

128CAA § 112(r)(1), 42 U.S.C. § 7412(r)(1) (2012).

General Duty to Prevent 

Accidental Releases
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Authorities under the Clean Air Act 

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and maintenance of a safe facility,” as well as release mitigation and 

community protection.129 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.130

The general duty clause applies to sources handling or storing 

substances listed by EPA in the Risk Management Program regulations 

or any other extremely hazardous substance, without a threshold. EPA 

headquarters officials said that, conceivably, the general duty clause 

would apply to every single well but stated that it would be in EPA 

Regions’ discretion where and when to use the general duty clause to 

conduct inspections. In some Regions, EPA has conducted inspections of 

gas well sites to enforce the general duty clause, including identifying 

noncompliance with certain safety standards. EPA Regional officials said 

that they use infrared video cameras to conduct inspections to identify 

leaks of methane from storage tanks or other equipment at well sites. For 

example, EPA Region 6 officials said they have conducted 45 inspections 

at well sites since July 2010 and issued 10 administrative orders related 

to violations of CAA general duty clause. EPA officials said that all well 

sites are required to comply with the general duty clause but that EPA 

prioritizes and selects sites for inspections based on risk.

Section 112(r) also provides EPA with the authority to issue orders as 

may be necessary to protect the public health when the EPA 

Administrator determines that there may be an imminent and substantial 

endangerment to human health or welfare or the environment because of 

an actual or threatened accidental release of a regulated substance.131

 

129EPA, Report to Congress on Hydrogen Sulfide Emissions Associated with the 

Extraction of Oil and Gas, EPA-453-R-93/045 at IV-35 (1993).

130See http://www.epa.gov/oem/publications.htm#alerts

131CAA § 112(r)(9)(A), 42 U.S.C. § 7412(r)(9)(A) (2012).

Imminent and Substantial 

Endangerment Authority 

Respecting Accidental 

Releases
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Authorities under the Clean Air Act 

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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 2010.132 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 

CWA133 and from the risk management requirements of CAA,134 the 

Chemical Safety Board recommended that EPA encourage owners and 

operators to reduce these risks.135 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.136

 

132U.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].

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 

133Note 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).

134Chemical Safety Board Report at 8. See 40 C.F.R. § 112.7(g) (2012).

135Chemical Safety Board Report at 52.

136See CAA § 112(r)(6)(I), 42 U.S.C. § 7412(r)(6)(I) (2012). See also 

http://www.csb.gov/recommendations/details.aspx?SID=95&pg=1&F_InvestigationId=95

Chemical Safety Board
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Authorities under the Clean Air Act 

Page 155 GAO-12-874 Unconventional Oil and Gas Development

by June 2013.137 The Chemical Safety Board also made related 

recommendations to several states and industry associations.138

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.139 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.

140

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.141 EPA must first consult with state and local authorities 

and attempt to confirm the accuracy of information before taking such 

actions.

 

137Regarding 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.

138Chemical Safety Board Report at 52-54.

139CAA § 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).

140CAA § 114(a), 42 U.S.C. § 7414(a) (2012).

141CAA § 303, 42 U.S.C. § 7603 (2012).

EPA Enforcement 

Authorities

Imminent and 

Substantial 

Endangerment 

Authority
Appendix V: Key Requirements and 

Authorities under the Resource Conservation 

and Recovery Act 

Page 156 GAO-12-874 Unconventional Oil and Gas Development

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,1 and 

also including some provisions respecting solid waste.2 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.3 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.4

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.5

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, 

 

1

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.

2

RCRA Subtitle D, 42 U.S.C. ch. 82, subch. IV (§§ 6941-6949a) (2012).

3

RCRA § 3006(b), 42 U.S.C. § 6926(b) (2012).

4

RCRA §§ 4006-09, 4004(a), 4005(a), 42 U.S.C. §§ 6946-49, 6944(a), 6945(a) (2012). 

5

RCRA § 1004(5), 42 U.S.C. § 6903(5) (2012).

Appendix V: Key Requirements and 

Authorities under the Resource Conservation 

and Recovery Act

Subtitle C – 

Hazardous Waste
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Authorities under the Resource Conservation 

and Recovery Act 

Page 157 GAO-12-874 Unconventional Oil and Gas Development

ignitability, corrosivity, or reactivity.6 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.7

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.8 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.”9 The study report was to “include appropriate 

findings and recommendations for Federal and non-Federal actions 

concerning such effects.”10

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:

[T]he Administrator shall, after public hearings and opportunity for comment, determine 

either to promulgate regulations under this subchapter for drilling fluids, produced 

waters, and other wastes associated with the exploration, development, or production 

of crude oil or natural gas or geothermal energy or that such regulations are 

unwarranted. The Administrator shall transmit his decision, along with any regulations, 

 

6

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).

7

See, e.g., RCRA §§ 3002, 3003, 3004, 42 U.S.C. §§ 6922, 6923, 6924 (2012).

8

Pub. L. No. 96-482 § 7, 94 Stat. 2334, 2336 (1980), 42 U.S.C. § 6921(b)(2) (2012).

9

Pub. L. No. 96-482 § 29(2), 94 Stat., 2350 (1980), amending RCRA § 8002(m), 42 

U.S.C. § 6982(m) (2012).

10Id.

Exemption of Certain Oil 

and Gas Production 

Wastes from Regulation as 

Hazardous Waste under 

RCRA Subtitle C
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Authorities under the Resource Conservation 

and Recovery Act 

Page 158 GAO-12-874 Unconventional Oil and Gas Development

if necessary, to both Houses of Congress. Such regulations shall take effect only when 

authorized by Act of Congress.11

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.12 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:13

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.14

 

1142 U.S.C. § 6921(b)(2)(B)-(C) (2012).

1253 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).

1353 Fed. Reg. at 25,450.

14Id. at 25,446.
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Authorities under the Resource Conservation 

and Recovery Act 

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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.15

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.16 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,”17 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.”18

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.19

 

15Id. at 25,447.

EPA’s work with states featured 

audits that ultimately led to the State Review of Oil and Natural Gas 

16Id.

17Id.

18Id. at 25,457.

19EPA, Exploration & Production Waste and RCRA, presented at ASTSWMO Annual 

Meeting (Oct. 26, 2011).
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Authorities under the Resource Conservation 

and Recovery Act 

Page 160 GAO-12-874 Unconventional Oil and Gas Development

Environmental Regulations (STRONGER) program.20

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.

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.

21

EPA officials told us the petition is currently under consideration and that 

the agency has not established a time frame for its decision.

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.

22 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.23

 

20The 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.

 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 

21Letter, 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).

22See 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.)

23EPA, Exploration & Production Waste and RCRA, presented at ASTSWMO Annual 

Meeting (Oct. 26, 2011).
Appendix V: Key Requirements and 

Authorities under the Resource Conservation 

and Recovery Act

Page 161 GAO-12-874 Unconventional Oil and Gas Development

issue, the agency intends to issue a proposed response to the petition. 

The proposed response will be printed in the Federal Register, and EPA 

will establish an electronic docket and provide an opportunity for public 

comment. Although EPA has not yet sought public comment on the 

petition, the agency has received several unsolicited comment letters, 

including from two industry associations, the STRONGER program, and 

two states.

If EPA revises the regulatory determination for some or all exploration 

and production wastes, the agency would conduct a full regulatory 

process to propose the regulations. Under the key RCRA provision, the 

regulations would not become effective until authorized by congressional 

action. Should the exemption be lifted, not all exploration and production 

wastes would necessarily be hazardous. Rather, whether particular 

exploration and production wastes would be hazardous and subject to 

regulation would depend on whether those particular wastes meet the 

regulatory definition of hazardous (i.e., are a listed waste or exhibit a 

characteristic of hazardous waste).

While well sites wastes originating within the well or generated by field 

operations such as water separation, demulsifying, degassing, and 

storage are exempt, RCRA Subtitle C regulations generally apply to other 

wastes that may be generated at oil and gas wells, such as discarded 

unused products, solvents used to clean surface machinery, and others, if 

they are actually hazardous. In 2002, EPA published a guide titled 

“Exemption of Oil and Gas Exploration and Production Wastes from 

Federal Hazardous Waste Regulations” that identifies, among other 

things, a list of nonexempt wastes. The guide identified nonexempt 

wastes including the following wastes that may be generated by activities 

at oil and gas well sites:

• unused fracturing fluids or acids;

• 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;

Oil and Gas Exploration 

and Production Wastes 

That Are Not Exempt from 

Regulation
Appendix V: Key Requirements and 

Authorities under the Resource Conservation 

and Recovery Act 

Page 162 GAO-12-874 Unconventional Oil and Gas Development

• 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.24 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.25 These facilities are subject to 

limits on the amount of hazardous waste they accumulate,26

 

2440 C.F.R. § 261.5, pt. 262 (2012).

as well as 

25Id. at § 261.5(a). 

26Id. at (g)(2).
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general requirements to determine which wastes are hazardous27 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.28 Generally, conditionally exempt small quantity 

generators would not be required to have an EPA ID number.29 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,30 and general requirements to determine which wastes are 

hazardous31 and to ensure that any hazardous wastes sent for off-site 

disposal are sent to RCRA-permitted or interim status facilities.32 In 

addition, the small quantity generators are required to have an EPA ID 

number and use manifests, by which hazardous waste may be tracked.33

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.34

 

27Id. at § 262.11.

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 

28Id. 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).

29Id. at §§ 261.5(b), 262.12.

30Id. at § 261.34.

31Id. at § 262.11.

32Id. 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).

33Id. at §§ 262.12, 262.20.

34Id. 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.).
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and inspection purposes.35 Generally, EPA (or the authorized state’s) 

involvement at generator-only sites includes receiving notifications and 

issuing identification numbers, receiving biennial reports,36

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,

conducting 

compliance assurance activities such as inspections, and investigating 

alleged problems.

37

 

35See EPA Form 8700-12.

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 

36Biennial 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).

37NAICS 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.
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Authorities under the Resource Conservation 

and Recovery Act 

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some may include downstream facilities, while others appear to be well 

sites.38

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.39

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.40 A 

key part of EPA’s limited regulatory role41 for solid waste was to establish 

criteria defining which solid waste disposal facilities and practices are 

“sanitary landfills” and those which constitute “open dumps,”42 where 

RCRA prohibited open dumping of solid waste.43

 

38EPA officials from one Region believed some well sites may be small quantity 

generators of hazardous waste.

39See, e.g., RCRA §§ 1003(a)(1)-(3), 4001, 42 U.S.C. §§ 6902(a)(1)-(3), 6941 (2012).

40See, 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).

41In 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).

42RCRA §§ 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.”). 

43RCRA § 4005(a), 42 U.S.C. §§ 6945(a) (2012).

Subtitle D – Solid 

Waste
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Consistent with the scheme established by RCRA Subtitle D, states have 

primary responsibility for managing disposal of solid waste, including that 

resulting from oil and gas exploration and production. State solid waste 

programs regulate treatment (which may include incineration) and land 

disposal of these wastes, among other things. In addition, states may 

have specific programs to address oil and gas production wastes, and 

some states put such wastes in a special category of solid waste, such as 

industrial wastes, with more stringent requirements than the federal 

minimum requirements. (See report and app. IX for discussion of selected 

aspects of state waste management.)

EPA has certain enforcement authorities to address hazardous wastes. 

RCRA sections 3007, 3008, and 3013 collectively provide EPA with 

authorities to monitor compliance, conduct investigations, and enforce 

Subtitle C (the hazardous waste subtitle) and its implementing 

regulations.44 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).45

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.

46,47

 

44RCRA §§ 3007, 3008, 3013, 42 U.S.C. §§ 6927, 6928, 6934 (2012). 

These orders may require the person 

to come into compliance immediately or by a specific time frame and/or 

45Cf. RCRA § 1004(5), 42 U.S.C. § 6903(5) (2012) with 40 C.F.R. §§ 261.3,-4 (2012).

46RCRA § 3008, 42 U.S.C. § 6928 (2012).

47EPA 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 generatoronly 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).

Enforcement
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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.48 Section 3007 also 

establishes mandatory compliance inspections.49 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.”50

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.

EPA officials did not provide any examples of EPA using its section 3007 

authority at oil or gas well sites.

51 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.52

 

48RCRA § 3007(a), 42 U.S.C. § 6927(a) (2012). 

49Id. at § 6927(e) (2012).

50See, 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.)”).

51RCRA § 3013(a), 42 U.S.C. § 6934(a) (2012).

52Id. at § 6934(d) (2012).
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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.53

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.

54 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.55

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.56

 

53RCRA § 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. 

54RCRA § 7003, 42 U.S.C. § 6973 (2012).

55Id. at § 6973(a).

56Id. at § 6973(b).

Imminent and 

Substantial 

Endangerment 

Authority
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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.57 EPA has interpreted the authority 

broadly, to allow a range of actions to be taken, including addressing the 

threat of endangerment.58

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.

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.

59 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.60 According to the report, the orders required operators “to 

remove oil from pits, install effective exclusionary devices, and/or clean 

up sites.”61

 

57RCRA § 1004(5), (27), 42 U.S.C. § 6903(5), (27) (2012).

EPA Region 8 has issued section 7003 orders to several 

commercial oilfield waste disposal facility operators in Wyoming, finding 

58See EPA. Office of Enforcement and Compliance Assurance, Guidance on the Use of 

Section 7003 of RCRA (October 1997).

59EPA Region 8, Oil and Gas Environmental Assessment Effort 1996 – 2002, at v (2003).

60Id. at 8. 

61Id.
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each site endangered the environment including having caused bird 

mortalities due to inadequate pit management.62

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.63

 

62In 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-cv00087 (Wy. Nov. 3, 2010). 

63West Bay Exploration, Agreement and Remediation Plan, EPA Docket No. RCRA-06-

2005-0913 (Sept. 14, 2005).
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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.1 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,2 as well as requiring reporting of hazardous 

substances releases above threshold quantities.3 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.4 CERCLA is primarily a 

remedial statute; it is preventive in that it authorizes responses to 

threatened releases of hazardous substances, pollutants, and 

contaminants, and to the extent that the liability scheme provides 

incentives for owners and operators to take care to avoid releases to the 

environment.

Under a provision known as the petroleum exclusion, CERCLA’s 

provisions do not apply to releases to the environment that are purely 

petroleum, including crude oil and natural gas, and fractions of crude oil 

including the hazardous substances, such as benzene, that are 

 

1

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.

2

CERCLA § 104, 42 U.S.C. § 9604 (2012).

3

CERCLA § 103(a), 42 U.S.C. § 9603(a) (2012).

4

Parties may also be held liable under CERCLA for damages related to the loss, injury or 

destruction of natural resources.

Appendix VI: Key Requirements and Authorities 

under the Comprehensive Environmental 

Response, Compensation, and Liability Act 

Relevant Exclusions and 

Definitions
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indigenous in those petroleum substances.5 EPA can respond to releases 

of hazardous substances, however, even if there are colocated petroleum 

releases.6

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.7

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.

The statutory definition for such federally permitted 

releases exempt from CERCLA liability and reporting also includes:

8

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.9

 

5

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 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). 

6

See 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).

7

CERCLA § 101(10), 42 U.S.C. § 9601(10) (2012). See also exclusions at id. § 9601(22) 

(2012).

8

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).

9

53 Fed. Reg. at 27,275.
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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.10 EPA regulations 

establish CERCLA hazardous substances and their reportable 

quantities.11 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.12

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.

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.

 

10CERCLA § 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.

1140 C.F.R. pt. 302, § 302.4 at table 302.4 (2012).

12See 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).

CERCLA Hazardous 

Substance Release 

Reporting
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EPA established the Superfund program to carry out its responsibilities 

and authorities under CERCLA.13 Under the Superfund program, EPA 

implements its authorities to compel parties responsible14

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.

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.

15 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.16

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 

 

13Through 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. 

14Under CERCLA, potentially responsible parties generally include current or former 

owners and operators of a site or the generators or transporters of the hazardous 

substances.

1540 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). 

16EPA, Memorandum, “Use of Non-Time Critical Removal Authority in Superfund 

Response Actions” (2000).

Relevant EPA Authorities
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release has occurred or is about to occur.17 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.18

• 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.19 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.20 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.21 EPA may obtain 

access by agreement, warrant, or administrative order.22 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.23

• 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 

 

17CERCLA § 104(a)(1), (b), 42 U.S.C. § 9604(a)(1), (b) (2012).

18Id. 

19Id. at § 9604(e).

20Id. at § 9604(e)(1)-(2). 

21Id. at § 9604(e)(3)-(4). 

22Id. at § 9604(e)(4)-(5). 

23Id. at § 9604(e)(5).
Appendix VI: Key Requirements and 

Authorities under the Comprehensive 

Environmental Response, Compensation, and 

Liability Act

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conduct removal actions, among other things.24 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.25

• 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;

26 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.27

• 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.

28

 

24Id. 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.

EPA also can issue an administrative 

order requiring a potentially responsible party to take response 

25CERCLA § 101(23), 42 U.S.C. § 9601(23) (2012).

26See id. at § 9601(33) . EPA cannot, however, recover its response costs associated with 

these releases.

27EPA 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.

28CERCLA § 106(a), 42 U.S.C. § 9606(a) (2012).
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Environmental Response, Compensation, and 

Liability Act

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actions as may be necessary to protect public health and welfare and 

the environment.29 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.30

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.31 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.32

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.33

 

29Id. at § 9606(a).

EPA is using CERCLA section 104(b) authority to conduct groundwater 

30See, e.g., CERCLA §§ 107, 122, 42 U.S.C. §§ 9607, 9622 (2012).

31See DOJ, news release (Sept. 23, 1999). 

32See 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). 

33See 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.
Appendix VI: Key Requirements and 

Authorities under the Comprehensive 

Environmental Response, Compensation, and 

Liability Act

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contamination investigations at Pavillion, Wyoming.34

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.

EPA officials also 

referenced CERCLA section 104(e) authority in requesting information

from operators of wells proximate to the Pavillion site.

35

 

34See EPA, Draft Report, Investigation of Ground Water Contamination near Pavillion, 

Wyoming, EPA 600/R-00/000 (December 2011) at xi, 1.

35Agency for Toxic Substances and Disease Registry, Health Consultation, Chesapeake 

ATGAS 2H Well Site, Leroy Hill Road, Leroy Township, Bradford County, PA (2011).
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 179 GAO-12-874 Unconventional Oil and Gas Development

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.1

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.2 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.3 The releases for 

which EPCRA requires reporting partially overlap with those for which the 

Comprehensive Environmental Response, Compensation, and Liability 

Act of 1980 (CERCLA)4 requires reporting.5

 

1

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.

Where there is overlap, 

EPCRA’s procedures ensure state and local authorities receive this 

2

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). 

3 EPCRA § 304(a), 42 U.S.C. §§ 11004(a) (2012). See also EPA, List of Lists (2011) 

available at 

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).

4

Pub. L. No. 96–510, 94 Stat. 2767 (1980) (codified at 42 U.S.C. ch. 103 (2012)).

5

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.

Appendix VII: Key Requirements and 

Authorities under the Emergency Planning 

and Community Right-to-Know Act

Generally Applicable 

Chemical Information, 

Inventory, and Release 

Reporting
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 180 GAO-12-874 Unconventional Oil and Gas Development

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.6 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.7

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.8 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.9

 

6

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).

For example, if the 

7

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). 

8

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.

9

40 C.F.R. § 370.10(a)(2)(i) (2012).

Requirements under 

EPCRA That May Be 

Triggered at Well Sites
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 181 GAO-12-874 Unconventional Oil and Gas Development

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 

FracFocus10 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.”11

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.12

 

10FracFocus 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.

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 

11Cf. http://fracfocus.org/chemical-use/what-chemicals-are-used and 40 C.F.R. § 302.4 

(2012).

12EPCRA 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.
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 182 GAO-12-874 Unconventional Oil and Gas Development

be present at the particular well site in quantities that would trigger 

section 311 and 312 requirements.13

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. 

EPCRA also requires some facilities in listed industries to report to EPA 

their releases of listed toxic chemicals to the environment;14

 

13EPA 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. 

at present, 

these requirements do not apply to oil and gas well operations.

Toxic Release Inventory
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 183 GAO-12-874 Unconventional Oil and Gas Development

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.15

EPCRA further requires EPA to make this information available to the 

public,16 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.17 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.18

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;19

 

14The 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).

(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 

15EPCRA § 313(g)(1)(C), 42 U.S.C. § 11023(g)(1)(C) (2012).

16Id. at (i).

17Pollution Prevention Act, § 6607, 42 U.S.C. § 13106 (2012).

18EPCRA § 313(h), 42 U.S.C. § 11023(h) (2012).

19Full-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).
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

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American Industry Classification System (NAICS) codes, and 

subsequently to update as needed to reflect changes to the NAICS 

codes.20

EPCRA section 313(b)(1)(B) provides EPA with authority to add or delete 

industrial codes.21 EPA issued initial regulations to implement the TRI in 

1988.22 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.23

EPA has since expanded the list of covered industries, but it has not 

included oil and gas extraction.

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.

24 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.25 In 1997, pursuant to 

section 313(b)(1)(B), EPA added seven industry groups26

 

20Community Right-to-Know; Toxic Chemical Release Reporting Using NAICS, 71 Fed. 

Reg. 32,464, 32,465 (June 6, 2006); see generally 

to the list of 

industries required to report releases in a rulemaking known as the Industry 

http://www.epa.gov/tri/lawsandregs/naic/ncodes.htm 

21EPCRA § 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). 

2253 Fed. Reg. 4500 (Feb. 16, 1988). 

23Id. 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.”).

24See KWWSZZZHSDJRYWULODZVDQGUHJVQDLFQFRGHVKWP

25EPA Office of Compliance, Sector Notebook Project: Profile of the Oil and Gas 

Extraction Industry 114 (October 2000).

26These 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.
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 185 GAO-12-874 Unconventional Oil and Gas Development

Expansion Rule.27

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.

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:

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.28

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.”29

 

27Addition 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).

2861 Fed. Reg. 33,588, 33,592 (June 27,1996).

2962 Fed. Reg. 23,834, 23,855 (1997).
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 186 GAO-12-874 Unconventional Oil and Gas Development

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.30 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.31

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.

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.

32 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.”33

 

30

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, 

http://exchange.regulations.gov/exchange/topic/trisectorsrule/agencyintro/tri-exchange

31In 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. 

32See, 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).

3361 Fed. Reg. 33,588, 33,592 (June 27,1996).
Appendix VII: Key Requirements and 

Authorities under the Emergency Planning and 

Community Right-to-Know Act

Page 187 GAO-12-874 Unconventional Oil and Gas Development

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.34 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 2012.35

EPCRA provides EPA with various authorities to enforce the act’s 

requirements.36 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.37 In cases of violations of 

section 304 release reporting requirements, EPA may assess 

administrative penalties, among other things.38

 

3476 Fed. Reg. 64,022 (Oct. 17, 2011).

35Id. at 64,025.

36EPCRA § 325, 42 U.S.C. § 11046 (2012). 

37Id. at § 11046(c)(1), (2), (4).

38 Id. at § 11046( b).

Enforcement
Appendix VIII: Key Requirements and 

Authorities under the Toxic Substances 

Control Act

Page 188 GAO-12-874 Unconventional Oil and Gas Development

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.1 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.2 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 1979.3 Generally, TSCA’s reporting requirements 

fall on the manufacturers (including importers), processors, and 

distributors of chemicals, rather than users of the chemicals.4

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 

 

1

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.

2

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).

3

See 

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, GAO-09-428T (Feb. 26, 2009).

4

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).

Appendix VIII: Key Requirements and 

Authorities under the Toxic Substances 

Control Act
Appendix VIII: Key Requirements and 

Authorities under the Toxic Substances 

Control Act

Page 189 GAO-12-874 Unconventional Oil and Gas Development

chemicals on the FracFocus5 list of “chemicals used most often” which 

are on the TSCA inventory.6

• Hydrochloric acid – Acid; 

These examples, which EPA chose as 

representative of different product function categories, are as follows:

• 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.

 

5

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. http://www.fracfocus.org

6

See http://www.epa.gov/oppt/existingchemicals/pubs/tscainventory, 

http://fracfocus.org/chemical-use/what-chemicals-are-used. 
Appendix VIII: Key Requirements and 

Authorities under the Toxic Substances 

Control Act

Page 190 GAO-12-874 Unconventional Oil and Gas Development

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.7 The petition asserts that more than 10,000 gallons of such 

chemicals may be used to fracture a single well.8 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.9

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.10 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.11

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 

 

 

7

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 

http://www.epa.gov/oppt/chemtest/pubs/petitions.html#petition10

8

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.

9

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.

10Earthjustice 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.

11Stephen 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. 
Appendix VIII: Key Requirements and 

Authorities under the Toxic Substances 

Control Act

Page 191 GAO-12-874 Unconventional Oil and Gas Development

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.12 Regulations promulgated under TSCA section 8(d) are to

require submission to EPA of reasonably ascertainable health and safety 

studies.13

TSCA provides EPA with certain enforcement authorities. For example, 

EPA may impose a civil penalty for certain violations of TSCA,14 such as 

failing to comply with requirements to notify and provide certain 

information to EPA before manufacturing a new chemical,15 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.16

 

12TSCA § 8(a)(1)-(2), 15 U.S.C. § 2607(a)(1)-(2) (2012).

13TSCA § 8(d), 15 U.S.C. § 2607(d) (2012).

14TSCA §§ 16(a)(1), 15, 15 U.S.C. §§ 2615(a)(1), 2614 (2012).

15TSCA § 5(a)(1), 15 U.S.C. § 2604(a)(1) (2012). See also 40 C.F.R. pt. 720 (2012).

16TSCA § 15(2), 15 U.S.C. § 2614(2) (2012).
Appendix IX: Selected State Requirements

Page 192 GAO-12-874 Unconventional Oil and Gas Development

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 State regulatory agencies

Colorado Colorado Oil and Gas Conservation Commission

Colorado Department of Public Health and Environment

North Dakota North Dakota Industrial Commission, Oil and Gas Division

North Dakota Department of Health 

Ohio Ohio Department of Natural Resources, Division of Oil and Gas 

Resource Management

Ohio Environmental Protection Agency

Pennsylvania Pennsylvania Department of Environmental Protection, Office of Oil 

and Gas Management

Texas Texas Railroad Commission, Oil and Gas Division

Texas Commission on Environmental Quality

Wyoming Wyoming Oil and Gas Conservation Commission

Wyoming Department of Environmental Quality

Source: GAO analysis of state information.

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); 

Appendix IX: Selected State Requirements
Appendix IX: Selected State Requirements 

Page 193 GAO-12-874 Unconventional Oil and Gas Development

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.1,2,3

Table 12: Selected State Requirements—Siting and Site Preparation

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

CO Testing requirements apply in certain circumstances. Specifically:

• Coalbed methane wells. If a conventional or plugged well exists within 1⁄4 mile of a proposed coalbed methane well, the 

two closest water wells within a 1⁄2 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 1⁄4 mile, or if access is denied to such wells, then a 

water well within 1⁄4 mile, or, failing that, within 1⁄2 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). 

 

1

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.

2

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.

3

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.
Appendix IX: Selected State Requirements 

Page 194 GAO-12-874 Unconventional Oil and Gas Development

ND 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).

OH 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).

PA 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).

TX No requirements identified in regulations or in statutes.

WY An application for a permit to drill or deepen a well must identify all water supply wells permitted by the state within 1⁄4 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

CO 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).

ND 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). 

OH 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). 

PA 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).

TX No requirements identified in regulations or in statutes.

WY 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).

 

 

 

 

 

 
Appendix IX: Selected State Requirements 

Page 195 GAO-12-874 Unconventional Oil and Gas Development

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

CO • 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).

ND • 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.

OH • 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).

PA Operators proposing activities that will disturb 5,000 square feet or more or that have the potential to discharge to a highquality 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).
Appendix IX: Selected State Requirements 

Page 196 GAO-12-874 Unconventional Oil and Gas Development

TX • 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). 

WY • 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 

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. 

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

Requirements relating to cementing/casing plans

CO The casinga 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). 

ND The proposed casing program, including size and weight of casing, the depth at which each casing stringb 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). 

OHc 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). 

PA 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 
Appendix IX: Selected State Requirements 

Page 197 GAO-12-874 Unconventional Oil and Gas Development

materials required by DEP as a condition of well permit. 25 Pa. Code § 78.83a (2012). 

TX 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). 

WY 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

CO Where pressure and formations are unknown, surface casingd 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).

ND 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).

OH 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 useable 

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).

PA 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).

TX 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). 

WY 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). 
Appendix IX: Selected State Requirements 

Page 198 GAO-12-874 Unconventional Oil and Gas Development

Prescribed cementation techniques for surface casing

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

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

OH 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).

PA 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).

TX 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). 

WY 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

CO 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). 

ND 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 shoee after the horizontal 

section has been drilled. N.D. Admin. Code 43-02-03-21 (2012). 

OH 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).
Appendix IX: Selected State Requirements 

Page 199 GAO-12-874 Unconventional Oil and Gas Development

PA 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). 

TX 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). 

WY 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

CO 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). 

ND 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). 

OH 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). 

PA 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).
Appendix IX: Selected State Requirements 

Page 200 GAO-12-874 Unconventional Oil and Gas Development

TX 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). 

WY 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

CO If an operator intends to drill a horizontal or deviated wellbore utilizing controlled directional drilling methods, other than 

whipstockingg 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). 

ND 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). 

OH 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). 

PA No requirements identified in regulations or in statutes.h

TX 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

WY 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). 
Appendix IX: Selected State Requirements 

Page 201 GAO-12-874 Unconventional Oil and Gas Development

Blowout preventer requirements

CO 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). 

ND 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). 

OH 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). 

PA 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). 

TX 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). 

WY 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, fieldspecific, 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. 
Appendix IX: Selected State Requirements 

Page 202 GAO-12-874 Unconventional Oil and Gas Development

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). 

Table 14: Selected State Requirements—Hydraulic Fracturing

Prior authorization/notice/inspection requirements

CO 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). 

ND No requirements identified in regulations or in statutes.

OH 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).

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

TX No requirements identified in regulations or in statutes.

WY 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

CO 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 

acknowledgement 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 
Appendix IX: Selected State Requirements 

Page 203 GAO-12-874 Unconventional Oil and Gas Development

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). 

ND 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). 

OH 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).

PA 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 
Appendix IX: Selected State Requirements

Page 204 GAO-12-874 Unconventional Oil and Gas Development

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). 

TX 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). 

WY • 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).
Appendix IX: Selected State Requirements 

Page 205 GAO-12-874 Unconventional Oil and Gas Development

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

CO During stimulation, bradenheade 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). 

ND • 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). 

 
Appendix IX: Selected State Requirements 

Page 206 GAO-12-874 Unconventional Oil and Gas Development

OH 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).

PA No requirements identified in regulations or in statutes.

TX No requirements identified in regulations or in statutes.

WY 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 

CO 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). 

ND No additional requirements identified in regulations or in statutes. 

OH • 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 
Appendix IX: Selected State Requirements 

Page 207 GAO-12-874 Unconventional Oil and Gas Development

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).

PA 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).

TX No additional requirements identified.

WY 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. 
Appendix IX: Selected State Requirements 

Page 208 GAO-12-874 Unconventional Oil and Gas Development

Table 15: Selected State Requirements—Well Plugging

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

CO 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).

ND 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). 

OH 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).

PA 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).

TX 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).
Appendix IX: Selected State Requirements 

Page 209 GAO-12-874 Unconventional Oil and Gas Development

WY 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.

Table 16: Selected State Requirements—Site Reclamation

Backfilling, regrading, recontouring, and compaction alleviation requirements

CO 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). 

ND 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). 

OH 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). 

PA 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. 
Appendix IX: Selected State Requirements 

Page 210 GAO-12-874 Unconventional Oil and Gas Development

TX 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). 

WY 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

CO 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). 

ND 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).

OH 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). 

PA 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). 

TX No requirements identified in regulations or in statutes.a

WY 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. 
Appendix IX: Selected State Requirements 

Page 211 GAO-12-874 Unconventional Oil and Gas Development

Table 17: Selected State Requirements—Waste Management in Pits

Pit siting requirements (with regard to sensitive areas)

CO 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).

ND 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).

OH 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).

PA 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).

TX No commercial oil and gas waste disposal pits may be constructed in any coastal natural resource areab 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

WY 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 1⁄4 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

CO 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).
Appendix IX: Selected State Requirements 

Page 212 GAO-12-874 Unconventional Oil and Gas Development

ND 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). 

OH 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).

PA 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). 

TX 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). 

WY 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). 

Freeboardd and secondary containment requirements for pits and tanks

CO • 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 
Appendix IX: Selected State Requirements 

Page 213 GAO-12-874 Unconventional Oil and Gas Development

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).

ND 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).

OH 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).

PA • 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 rulese 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).

TX 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).

WY Operators are reminded to comply with federal regulationsfthat 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 

CO 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 
Appendix IX: Selected State Requirements 

Page 214 GAO-12-874 Unconventional Oil and Gas Development

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). 

ND 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). 

OH 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). 

PA 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). 

TX 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).

 

 

 

 
Appendix IX: Selected State Requirements 

Page 215 GAO-12-874 Unconventional Oil and Gas Development

WY 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. 
Appendix IX: Selected State Requirements 

Page 216 GAO-12-874 Unconventional Oil and Gas Development

Table 18: Selected State Requirements—Waste Management through Underground Injectiona

Requirements regarding existing wells

CO 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).

ND 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).

OH 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 (1⁄4 mile to 1⁄2 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

PAc 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 (‘‘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). 

TX 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). 

WY 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

CO 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).

ND 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).
Appendix IX: Selected State Requirements 

Page 217 GAO-12-874 Unconventional Oil and Gas Development

OH 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). 

PA Wells shall be cased and cemented to prevent movement of fluids into or between protected aquifers.iSurface 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).

TX 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).

WY 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

CO 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).

ND 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).

OH 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). 

PA 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). 

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

WY Regulations do not specify limit or formula.j

Monitoring/reporting requirements

CO 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).

 

 
Appendix IX: Selected State Requirements 

Page 218 GAO-12-874 Unconventional Oil and Gas Development

ND 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).

OH 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

PA 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). 

TX 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).

WY 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

CO 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).

ND 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).

OH 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

PA 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).

TX 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).
Appendix IX: Selected State Requirements 

Page 219 GAO-12-874 Unconventional Oil and Gas Development

WY 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

CO 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).

ND 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).

OH 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). 

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

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

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

Plugging

CO 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). 

ND 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).

OH 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). 

 
Appendix IX: Selected State Requirements 

Page 220 GAO-12-874 Unconventional Oil and Gas Development

PA 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).

TX 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).

WY 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

CO 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

ND 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).

OH None identified.b

PA 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 1⁄4 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).

TX None identified.

WY None identified.

Source: GAO analysis of state information.
Appendix IX: Selected State Requirements

Page 221 GAO-12-874 Unconventional Oil and Gas Development

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). 

fAccording 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). 
Appendix IX: Selected State Requirements 

Page 222 GAO-12-874 Unconventional Oil and Gas Development

Table 19: Selected State Requirements—Managing Air Emissions

Requirements related to hydrogen sulfide gas (H2S) 

CO 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). 

ND 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). 

OH 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). 

PA 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). 

TX 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).

WY 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). 
Appendix IX: Selected State Requirements 

Page 223 GAO-12-874 Unconventional Oil and Gas Development

Requirements related to venting and flaring

CO 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). 

ND 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). 

OH 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). 

PA 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). 

TX 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 
Appendix IX: Selected State Requirements 

Page 224 GAO-12-874 Unconventional Oil and Gas Development

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).

WY 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.
Appendix X: Crosswalk between Selected 

Requirements from EPA, States, and Federal 

Lands

Page 225 GAO-12-874 Unconventional Oil and Gas Development

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

Area of regulation

EPA environmental and 

public health requirements

Requirements of six states

reviewed

Additional requirements for 

federal minerals

Siting and site preparation

Comprehensive environmental 

assessment prior to drilling

Noa b Yes

Identification or testing of water wells 

prior to drilling of production wells 

No 1 of 6 (Wyoming) 

[identification alone]

2 of 6 (Colorado, Ohio) 

[identification and testing]c

Yes – identification

No – testing

Required setbacks from water sources Nod 5 of 6 (Colorado, North 

Dakota, Pennsylvania, Ohio, 

Wyoming)

Yes

Erosion control, site preparation, surface 

disturbance minimization, and 

stormwater management

Effectively noe 6 of 6 [any]

4 of 6 (Colorado, North 

Dakota, Pennsylvania, 

Wyoming) [stormwater 

permitting]f

Yes

Drilling, casing, and cementing

Requirements relating to 

cementing/casing plans

Nog 6 of 6h Yes

Prescribed placement of surface casing 

relative to groundwater zones

Nog 6 of 6 Yes

Prescribed cementation techniques for 

surface casing

Nog 6 of 6 No; instead the Bureau of 

Land Management (BLM) 

has performance standards

Requirement for cement waiting period 

and/or integrity tests

Nog 6 of 6 Yes

Blowout preventerirequirements Nog 5 of 6j(Colorado, North 

Dakota, Pennsylvania, 

Texas, Wyoming)

Yes

Hydraulic fracturing

Prior authorization/notice/inspection 

requirements

No 4 of 6 (Colorado, Ohio, 

Pennsylvania, Wyoming)

Not currently, but in BLM 

proposed rule

Requirements to disclose information on 

fracturing fluids

Nok 6 of 6 Not currently, but in BLM 

proposed rule

Appendix X: Crosswalk between Selected 

Requirements from EPA, States, and Federal 

Lands 
Appendix X: Crosswalk between Selected 

Requirements from EPA, States, and Federal 

Lands

Page 226 GAO-12-874 Unconventional Oil and Gas Development

Area of regulation

EPA environmental and 

public health requirements

Requirements of six states

reviewed

Additional requirements for 

federal minerals

Pressure monitoring, testing, limitations 

or other mechanical integrity 

requirements specific to hydraulic 

fracturing

No 4 of 6 (Colorado, North 

Dakota, Ohio, Wyoming)

Not currently, but in BLM 

proposed rule

Well plugging

Requirements for notification, plugging 

plan or method, witnessing, and 

reporting

Nol 6 of 6 Yes

Programs to plug wells that are not 

properly plugged and have been 

abandoned

No 6 of 6 Yesm

Site reclamation

Requirements for backfilling, regrading, 

recontouring, and alleviating compaction 

of soil

No 6 of 6 Yes

Revegetation requirements No 5 of 6 (Colorado, North 

Dakota, Ohio, Pennsylvania, 

Wyoming)

Yes

Waste management

Options for waste disposal:

Underground injection Yes (Safe Drinking Water 

Act) 

5 states have their own 

requirements (Colorado, 

North Dakota, Ohio, Texas, 

Wyoming); EPA implements 

the program in Pennsylvania

In the permit application, 

operators must describe the 

final disposal of waste 

materials. 

Direct discharge to surface water Yes (Clean Water Act—

certain discharges prohibited, 

others subject to conditions 

and permits) 

Surface discharges are 

allowed in certain cases in 3 

western states (Colorado, 

Texas, Wyoming)

In the permit application, 

operators must describe the 

final disposal of waste 

materials.

Requirements for discharge to 

publicly-owned treatment works 

(POTWs) or Centralized Waste 

Treatment Facilities (CWT)

Pretreatment standards for 

shale gas wastewater under 

development (Clean Water 

Act) 

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)

In the permit application, 

operators must describe the 

final disposal of waste 

materials.

Recycling or other reuse Yes (Clean Water Act—

certain produced water 

discharges) 

6 of 6 states allow recycling 

or other reuseo

 

In the permit application, 

operators must describe the 

final disposal of waste 

materials.

Solid waste disposal Effectively nop Yes In the permit application, 

operators must describe the 

final disposal of waste 

materials.
Appendix X: Crosswalk between Selected 

Requirements from EPA, States, and Federal 

Lands

Page 227 GAO-12-874 Unconventional Oil and Gas Development

Area of regulation

EPA environmental and 

public health requirements

Requirements of six states

reviewed

Additional requirements for 

federal minerals

Hazardous waste disposal Effectively noq No In the permit application, 

operators must describe the 

final disposal of waste 

materials.

Pit siting requirements (with regard to 

sensitive areas)

Nor 6 of 6 No specific requirements but 

pits must be approved

Pit lining requirements No 5 of 6s (Colorado, North 

Dakota, Pennsylvania, 

Texas, Wyoming)

Not currently, but BLM 

proposed rule would require 

liners for pits used to store 

hydraulic fracturing flowback 

fluids.

Pit closure requirements No 6 of 6 Yes

Managing air emissions

Requirements for criteria pollutants Certain Clean Air Act 

provisions apply

5 of 6 states have permitting 

or registration programs 

(Colorado, North Dakota, 

Ohio, Texas, Wyoming)t

No

Requirements for hazardous air 

pollutants

Certain Clean Air Act 

provisions apply

State permitting or 

registration programs may 

address hazardous air 

pollutants

No

Requirements related to hydrogen 

sulfide gas 

No specific requirementsu 6 of 6 Yes

Requirements related to flaring Under new New Source 

Performance Standards, 

most hydraulically fractured 

gas wells must do green 

completions 

6 of 6 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. 
Appendix X: Crosswalk between Selected 

Requirements from EPA, States, and Federal 

Lands

Page 228 GAO-12-874 Unconventional Oil and Gas Development

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. 

mAccording 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. 
Appendix XI: Comments from the Department 

of Agriculture

Page 229 GAO-12-874 Unconventional Oil and Gas Development

Appendix XI: Comments from the 

Department of Agriculture
Appendix XII: Comments from the Department 

of the Interior

Page 230 GAO-12-874 Unconventional Oil and Gas Development

Appendix XII: Comments from the 

Department of the Interior
Appendix XII: Comments from the Department 

of the Interior

Page 231 GAO-12-874 Unconventional Oil and Gas Development
Appendix XII: Comments from the Department 

of the Interior

Page 232 GAO-12-874 Unconventional Oil and Gas Development
Appendix XIII: GAO Contact and Staff 

Acknowledgments

Page 233 GAO-12-874 Unconventional Oil and Gas Development

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

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.

Appendix XIII: GAO Contact and Staff 

Acknowledgments 

GAO Contact

Staff 

Acknowledgments

(361347)
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