oversight

Unconventional Oil and Gas Development: Key Environmental and Public Health Requirements

Published by the Government Accountability Office on 2012-09-05.

Below is a raw (and likely hideous) rendition of the original report. (PDF)

                 United States Government Accountability Office

GAO              Report to Congressional Requesters




September 2012
                 UNCONVENTIONAL
                 OIL AND GAS
                 DEVELOPMENT

                 Key Environmental
                 and Public Health
                 Requirements




GAO-12-874
                                                September 2012

                                                UNCONVENTIONAL OIL AND GAS
                                                DEVELOPMENT
                                                Key Environmental and Public Health Requirements
Highlights of GAO-12-874, a report to
congressional requesters




Why GAO Did This Study                          What GAO Found
Technological improvements have                 As with conventional oil and gas development, requirements from eight federal
allowed the extraction of oil and natural       environmental and public health laws apply to unconventional oil and gas
gas from onshore unconventional                 development. For example, the Clean Water Act (CWA) regulates discharges of
reservoirs such as shale, tight                 pollutants into surface waters. Among other things, CWA requires oil and gas
sandstone, and coalbed methane                  well site operators to obtain permits for discharges of produced water—which
formations. Specifically, advances in           includes fluids used for hydraulic fracturing, as well as water that occurs naturally
horizontal drilling techniques combined         in oil- or gas-bearing formations—to surface waters. In addition, the Resource
with hydraulic fracturing (pumping              Conservation and Recovery Act (RCRA) governs the management and disposal
water, sand, and chemicals into wells
                                                of hazardous wastes, among other things. However, key exemptions or
to fracture underground rock
                                                limitations in regulatory coverage affect the applicability of six of these
formations and allow oil or gas to flow)
have increased domestic development
                                                environmental and public health laws. For example, CWA also generally
of oil and natural gas from these               regulates stormwater discharges by requiring that facilities associated with
unconventional reservoirs. The                  industrial and construction activities get permits, but the law and its regulations
increase in such development has                largely exempt oil and gas well sites. In addition, oil and gas exploration and
raised concerns about potential                 production wastes are exempt from RCRA hazardous waste requirements based
environmental and public health effects         on a regulatory determination made by the Environmental Protection Agency
and whether existing federal and state          (EPA) in 1988. EPA generally retains its authorities under federal environmental
environmental and public health                 and public health laws to respond to environmental contamination.
requirements are adequate.
                                                All six states in GAO’s review implement additional requirements governing
GAO was asked to review                         activities associated with oil and gas development and have updated some
environmental and public health                 aspects of their requirements in recent years. For example, all six states have
requirements for unconventional oil             requirements related to how wells are to be drilled and how casing—steel pipe
and gas development and (1) describe            within the well—is to be installed and cemented in place, though the specifics of
federal requirements; (2) describe              their requirements vary. The states also have requirements related to well site
state requirements; (3) describe                selection and preparation, which may include baseline testing of water wells
additional requirements that apply on           before drilling or stormwater management.
federal lands; and (4) identify
challenges, if any, that federal and            Oil and gas development on federal lands must comply with applicable federal
state agencies reported facing in               environmental and state laws, as well as additional requirements. These
regulating oil and gas development              requirements are the same for conventional and unconventional oil and gas
from unconventional reservoirs. GAO             development. The Bureau of Land Management (BLM) oversees oil and gas
identified and analyzed federal laws,           development on approximately 700 million subsurface acres. BLM regulations for
state laws in six selected states               leases and permits govern similar types of activities as state requirements, such
(Colorado, North Dakota, Ohio,                  as requirements for how operators drill the well and install casing. BLM recently
Pennsylvania, Texas, and Wyoming),              proposed new regulations for hydraulic fracturing of wells on public lands.
and interviewed federal and state
officials and representatives from              Federal and state agencies reported several challenges in regulating oil and gas
industry, environmental, and public             development from unconventional reservoirs. EPA officials reported that
health organizations.                           conducting inspection and enforcement activities and having limited legal
                                                authorities are challenges. For example, conducting inspection and enforcement
GAO is not making recommendations.
In commenting on the report, agencies           activities is challenging due to limited information, such as data on groundwater
provided information on recent                  quality prior to drilling. EPA officials also said that the exclusion of exploration
regulatory activities and technical             and production waste from hazardous waste regulations under RCRA
comments.                                       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
View GAO-12-874. For more information,          challenges. For example, officials from several states and BLM said that retaining
contact David C. Trimble at (202) 512-3841 or   employees is difficult because qualified staff are frequently offered more money
trimbled@gao.gov.
                                                for private sector positions within the oil and gas industry.
                                                                                         United States Government Accountability Office
Contents


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




               Page i                        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 ii                       GAO-12-874 Unconventional Oil and Gas Development
Tables
                                                                       a
          Table 1: Potential Waste Management and Disposal Options                   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 iii                      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 iv                       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


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Page v                                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 has
                                   increased significantly in several areas of the country, including the


                                   1
                                    Conventional sandstone has well-connected pores, but tight sandstone has irregularly
                                   distributed and poorly connected pores. Due to this low connectivity or permeability, gas
                                   trapped within tight sandstones is not easily produced.
                                   2
                                    The Energy Information Administration is the statistical and analytical agency within the
                                   Department of Energy that collects, analyzes, and disseminates independent and impartial
                                   information on energy issues.
                                   3
                                    Shale oil differs from “oil shale.” Oil shale requires a different process to extract.
                                   Specifically, to extract the oil from oil shale, the rock needs to be heated to very high
                                   temperatures—ranging from about 650 to 1,000 degrees Fahrenheit—in a process known
                                   as retorting. For additional information on oil shale, see GAO, Energy-Water Nexus: A
                                   Better and Coordinated Understanding of Water Resources Could Help Mitigate the
                                   Impacts of Potential Oil Shale Development, GAO-11-35 (Washington, D.C.:
                                   Oct. 29, 2010).




                                   Page 1                                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 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




4
 Department of Energy, Secretary of Energy Advisory Board, Shale Gas Production
Subcommittee 90-Day Report (Washington, D.C.: 2011)
5
 GAO is conducting a separate and more detailed review of risks associated with shale oil
and gas development.
6
 EPA announced in March 2010 that its Office of Research and Development would
conduct a study to examine the potential effects of hydraulic fracturing on drinking water
resources. According to EPA officials, the agency anticipates issuing a progress report in
2012 and a final report in 2014.




Page 2                                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 3                             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 4                         GAO-12-874 Unconventional Oil and Gas Development
                             Oil and gas reservoirs vary in their geological makeup, location, and size.
Background                   Regardless of the reservoir, unconventional oil and gas development
                             involves a number of activities, many of which are also conducted in
                             conventional oil and gas drilling. This section describes the types and
                             locations of oil and gas reservoirs and the key stages of oil and gas
                             development.


Types and Locations of Oil   Oil and natural gas are found in a variety of geologic formations. In
and Gas Reservoirs           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.




                             Page 5                         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 6                               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 7                                    GAO-12-874 Unconventional Oil and Gas Development
Activities Associated With   Developing unconventional reservoirs involves a variety of activities,
Oil and Gas Development      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.




                             Page 8                                 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 9                           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 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.




10
  In acquiring this water, operators must comply with applicable state and regional laws or
rules regarding water withdrawals, but these are outside the scope of this report.
11
  The Ground Water Protection Council is a nonprofit organization whose members are
state groundwater regulatory agencies. Ground Water Protection Council and ALL
Consulting. “Modern Shale Gas Development in the United States: A Primer.” Prepared
for the Department of Energy and National Energy Technology Laboratory. April 2009.
12
  Not all the fluids injected into the well during hydraulic fracturing necessarily flow back to
the surface.




Page 10                                 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 11                                   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 12                                   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 Sometimes,
when a well starts production, operators reclaim the portions of a site
affected by the initial drilling activity.

Waste management and disposal. Throughout the drilling, hydraulic
fracturing, and subsequent production activities, operators must manage
and dispose of several types of waste. For example, operators must
manage produced water, which, for purposes of this report includes
flowback water—the water, proppant, and chemicals used for hydraulic
fracturing—as well as water that occurs naturally in the oil- or gas-bearing
geological formation. Operators temporarily store produced water in tanks
or pits, and some operators may recycle it for reuse in subsequent
hydraulic fracturing. Options for permanently disposing of produced water
vary and may include, for example, injecting it underground into wells
designated for such purposes. 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.




13
 Backfilling is refilling a pit or other area with soil.
14
  We recently issued a report on the quantity, quality, and management of water produced
during oil and gas production. See GAO, Energy-Water Nexus: Information on the
Quantity, Quality, and Management of Water Produced during Oil and Gas Production,
GAO-12-156 (Washington, D.C.: Jan. 9, 2012).




Page 13                                   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        •   Produced water                        •   Drill cuttings                        •  Unused hydraulic fracturing
waste                   •   Drilling mud                          •   Trash                                    chemicals being discarded
                                                                                                            •  Certain other chemical and
                                                                                                               oily wastes
Options for temporary   •   Tanks or pits                         •    Tanks or pits                        •     Tanks
storage
Options for reuse       •   Recycle for use in future             •    Roadspreading of drill               N/A
                            hydraulic fracturing                       cuttings
                        •   Irrigation
                        •   Roadspreading (used for dust or
                            ice suppression)
                        •   Reuse of drilling mud
Options for             •   Underground injection well            •    Solid waste landfill                 •     Hazardous waste disposal
permanent disposal      •   Discharge to surface water            •    Bury drill cuttings on or near             facility
                        •   Commercial treatment facilities            well pad
                        •   Publicly-owned treatment works
                                            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 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



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




                                            Page 14                                    GAO-12-874 Unconventional Oil and Gas Development
     respiratory causes. 16 Particulate matter is a complex mixture of small
     particles and liquid droplets, which are linked to a variety of health
     problems such as cardiovascular and respiratory problems. Nitrogen
     oxides have been linked to respiratory illness. Short-term exposure to
     sulfur dioxide is linked to a number of adverse respiratory effects,
     including the narrowing of airways and increased asthma symptoms.
     Carbon monoxide can cause harmful health effects by reducing
     oxygen delivery to the body’s organs (like the heart and brain).

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

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

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

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




16
  Volatile organic compounds are emitted as gases from certain solids or liquids and
include a variety of chemicals, some of which may have short- and long-term adverse
health effects. Volatile organic compounds are emitted by a wide array of products
numbering in the thousands including paints and lacquers, paint strippers, cleaning
supplies, and pesticides.
17
  Flaring involves the burning of gas either for safety reasons or because operators do not
have the infrastructure to bring the gas to market. For more information on flaring, see
GAO, Federal Oil and Gas Leases: Opportunities Exist to Capture Vented and Flared
Natural Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases,
GAO-11-34 (Washington, D.C.: Oct. 29, 2010).




Page 15                               GAO-12-874 Unconventional Oil and Gas Development
Figure 6: Potential Sources and Types of Air Emissions from Oil and Gas Development




                                        Page 16                          GAO-12-874 Unconventional Oil and Gas Development
                           Requirements from eight federal laws apply to the development of oil and
Federal                    gas from unconventional sources. In large part, the same requirements
Environmental and          apply to conventional and unconventional oil and gas development. There
                           are exemptions or limitations in regulatory coverage for preventive
Public Health Laws         programs authorized by six of these laws, though EPA generally retains
Apply to                   its authorities under federal environmental and public health laws to
Unconventional Oil         respond to environmental contamination. States may have regulatory
                           programs related to some of these exemptions or limitations in federal
and Gas Development        regulatory coverage; state requirements are discussed later in this report.
but with Key
Exemptions

Eight Federal              Parts of the following eight federal environmental and public health laws
Environmental and Public   apply to unconventional oil and gas development:
Health Laws Apply to       •   Safe Drinking Water Act (SDWA)
Unconventional Oil and
Gas Development            •   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 for more details about seven of
                           these laws, please see appendixes II through VIII.



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




                           Page 17                              GAO-12-874 Unconventional Oil and Gas Development
Safe Drinking Water Act   SDWA is the main federal law that ensures the quality of drinking water. 19
                          Two key aspects of SDWA that are part of the regulatory framework
                          governing unconventional oil and gas development are the Underground
                          Injection Control (UIC) program and the imminent and substantial
                          endangerment provision.

                          UIC Program
                          Under SDWA, EPA regulates the injection of fluids underground through
                          its UIC program, including the injection of produced water from oil and
                          gas development. The UIC program protects underground sources of
                          drinking water by setting and enforcing standards for siting, constructing,
                          and operating injection wells. Injection wells in the UIC program fall into
                          six different categories based on the types of fluids being injected. The
                          wells used to manage fluids associated with oil and gas production,
                          including produced water, are Class II wells. 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



                          19
                              Pub. L. No. 93-523 (1974), codified as amended at 42 U.S.C. §§ 300f–300j-26 (2010).
                          20
                            Other classes of UIC wells are used by other industries. For example, Class I wells are
                          for the injection of hazardous, radioactive, and industrial wastes. Class III wells are used
                          for the injection of fluids as part of mining operations, such as for mining salts or uranium.
                          21
                            A third type of Class II UIC well is a hydrocarbon storage well, which injects liquid
                          hydrocarbons into underground formations, such as salt caverns, which can store the
                          hydrocarbons for later use. EPA estimates there are over 100 hydrocarbon storage wells
                          in use in the United States.




                          Page 18                                GAO-12-874 Unconventional Oil and Gas Development
Figure 7: Enhanced Recovery and Disposal Wells




Page 19                         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 operator 23 must, among other things (1) obtain a permit from EPA or a
state, (2) demonstrate that casing and cementing are adequate, and (3)
pass an integrity test prior to beginning operation and at least once every
5 years. In addition, when proposing a new Class II UIC well, an operator
must identify any existing water or abandoned production or injection
wells generally within one-quarter mile of the proposed well. During the
life of the Class II UIC well, the operator has to comply with monitoring
requirements, including tracking the injection pressure, rate of injection,
and volume of fluid injected.

SDWA authorizes EPA to approve by rule a state to be the primary
enforcement responsibility—called primacy—for the UIC program, which
means that a state assumes responsibility for implementing its program,
including permitting and monitoring UIC wells. Generally, to be approved
for primacy, state programs must be at least as stringent as the federal
program for each of the well classes for which primacy is sought;
however, SDWA also includes alternative provisions for primacy related
to Class II wells whereby, in lieu of adopting requirements consistent with
EPA’s Class II regulations, a state can demonstrate to EPA that its
program is effective in preventing endangerment of underground sources
of drinking water. Five of the six states in our review (Colorado, North
Dakota, Ohio, Texas, and Wyoming) have been granted primacy for
Class II wells under the alternative provisions. Pennsylvania has not
applied for primacy, so EPA directly implements the program there.
Please see appendix IX for more information about UIC requirements in
the six states in our review.

As discussed, the UIC program regulates the injection of fluids
underground. Historically, the UIC program was not used to regulate
hydraulic fracturing, even though fracturing entails the injection of fluid
underground. In 1994, in light of concerns that hydraulic fracturing of
coalbed methane wells threatened drinking water, citizens petitioned EPA



22
 See discussion below. According to EPA, some states’ UIC requirements for Class II
wells are very similar or identical to EPA requirements.
23
  For simplicity, throughout this report we refer to requirements on well operators. In some
cases requirements may also apply to well owners.




Page 20                               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 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



24
 The court ordered EPA to reconsider its approval of Alabama’s program. Legal
Environmental Assistance Foundation v. EPA, 118 F.3d 1467, 1478 (11th Cir.1997).
25
  UIC regulations at the time and now provide that ‘‘[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.
26
  In 2003, EPA entered into a memorandum of agreement with three major fracturing
service companies in which the companies voluntarily agreed to eliminate diesel fuel in
hydraulic fracturing fluids injected into underground sources of drinking water during
hydraulic fracturing of coalbed methane wells.
27
  According to EPA officials, EPA Region 3 has sent letters to the relevant operators who
may have used diesel in hydraulic fracturing stating they must apply for a Class II UIC
permit if they continue using diesel in hydraulic fracturing.




Page 21                                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 22                         GAO-12-874 Unconventional Oil and Gas Development
                  For more details about SDWA, please see appendix II.

Clean Water Act   To restore and maintain the nation’s waters, CWA authorizes EPA to,
                  among other things, regulate pollutant discharges and respond to spills
                  affecting rivers and streams. 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 In
                  addition, under certain circumstances, EPA has response authorities; for
                  example, it can generally bring suit or take other actions to protect the
                  public health and welfare from actual or threatened discharges of oil or
                  hazardous substances to U.S. navigable waters and adjoining shorelines.

                  NPDES
                  EPA’s NPDES program limits the types and amounts of pollutants that
                  industrial sites, industrial wastewater treatment facilities, and municipal
                  wastewater treatment facilities (often called publicly-owned treatment works
                  or POTWs) can discharge into the nation’s surface waters by requiring
                  these facilities to have and comply with permits listing pollutants and their
                  discharge limits. As required by CWA, EPA develops effluent limitations for
                  certain industrial categories based on available control technologies and
                  other factors to prevent or treat the discharge. EPA established multiple



                  28
                    The Federal Water Pollution Control Act Amendments of 1972, Pub. L. No. 92-500, § 2,
                  86 Stat. 816, codified as amended at 33 U.S.C. §§ 1251-1387 (2011) (commonly referred
                  to as the Clean Water Act).
                  29
                    For the purpose of this document, when we use the term “surface waters” in relation to
                  federal regulation, we refer to waters of the United States, including jurisdictional rivers,
                  streams, wetlands, and other waters. State definitions of the term “surface waters” may
                  differ. EPA officials noted that some surface waters may not be jurisdictional for certain
                  CWA provisions.
                  30
                    The scope of jurisdiction for the section 311 oil spill program is broader than that for the
                  NPDES program. The section 311 oil spill program and the NPDES program both have
                  jurisdiction over navigable waters of the United States; Section 311 also provides
                  jurisdiction over spills of oil or hazardous substances into or on adjoining shorelines or that
                  may affect natural resources of the United States, among others.




                  Page 23                                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 west 32 in which
the quality of produced water from the wells is good enough for watering
crops and livestock or to support wildlife in streams. The effluent
limitations guideline for this subcategory allows such discharges of
produced water for these purposes as long as the water meets a
minimum quality standard for oil and grease. EPA officials identified 349
facilities with discharge permits in this subcategory. Officials also stated



31
  EPA established additional industrial categories in the oil and gas sector for wells in
certain near-shore coastal areas, but effluent limitation guidelines for this category are not
discussed here, as this report is focused on onshore unconventional oil and gas
production.
32
  Specifically, the agricultural and wildlife water use subcategory includes wells located
west of the 98th meridian, which extends from approximately the eastern border of North
Dakota south through central Texas.




Page 24                                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 25                          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 The 2005 Energy Policy Act expanded the language of
the exemption to include construction activities at oil and gas well sites,
meaning that uncontaminated stormwater discharges from oil and gas
construction sites also do not require NPDES permits. So while other
industries must generally obtain NPDES permits for construction activities
that disturb an acre or more of land, operators of oil and gas well sites are
generally not required to do so.

Spill Reporting and Spill Prevention and Response Planning
CWA prohibits discharges of oil or hazardous substances into U.S.
navigable waters or on adjoining shorelines. Specifically, CWA requires
facilities—including oil and gas well sites—to report any unpermitted
releases of oil or hazardous substances above threshold quantities to the


33
  POTWs will be discussed in greater detail later in this report.
34
  The 1987 Water Quality Act also exempted oil and gas processing, treatment, and
transmission facilities from permit requirements for stormwater discharges.
35
  EPA has established by regulation threshold amounts of certain pollutants that, if
released, trigger reporting requirements; these amounts are known as “reportable
quantities.” Specifically, the reportable quantities triggering a permit are listed in 40 C.F.R.
§§ 117.21, 302.6, 110.6 (2011).




Page 26                                 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 The amount of oil storage capacity at oil and gas
well sites tends to vary based on whether the well is being drilled,
hydraulically fractured, or has entered production. For example, during
drilling at well sites located near these waters, operators generally have
to comply with SPCC requirements if fuel tanks for the drilling rig exceed
the 1,320 gallon threshold. According to EPA officials, nearly all drill rigs
have fuel tanks larger than 1,320 gallons, and so most well sites are
subject to the SPCC rule during drilling if they are near these waters. Oil
and gas well sites that are subject to the SPCC rule were required to
comply by November 2011 or before starting operations.

In accordance with CWA, EPA directly administers the SPCC program
rather than delegating authority to states. EPA regulations generally do
not require facilities to report SPCC information to EPA, including whether
or not they are regulated. As a result, EPA does not know the universe of




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




Page 27                               GAO-12-874 Unconventional Oil and Gas Development
SPCC-regulated facilities. 37 To ensure that regulated facilities are meeting
SPCC requirements, EPA Regional personnel may inspect these facilities
to evaluate their compliance. EPA officials said that some of these
inspections were conducted as follow-up after spills were reported and
that most inspections are conducted during the production phase, since
drilling and hydraulic fracturing are of much shorter durations, making it
difficult for inspectors to visit these sites during those times. According to
EPA officials, Regional personnel inspected 120 oil and gas well sites
nationwide in fiscal year 2011 and found noncompliance at 105 of these
sites. These violations ranged from paperwork inconsistencies to more
serious violations, such as a lack of secondary containment around
stored oil or failure to implement an SPCC plan (though EPA officials
were unable to specifically quantify the number of more serious
violations). EPA officials said that EPA has addressed some of the 105
violations through enforcement actions.

Imminent and Substantial Endangerment and Release Response
Authorities
CWA also provides EPA with authorities to address the discharge of
pollutants and to address actual or threatened discharges of oil or
hazardous substances in certain circumstances. For example, under one
provision, EPA has the authority to address actual or threatened
discharges of oil or hazardous substances into U.S. navigable waters or
on adjoining shorelines upon a determination that there may be an
imminent and substantial threat to the public health or welfare of the
United States, by bringing suit or taking other action, including issuing
administrative orders that may be necessary to protect public health and
welfare. Under another provision, EPA has authority to obtain records and
access to facilities, among other things, in order to determine if a person
is violating certain CWA requirements. For example, EPA conducted
initial investigations in Bradford County, Pennsylvania, following a 2011
spill of hydraulic fracturing and other fluids that entered a stream. Citing



37
  See 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 28                                GAO-12-874 Unconventional Oil and Gas Development
                its authority under CWA and other laws, 38 EPA requested information
                from the operator about the incident, including information about the
                chemicals involved and the environmental effects of the spill. Meanwhile,
                the Pennsylvania Department of Environmental Protection signed a
                consent order and agreement with the operator in 2012 that required the
                operator to pay fines and implement a monitoring plan for the affected
                stream.

                For more details about CWA, please see appendix III.

Clean Air Act   CAA, a federal law that regulates air pollution from mobile and stationary
                sources, was enacted to improve and protect the quality of the nation’s
                air. 39 Under CAA, EPA sets national ambient air quality standards for the
                six criteria pollutants––ground level ozone, carbon monoxide, particulate
                matter, sulfur dioxide, nitrogen oxides, and lead––at levels it determines
                are necessary to protect public health and welfare. States then develop
                state implementation plans (SIP) to establish how the state will attain air
                quality standards, through regulation, permits, policies, and other means.
                States must obtain EPA approval for SIPs; if a SIP is not acceptable, EPA
                may assume responsibility for implementing and enforcing CAA in that
                state. CAA also authorizes EPA to regulate emissions of hazardous air
                pollutants, such as benzene. In addition, under CAA, EPA requires
                reporting of greenhouse gas emissions from a variety of sources,
                including oil and gas wells.

                Mobile Sources–Criteria Air Pollutants
                In accordance with CAA, EPA has progressively implemented more
                stringent diesel emissions standards to lower the amount of key pollutants
                from mobile diesel-powered engines since 1984. 40 These standards apply
                to a variety of on- and off-road diesel-powered engines, including trucks
                used in the oil and gas industry to move materials to and from well sites
                and compressors used to drill and hydraulically fracture wells. Diesel


                38
                  Specifically, EPA cited authorities under CWA section 308, as well as under CERCLA
                and RCRA.
                39
                  Clean Air Act Amendments of 1970, Pub. L. No. 91-604, 84 Stat. 1676 (1970), codified
                as amended at 42 U.S.C. §§ 7401-7671q (2011) (commonly referred to as the Clean Air
                Act).
                40
                 See GAO, Diesel Pollution: Fragmented Federal Programs That Reduce Mobile Source
                Emissions Could Be Improved, GAO-12-261 (Washington, D.C.: Feb. 7, 2012).




                Page 29                             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 sites 42 and (2) to the extent
that EPA promulgated standards for equipment that may be located at
well sites, the capacity of equipment located at well sites was generally
too low to trigger the requirement. For example, in 1987, EPA issued
NSPS for storage vessels containing petroleum liquids; however, the
standards apply only to tanks above a certain size, and EPA officials said
that most storage tanks at oil and gas sites are below the threshold.

In April 2012, EPA promulgated NSPS for the oil and natural gas
production industry which, when fully phased-in by 2015, will require
reductions of volatile organic compound emissions at oil and gas well
sites, including wells using hydraulic fracturing. 43 Specifically, these new


41
  For example, precursors to ground level ozone are nitrogen oxides and volatile organic
compounds.
42
  EPA did promulgate standards related to other parts of the oil and gas industry. For
example, in 1985, EPA promulgated NSPS that focused on natural gas processing plants,
which remove impurities from natural gas to prepare it for use by consumers.
43
  EPA’s April 2012 rulemaking also set NSPS for other parts of the oil and natural gas
industry, such as for equipment leaks, certain types of compressors, and pneumatic
controllers located at natural gas processing plants.




Page 30                              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


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




Page 31                                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 32                         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 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.




45
  In addition to NESHAPs specific to the oil and natural gas production industrial source
category, EPA promulgated other NESHAPs that could apply to oil and gas well sites
depending on the types of equipment in use and their size. See appendix IV for more
details.
46
 EPA Region 6 includes the states of Arkansas, Louisiana, New Mexico, Oklahoma, and
Texas.




Page 33                               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 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



47
  In addition, a 1999 law provided an exemption for flammable substances being used as
fuel; this exemption applies to any type of facility using fuel. Chemical Safety Information,
Site Security and Fuels Regulatory Relief Act, Pub. L. No. 106–40 § 2, 113 Stat 207
(1999).
48
  The Chemical Safety Board is an independent federal agency investigating chemical
accidents to protect workers, the public, and the environment. See U.S. Chemical Safety
and Hazard Investigation Board, Investigative Study Final Report: Public Safety at Oil and
Gas Storage Facilities, Report No. 2011-H-1 (September 2011).




Page 34                                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 The Chemical Safety Board requested
                            that EPA provide a response stating how EPA will address the
                            recommendation. EPA responded in June 2012, stating its intent to
                            comply with the recommendation.

                            Stationary Sources–Greenhouse Gas Reporting
                            As of 2012, oil and natural gas production facilities are required to report
                            their greenhouse gas emissions to EPA on an annual basis as described
                            in EPA’s greenhouse gas reporting rule. According to EPA documents, oil
                            and gas well sites may emit greenhouse gases, including methane and
                            carbon dioxide, from sources including: (1) combustion sources, such as
                            engines used on site, which typically burn natural gas or diesel fuel, and
                            (2) indirect sources, such as equipment leaks and venting. 50 The
                            greenhouse gas reporting rule requires oil and gas production facilities
                            (defined in regulation as all wells in a single basin that are under common
                            ownership or control) that emit more than 25,000 metric tons of carbon
                            dioxide equivalent at the basin level to report their annual emissions of
                            carbon dioxide, methane, and nitrous oxide from equipment leaks and
                            venting, gas flaring, and stationary and portable combustion. EPA
                            documents estimate that emissions from approximately 467,000 onshore
                            wells are covered under the rule.

                            For more details about CAA, please see appendix IV.

Resource Conservation and   RCRA, passed in 1976, established EPA’s authority to regulate the
Recovery Act                generation, transportation, treatment, storage, and disposal of hazardous
                            wastes. 51 Subsequently, the Solid Waste Disposal Act Amendments of
                            1980 created a separate process by which oil and gas exploration and



                            49
                              The Chemical Safety Board also noted that exploration and production storage tanks are
                            exempt from the security requirements of CWA’s spill prevention program.
                            50
                              Other major greenhouse gases covered by EPA’s greenhouse gas reporting rule include
                            hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.
                            51
                              Pub. L. No. 94-580, 90 Stat. 2795 (1976) (amending the Solid Waste Disposal Act, but
                            generally referred to as RCRA), codified as amended at 42 U.S.C. §§ 6901-6992k (2011).
                            RCRA also created a framework in which states are largely responsible for solid (i.e.,
                            nonhazardous) waste regulations, including treatment and land disposal of these wastes.
                            State solid waste provisions will be discussed in greater detail later in this report.




                            Page 35                             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
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,



52
  Specifically, oil and gas exploration and production waste includes drilling fluids,
produced waters, and other wastes associated with the exploration, development, or
production of crude oil or natural gas, among other things.
53
  Field operations include, for example, water separation, demulsifying, degassing, and
storage at well sites.
54
   Small quantity generators are those generating between 100 and 1,000 kilograms of
hazardous waste per month, and large quantity generators are those generating more
than 1,000 kilograms per month. Both small and large quantity generators are required to
obtain an EPA identification number and are subject to certain regulations. Facilities
generating less than 100 kilograms of hazardous waste per month are considered
conditionally exempt small quantity generators provided they meet certain conditions, and
if so, do not need to obtain an identification number.
55
  These conditionally exempt small quantity generators are subject to limited generator
waste management standards, namely to identify their hazardous waste, comply with
storage limit requirements, and ensure waste treatment or disposal in a proper facility.




Page 36                               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.

Comprehensive Environmental   Congress passed CERCLA in 1980 to protect public health and the
Response, Compensation, and   environment by addressing the cleanup of hazardous substance
Liability Act                 releases. 56 CERCLA establishes a system governing the reporting and
                              cleanup of releases of hazardous substances and provides the federal
                              government the authority to respond to actual and threatened releases of
                              hazardous substances, pollutants, and contaminants that may endanger
                              public health and the environment. CERCLA requires operators of oil and
                              gas sites to report certain releases of hazardous substances and gives



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




                              Page 37                             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 38                        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.

Emergency Planning and        Among other things, EPCRA provides individuals and their communities
Community Right-to-Know Act   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 When asked whether
                              oil and gas well sites would commonly trigger EPCRA’s release
                              notification and chemical storage reporting requirements, EPA officials
                              said these requirements could be triggered at every well site.

                              EPCRA also established the Toxics Release Inventory (TRI)––a publicly
                              available database containing information about chemical releases from
                              more than 20,000 industrial facilities––but EPA regulations for the TRI do


                              57
                                Pub. L. No. 99-499, 100 Stat. 1728 (1986), codified at 42 U.S.C. §§ 11001–11050
                              (2012).
                              58
                                Three types of releases must be reported: (1) release of extremely hazardous
                              substances for which notification is also required under CERCLA § 103(c), (2) release of
                              extremely hazardous substances for which notification is not required under CERCLA §
                              103(c), but above reporting thresholds and subject to additional conditions, and (3)
                              release of other hazardous substances for which notification is also required under
                              CERCLA § 103(c), subject to CERCLA reporting thresholds or 1 pound default threshold.
                              EPCRA § 304(a), 42 U.S.C. §§ 11004(a) (2011).
                              59
                                Specifically, the thresholds are (1) more than 500 pounds or the threshold planning
                              quantity, whichever is lower, of extremely hazardous substances, or (2) more than 10,000
                              pounds of other hazardous chemicals.




                              Page 39                              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 EPA officials said that
adding oil and gas well sites would likely provide an incomplete picture of


60
  In addition to identifying industries, EPCRA specifies that reporting requirements apply
to owners or operators of covered facilities: (1) with 10 or more full-time employees and
(2) that manufactured, processed, or otherwise used a listed toxic chemical in excess of
the reporting threshold during the calendar year.
61
  The complete list of industries added by EPA in 1997 includes metal mining, coal
mining, electrical utilities that combust coal and/or oil for the purpose of generating power
for distribution in commerce, refuse processing or destruction facilities regulated under
RCRA’s hazardous waste provisions, chemical wholesalers, petroleum terminals, and bulk
stations and solvent recovery services.
62
  Other thresholds include the number of employees at the facility.
63
  Officials said that EPA is also considering steam generation from coal and/or oil,
petroleum bulk storage, iron ore mining, phosphate mining, large dry cleaning, and solid
waste combustors and incinerators.




Page 40                                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.

Toxic Substances Control Act   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 TSCA allows chemical
                               companies to assert confidentiality claims on information provided to
                               EPA; if the information provided meets certain criteria, EPA must protect
                               it from disclosure to the public.

                               EPA maintains a list of chemicals that are or have been manufactured or
                               processed in the United States, called the TSCA inventory. Of the over
                               84,000 chemicals currently in the TSCA inventory, about 62,000 were
                               already in commerce when EPA began reviewing chemicals in 1979.
                               Since then, EPA has reviewed more than 45,000 new chemicals, of which
                               approximately 20,000 were added to the inventory after chemical
                               companies began manufacturing them. As part of EPA’s Study on the
                               Potential Impacts of Hydraulic Fracturing on Drinking Water Resources,
                               EPA is currently analyzing information provided by nine hydraulic
                               fracturing service companies, including a list of chemicals used in
                               hydraulic fracturing operations. EPA officials said that they expect most of


                               64
                                 Pub. L. No. 94-469, 90 Stat. 2003 (1976), codified as amended at 15 U.S.C. §§ 2601-
                               2692 (2012). TSCA addresses those chemicals manufactured or imported into the United
                               States, but it generally excludes certain substances, such as pesticides, which are
                               regulated under the Federal Insecticide, Fungicide, and Rodenticide Act, and any food,
                               food additive, drug, cosmetic, or device regulated under the Federal Food, Drug, and
                               Cosmetics Act. Hereinafter, references to chemical substances in discussions of TSCA
                               are intended to include mixtures.
                               65
                                  These authorities are conditional on EPA making certain findings. For example, prior to
                               requiring testing under section 4, TSCA requires EPA to make findings (1) regarding the
                               risk of injury to health or the environment or regarding human exposure, (2) that existing
                               data are insufficient, and (3) that testing with respect to such effects is necessary to
                               develop needed data. Regarding actions to protect adequately against unreasonable
                               risks, examples of EPA actions include prohibiting or limiting the manufacture, processing,
                               or distribution in commerce of chemical substances or by placing restrictions on chemical
                               uses.




                               Page 41                               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 According to the petition, EPA and
                                  the public currently lack adequate information about the health and
                                  environmental effects of chemicals used in oil and gas exploration and
                                  production, and EPA should exercise its TSCA authorities to ensure that
                                  chemicals used in oil and gas exploration and production do not present
                                  an unreasonable risk of harm to health and the environment. In a letter to
                                  the petitioners, EPA granted the petition in part, stating there is value in
                                  beginning a rulemaking process under TSCA to obtain data on chemical
                                  substances used in hydraulic fracturing. EPA’s letter also stated that the
                                  TSCA proposal would focus on providing an aggregate picture of the
                                  chemical substances used in hydraulic fracturing, which would
                                  complement and not duplicate well-by-well disclosure programs that exist
                                  in some states. The letter also indicates that the agency is drafting an
                                  Advance Notice of Proposed Rulemaking on this issue. As of August 31,
                                  2012, EPA has not released a publication date for this proposed
                                  rulemaking. EPA also intends to convene a stakeholder process to gather
                                  additional information for use in developing a proposed rule.

                                  For more details about TSCA, please see appendix VIII.

Federal Insecticide, Fungicide,   FIFRA, as amended, mandates that EPA administer pesticide registration
and Rodenticide Act               requirements and authorizes EPA to regulate the use, sale, and
                                  distribution of pesticides to protect human health and preserve the




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




                                  Page 42                               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


Exemptions Are Related to   As discussed above, in six of the eight federal environmental and public
Preventive Programs         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



                            67
                              The Federal Environmental Pesticide Control Act, Pub. L. No. 92-516, 86 Stat. 973
                            (1972) (amending FIFRA), codified as amended at 7 U.S.C. §§ 136-136y (2012).
                            68
                              Ground Water Protection Council and ALL Consulting. “Modern Shale Gas Development
                            in the United States: A Primer.” Prepared for the Department of Energy and National
                            Energy Technology Laboratory. April 2009.
                            69
                              Glutaraldehyde is also used as a disinfectant for medical and dental equipment, in water
                            treatment systems, and as a preservative.




                            Page 43                              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

                                                                                                              Type of program related to
                                                                                                              exemption or limitation in
                                                                                                                 regulatory coverage
Law        Description of exemption or limitation in regulatory coverage                Source                  Preventive    Response
SDWA       Hydraulic fracturing with fluids other than diesel fuel does not require a   Statutory (2005)
                                                                                                                     X
           UIC permit.
CWA        Federal stormwater permits are not required for uncontaminated               Statutory (1987,
                                                                                                                     X
           stormwater at oil and gas construction sites or at oil and gas well sites.   2005)
CAA        Emissions of hazardous air pollutants from oil and gas wells and their       Statutory (1990)
           associated equipment may not be aggregated together or with those of
                                                                                                                     X
           pipeline compressors or pump stations to determine whether they are
           a major source.
           In the Risk Management Program, many naturally-occurring                     Regulatory/EPA
           hydrocarbons in oil and gas are not included in the threshold                decision (1988)              X
           determination of whether a facility should be regulated.
RCRA       Oil and gas exploration and production wastes are not regulated as           Regulatory/EPA
                                                                                                                     X
           hazardous waste.                                                             decision (1988)
CERCLA     Liability and reporting provisions do not apply to injections of fluids      Statutory (1980)
           authorized by state law for production, enhanced recovery, or                                             X
           produced water.
EPCRA      Oil and gas well operations are not required to report releases of listed    Regulatory/EPA
                                                                                                                     X
           chemicals to the TRI.                                                        decision (1997)
                                            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 44                                  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 See appendixes II through VI for a more detailed discussion of
these authorities.




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




Page 45                         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 Actual or threatened discharge of oil or hazardous substances into
           (§ 311)                                                 U.S navigable waters or on adjoining shorelines
CAAb       Imminent and substantial endangerment                   Accidental release to the air of regulated substance
           (§ 112(r)(9))
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 (§          Persons and facilities subject to UIC program requirements
           1445(b))
CWA        Access to records and to inspect facilities; require    Location of effluent source
           reports (§ 308(a))
           Access to records and to inspect facilities; ability to Persons and facilities subject to section 311, such as SPCC
           require provision of information (§ 311(m)(2))          program requirements
CAA        Access to records; ability to require provision of      Person who owns or operates any emission source, among others
           information (§ 114(a))
RCRA       Access to records and to inspect facilities (§ 3007)    Persons that have generated, stored, treated, transported, disposed
                                                                                                                d
                                                                   of, or otherwise handled hazardous wastes
CERCLA Access to records and to inspect facilities; ability to Location of actual or threatened release, generation, storage,
           require provision of information (§ 104(e))             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 46                                      GAO-12-874 Unconventional Oil and Gas Development
                           The six states in our review implement additional requirements governing
States in Our Review       a number of activities associated with oil and gas development. One of
Implement Additional       the states—Pennsylvania—is also part of the Delaware River Basin
                           Commission—a regional commission that implements additional
Requirements and           requirements. All six states have updated some aspects of their
Recently Updated           requirements in recent years.
Some Requirements

States in Our Review       In addition to implementing and enforcing certain aspects of federal
Implement Additional       requirements with EPA approval and oversight, the six states in our
Requirements and Certain   review implement additional requirements governing a number of
                           activities associated with oil and gas development. State requirements
Federal 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.




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




                           Page 47                             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

                                                 EPA environmental and public health
Area of regulation                               requirements                                Requirements of six states reviewed
Siting and site preparation
Identification or testing of water wells prior   No                                          1 of 6 (Wyoming) [identification alone]
to drilling of production wells                                                              2 of 6 (Colorado, Ohio) [identification and
                                                                                                      a
                                                                                             testing]
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        Noc                                         6 of 6
plans
Prescribed placement of surface casing           Noc                                         6 of 6
relative to groundwater zones
Hydraulic fracturing
Requirements to disclose information on          Nod                                         6 of 6
fracturing fluids
Well plugging
Requirements for notification, plugging plan No                                              6 of 6
or method, witnessing, and reporting
Programs to plug wells that are not properly No                                              6 of 6
plugged and have been abandoned
Site reclamation
Requirements for backfilling, regrading,         No                                          6 of 6
recontouring, and alleviating compaction of
soil
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,   Surface discharges are allowed in certain
                                                 others subject to conditions and permit)    cases in 3 western states (Colorado,
                                                                                             Texas, and Wyoming)




                                                 Page 48                            GAO-12-874 Unconventional Oil and Gas Development
                                                EPA environmental and public health
Area of regulation                              requirements                                                   Requirements of six states reviewed
   Requirements for discharge to POTWs Pretreatment standards for shale gas                                    Disposal at POTWs is an option in two
   or Centralized Waste Treatment (CWT) wastewater under development (CWA)                                     states (Ohio, Pennsylvania)e
   facilities                                                                                                  Disposal at CWT facilities is an option in 3
                                                                                                               states (Colorado, Pennsylvania, Wyoming)
   Recycling or other reuse                     Yes (CWA – certain produced water                              6 of 6 states allow recycling or other reuse
                                                discharges)
   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        No specific requirements but CAA general                       6 of 6
gas                                             duty clause requires prevention of
                                                accidental releases
Requirements related to flaring                 Under new NSPS regulation, most                                6 of 6
                                                hydraulically fractured gas wells must do
                                                green completions
                                            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 49                                                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.


Siting and Site Preparation   All six states we reviewed have state requirements regarding site
                              selection and preparation, though the specifics of their requirements vary.
                              Specifically, states have requirements for baseline testing of water wells,
                              required setbacks from water sources, and stormwater management,
                              among others. For example, three of the six states—Colorado, Ohio, and
                              Pennsylvania—have requirements that encourage or require operators to
                              conduct baseline water testing in certain cases. Colorado requires testing
                              of certain nearby wells when a proposed coalbed methane well is located
                              within a quarter-mile of a conventional gas well or a plugged and
                              abandoned well. 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 Operators
                              in Pennsylvania can defend against this presumption if they have
                              predrilling tests conducted by an independent certified laboratory showing
                              that the pollution predated drilling. State regulators in Pennsylvania said
                              that nearly all companies in Pennsylvania conduct baseline testing of
                              nearby water wells, in many cases up to 4,000 feet from the drilling site.

                              Five of the six states—Colorado, North Dakota, Ohio, Pennsylvania, and
                              Wyoming—we reviewed have requirements related to setbacks for well
                              sites or equipment from certain water sources. For example, in Ohio, oil


                              72
                                An abandoned well is a well that is no longer under control of an operator, whether or
                              not it was properly plugged. In Colorado, wells must be tested for all major cations
                              (positively-charged ions) and anions (negatively-charged ions), total dissolved solids, iron,
                              manganese, selenium, nitrates and nitrites, dissolved methane, field pH, sodium
                              adsorption ratio, presence of bacteria (iron related, sulfate reducing, slime, and coliform),
                              specific conductance, and hydrogen sulfide.
                              73
                                In Ohio, sampling must be conducted in accordance with state guidelines, which require
                              testing for barium, calcium, iron, magnesium, potassium, sodium, chloride, conductivity,
                              pH, sulfate, alkalinity, and total dissolved solids.
                              74
                                Pennsylvania has a similar provision for conventional wells, which presumes operators
                              to be liable for any pollution of water wells within 1,000 feet of a conventional well that
                              occurs within 6 months of drilling activities.




                              Page 50                                  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 In Pennsylvania, there are also setbacks from public water
                                  supplies and certain other bodies of water such as springs and wetlands.

                                  Oil and gas operations are generally not subject to certain stormwater
                                  permitting requirements under the Clean Water Act, but four of the six
                                  states we contacted—Colorado, North Dakota, Pennsylvania, and
                                  Wyoming—have their own stormwater permitting requirements. For
                                  example, the Wyoming Department of Environmental Quality requires
                                  permit coverage for stormwater discharges from all construction activities
                                  disturbing 1 or more acres. These permits require the operator to develop
                                  a stormwater management program, including best management
                                  practices, that can be reviewed by the Wyoming Department of
                                  Environmental Quality. In North Dakota, operators must obtain a permit
                                  for construction activities that disturb 5 or more acres, and state officials
                                  said that nearly all oil and gas drilling projects meet this threshold. This
                                  permit also requires the operator to develop a stormwater management
                                  program and implement best management practices for managing
                                  stormwater, such as using straw bales or dikes to manage water runoff.
                                  We did not identify any stormwater permitting requirements for Ohio and
                                  Texas, but their state regulations address stormwater in other ways. For
                                  example, operators in Ohio are required to comply with the state’s best
                                  management practices during construction, such as design guidelines for
                                  constructing access roads. Texas regulations prohibit operators from
                                  causing or allowing pollution of surface water and encourage operators to
                                  implement best management practices to minimize discharges, including
                                  discharges of sediment during storm events.

                                  States have additional requirements relating to erosion control, site
                                  preparation, and surface disturbance minimization. For more details about
                                  state siting and site preparation requirements, see appendix IX.

Drilling, Casing, and Cementing   All of the six states in our review have requirements related to how wells
                                  are to be drilled and casing should be installed and cemented in place,



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




                                  Page 51                              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 Different casing and cementing requirements apply
in Pennsylvania when drilling through coal formations, which state
regulators said is common in the southwest part of the state. In Texas,
operators are required to run surface casing to protect all usable quality
water, as defined by the Texas Commission on Environmental Quality.
The depth of the surface casing may be specified in a letter by the
commission or in rules specific to a particular oil or gas field, which
account for local considerations. In no case may surface casing be set
deeper than 200 feet below the specified depth without prior approval
from the Texas Railroad Commission, the oil and gas regulator in Texas.
Operators in Wyoming are generally required to run surface casing to
reach a depth below all known or reasonably estimated usable
groundwater as defined in regulations and generally 100 to 120 feet
below certain permitted water supply wells within a quarter-mile, but
certain coalbed methane wells are exempt from these requirements. Until
2012, Ohio did not specify a depth to which surface casing was required
to be set but according to state regulators, the depth of the casing used to
protect groundwater was dictated through the permitting process, and
regulators and operators were generally following the same casing and
cementing requirements for unconventional wells as they would for Class
II UIC wells. Ohio adopted new regulations effective August 2012 that
generally require operators to run surface casing at least 50 feet below
the base of the deepest underground source of drinking water or at least
50 feet into bedrock, whichever is deeper.

Among the six states we contacted, North Dakota and Ohio are the only
states with specific casing and cementing provisions for horizontal wells.
However, all six states have some requirements—whether through law,
regulation, or the permitting process—that generally require operators to
provide regulatory officials with information about the vertical and


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




Page 52                             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.

Hydraulic Fracturing   All six states we reviewed have requirements for disclosing the chemicals
                       used in hydraulic fracturing, but the specific requirements vary (see table
                       5). Four states—Colorado, North Dakota, Pennsylvania, and Texas—
                       require disclosure through the website FracFocus, which is a joint project
                       of the Ground Water Protection Council and the Interstate Oil and Gas
                       Compact Commission. 77 For example, operators that perform hydraulic
                       fracturing in Texas are required to upload certain information to the
                       website FracFocus within 30 days after completion of the well or 90 days
                       after the drilling operation is completed, whichever is earlier. Information
                       required to be uploaded to FracFocus includes, among other things, the
                       operator’s name; the date of completion of hydraulic fracturing; the well
                       location; the total volume of water used to conduct fracturing; and
                       chemicals used, including their trade names, suppliers, intended use, and
                       concentration. In Ohio, companies have options as to how to disclose
                       information, including through FracFocus. Wyoming’s chemical disclosure
                       requirements were developed prior to the development of FracFocus, and
                       the state does not require operators to disclose information through the
                       website. Among the six states we contacted, Wyoming is the only state


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




                       Page 53                              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          FracFocus          FracFocus               State website,             FracFocus          FracFocus           State agency
mechanism          website            website                 FracFocus                  website            website; state
                                                              website, or other                             website if
                                                              state approved                                FracFocus is
                                                              method                                        unavailable
Timing of          Information must No timing                 Information must           Information must   Information must    Information must
disclosure         be disclosed       requirement             be disclosed               be disclosed       be disclosed        be disclosed
requirement        within 60 days     specified.              within 60 days             within 60 days     within 30 days      before hydraulic
                   following                                  after the                  following the      after completion    fracturing and
                   completion of                              completion of              conclusion of      of the well or      within 30 days of
                   hydraulic                                  drilling or after a        hydraulic          within 90 days      completion
                   fracturing and not                         determination              fracturing.        after drilling is
                   later than 120                             that a well is a                              completed,
                   days after the                             dry or lost hole.                             whichever is
                   commencement                                                                             earlier.
                   of hydraulic
                   fracturing.
Protections for    Yes                None identifieda        Yes                        Yes                Yes                 Yes
confidential
information or
trade secrets
Provisions to      None identifieda   None identifieda        Yes                        None identifieda   Yes                 Yes
challenge trade
secrets
Provisions for     Yes                None identifieda        Yes                        Yes                Yes                 None identifieda
disclosure to
health
professionals
Provisions for     Yes                None identifieda        Yes                        Yes                Yes                 None identifieda
disclosure to
emergency
responders
                                          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 54                                              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 55                        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.

Well Plugging   All six states in our review have requirements regarding well plugging,
                such as notifying the state prior to plugging or using specific materials or
                methods to do so. For example, operators in Colorado must obtain prior
                approval from state regulators for the plugging method and provide notice
                of the estimated time and date of plugging. Colorado regulations specify
                that the material used for plugging must be placed in the well in a manner
                that permanently prevents migration of oil, gas, water, or other
                substances out of the formation in which it originated. Cement plugs must
                be a minimum of 50 feet in length and must extend a minimum of 50 feet
                above each zone to be protected. After plugging the well, operators must
                submit reports of plugging and abandonment to the Colorado Oil and Gas
                Conservation Commission and include information specifying the fluid
                used to fill the wellbore, information about the cement used, date of work,
                and depth of plugs. In Pennsylvania, operators must follow (1) specific
                provisions for well plugging based on whether the well is located in a coal
                area or noncoal area or (2) an alternate approved method. Prior to
                plugging a well in an area underlain by a workable coal seam, the oil and
                gas operator must notify the state and the coal company to permit
                representatives to be present at the plugging.

                In addition, all six states have programs to plug wells that were improperly
                plugged and have been abandoned, though their level of activity varies.
                For example, state regulators in Texas said that the primary objective of
                their program, which began in 1983, is to plug abandoned oil and gas
                wells that are causing pollution or threatening to cause pollution for which
                a responsible operator does not exist; the responsible operator failed to
                plug the well; or the responsible operator failed to otherwise bring the
                wells into compliance. As of 2009, Texas state regulators had plugged
                30,000 wells, and approximately 8,000 potentially abandoned wells
                remained throughout the state. Officials stated, however, that many of


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




                Page 56                              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.

Site Reclamation       All six states in our review have requirements for site reclamation, though
                       the extent of the requirements varies. Five states—Colorado, Ohio, North
                       Dakota, Pennsylvania, and Wyoming—have requirements both for
                       backfilling soil and for revegetating areas. For example, in Colorado, final
                       reclamation must generally be complete within 3 months of plugging a
                       well on crop land and within 12 months on noncrop land. Reclamation in
                       Colorado involves returning segregated soil horizons to their original
                       relative positions; 79 returning crop land to its original contour; as near as
                       practicable, returning noncrop land to its original contour to achieve
                       erosion control and long-term stability; and adequately tilling to establish
                       a proper seedbed. In Wyoming, operators must begin reclamation within
                       1 year of permanent abandonment of a well or last use of a pit and in
                       accordance with the landowner’s reasonable requests, or to resemble the
                       original vegetation and contour of adjoining lands. In addition, where
                       practical, topsoil must be stockpiled during construction for use in
                       reclamation. Texas has requirements for contouring soil, but we did not
                       identify requirements for revegetating the area.

                       For more details about state site reclamation requirements, see
                       appendix IX.

Waste Management and   All six states in our review have some requirements regarding waste
Disposal               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



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




                       Page 57                                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 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



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




Page 58                              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 in doing so, the states must apply, where applicable,
EPA’s effluent limitations guidelines discussed above. According to state
regulators in Wyoming, the state has about 1,000 currently active permits
for discharges of produced water from coalbed methane formations and
500 permits for produced water from conventional formations. In contrast,
state regulators in North Dakota said that there are no direct surface
discharges of produced water in their state because the produced water
is too salty.

Some states, such as Colorado and Pennsylvania, also have commercial
facilities, which treat produced water before discharging it to surface
waters. In addition, disposal to a POTW is an option in Ohio and


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




Page 59                              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 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


82
  As discussed earlier in this report, EPA sets pretreatment standards that apply when
wastewater is sent to a facility—such as an industrial treatment facility or POTW—before
being discharged to surface waters. To date, EPA has not set pretreatment standards
specifically for produced water, though there is a general requirement that discharges to
POTWs cannot cause the POTW to violate its own NPDES permit or interfere with
treatment processes.
83
 The federal secondary standard for drinking water is 500 milligrams per liter.
84
  Ohio law provides that, generally, produced water must be disposed of only by
underground injection, by surface application, in association with enhanced recovery of oil
or gas resources from a well, or by other methods approved by the Chief of the Division of
Oil and Gas Resources Management within the Ohio Department of Natural Resources for
testing or implementing a new technology or method of disposal. Ohio Rev. Code Ann. §
1509.22(C)(1) (2012). According to OEPA officials, the permit did not involve an approved
test or implementation of a new technology or method of disposal.
85
  Patriot Water Treatment, LLC v. Korleski, ERAC case Nos. 156477, 156588, 786501,
and 786589 (2012).




Page 60                               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 In addition, state regulators in
Pennsylvania said that the best option for dealing with produced water in
the state is recycling, and the Department of Environmental Protection
can track what percentage of recycled water was used in hydraulic
fracturing based on information required on well completion reports.
Approximately 90 percent of produced water in Pennsylvania is recycled,
according to state regulators. The Texas Railroad Commission has
approved several recycling projects in the Barnett Shale to reduce the
amount of fresh water used in development activities there. Four of the
six states—Colorado, North Dakota, Ohio, and Wyoming—also allow
operators to reuse certain types of fluid waste for road applications. For
example, in Ohio, produced water, excluding flowback from hydraulic
fracturing, may be used for dust and ice suppression on roads with the
approval of local governments; approximately 1 percent of produced
water is used in this way. In Wyoming, road and land applications may be
permitted as reuses of produced water. North Dakota allows road but not
land application of produced water.

Regulatory agencies in all six states implement requirements for the
disposal of waste such as drill cuttings. For example, in Colorado, drill
cuttings may be buried in pits at the well site, an activity which is regulated
by the Colorado Oil and Gas Conservation Commission. Drill cuttings taken
off site for disposal at a commercial waste facility must comply with the
regulations of the state’s Department of Public Health and Environment that
govern those facilities. Texas allows drill cuttings to be landfarmed on the
well site where they were generated with the written permission of the



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




Page 61                             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 Texas allows
on-site burial of drill cuttings that were obtained using drilling fluids with a
chloride concentration in excess of 3,000 milligrams per liter. In North
Dakota, operators frequently bury drill cuttings on-site where the North
Dakota Industrial Commission’s Oil and Gas Division has authority, but, in
some cases, the drill cuttings may be disposed of at a landfill under the
jurisdiction of the Department of Health due to shallow groundwater or
permeable subsoil.

As discussed earlier in this report, officials in the six states we reviewed
were not aware of any oil or gas well sites that would be regulated as
small-quantity generators of hazardous waste under RCRA. Pursuant to
RCRA, regulation of waste that is not considered hazardous is largely a
state responsibility. Some states have special categories of waste and
associated additional requirements that apply to industrial wastes
generally, or oil and gas wastes specifically. For example, waste from
crude oil and natural gas exploration and production in North Dakota is
called special waste. Special waste landfills must be permitted and
comply with specific design standards. Currently, there are four special
waste landfills in North Dakota with another five proposed special waste
landfills at the beginning stages of the permitting process. State
regulators said that special waste consists mostly of drill cuttings but can
also include other things such as contaminated soil. In Pennsylvania, oil
and gas waste falls into a category of waste called residual waste that
applies to, among other things, certain wastes from industrial, mining, or
agricultural operations. Residual waste disposal must be permitted and is
subject to processing and storage rules.

All six states in our review have requirements for managing and disposing
of wastes, such as oilfield equipment, drilling solids, and produced water
that have been exposed to or contaminated with naturally-occurring




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




Page 62                               GAO-12-874 Unconventional Oil and Gas Development
                         radioactive material (NORM) or technologically-enhanced NORM. 88 NORM
                         occurs naturally in some geologic formations that also contain oil or gas
                         and when NORM is brought to the surface during drilling and production, it
                         remains in drill cuttings and produced water and, under certain conditions,
                         creates scales or deposits on pipes or other oilfield equipment. Officials at
                         the Colorado Department of Public Health and Environment said that they
                         set tiers for how to manage materials that contain NORM based on their
                         level of radioactivity. In addition, they said that the department is working
                         with the Colorado Oil and Gas Conservation Commission to require
                         operators to perform certain tests on produced water before allowing
                         produced water to be used for road application. Texas officials said that the
                         state requires operators to identify NORM-contaminated equipment with
                         the letters “NORM” by securely attaching a clearly visible waterproof tag or
                         marking with a legible waterproof paint or ink. In addition, Texas requires
                         operators to dispose of oil and gas NORM waste by methods that are
                         specifically authorized by rule or specifically permitted. State regulators in
                         Wyoming said that a lot of NPDES permits for direct discharges to surface
                         waters have limits on radioactivity that would probably lead the operator to
                         dispose of produced water contaminated with NORM in a Class II UIC well.

                         For more details about states waste management and disposal
                         requirements, see appendix IX.

Managing Air Emissions   Five of the six states we reviewed have permitting or registration
                         requirements for managing air emissions from oil and gas production
                         sites. In addition, all six states have requirements related to venting and
                         flaring of gas and limiting or managing emissions of hydrogen sulfide—a
                         hazardous and deadly gas—at drilling sites.

                         Five of the six states we reviewed —Colorado, North Dakota, Ohio,
                         Texas, and Wyoming—have developed permitting or registration
                         requirements that apply to oil and gas development. For example,
                         according to state regulators, the vast majority of production wells in
                         Colorado require air permits. Operators with certain condensate tanks
                         and tank batteries are required to obtain a permit if the tanks have
                         uncontrolled actual emissions of volatile organic compounds greater than
                         or equal to 2 tons per year in areas which are not attaining certain air


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




                         Page 63                               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 64                         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.


Regional Commission     One of the states in our review—Pennsylvania—is also part of a regional
Implements Additional   commission that implements additional requirements governing several
Requirements            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


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




                        Page 65                               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.


States Have Recently   All six states in our review have updated some aspects of their
Updated Some           requirements in recent years. Key examples include the following:
Requirements
                       •   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




                       Page 66                        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 67                         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
Additional           Management (BLM), Forest Service, National Park Service, and Fish and
Requirements Apply   Wildlife Service (FWS) manage federal lands for a variety of purposes.
                     Specifically, both the Forest Service and BLM manage their lands for
on Federal Lands     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.




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




                     Page 68                              GAO-12-874 Unconventional Oil and Gas Development
Requirements for                 Requirements for operators developing federally owned mineral rights are
Federally Owned Mineral          imposed by federal agencies during planning and leasing processes
Rights                           carried out by federal agencies. Operators must also meet specific
                                 requirements during several of the activities involved in oil and gas
                                 development.

Planning and Leasing Processes   BLM has primary authority for issuing leases and permits for federal oil
                                 and gas resources even in cases when surface lands are managed by
                                 other federal agencies or owned by private landowners. The majority of
                                 federal oil and gas leases underlie lands managed by BLM or the Forest
                                 Service, but there are some federal oil and gas resources available for
                                 leasing under lands managed by other federal agencies or private
                                 landowners. 91 Altogether, BLM oversees oil and gas development on
                                 approximately 700 million subsurface acres.

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




                                 91
                                    BLM has also issued leases that underlie lands managed by the Park Service and FWS.
                                 These lands are generally not available for oil and gas development except in special
                                 circumstances. For example, FWS lands may be leased if an oil and gas operation outside
                                 of FWS lands is draining federal minerals under the FWS land. For the Park Service, small
                                 portions of three units of the National Park system are also open to federal mineral leasing
                                 based on their enabling legislation: Glen Canyon National Recreation Area, Lake Mead
                                 National Recreation Area, and Whiskeytown National Recreation Area. Currently, there are
                                 no parcels under lease in these areas. In order for oil and gas development to occur in these
                                 areas, the National Park system regional director must consent to the lease and permit, and
                                 can do so only upon determination that the activity permitted will not have significant adverse
                                 effect upon the resources or administration of the unit. (43 C.F.R. § 3109.2(b)). Three other
                                 units have a total of 16 wells under leases predating these policies.
                                 92
                                   Pub. L. No. 91-190 (1970), codified as amended at 42 U.S.C. §§ 4321-4347 (2012).




                                 Page 69                                GAO-12-874 Unconventional Oil and Gas Development
                                         either an environmental assessment or environmental impact statement. 93
                                         After the planning process, BLM takes the lead in preparing the NEPA
                                         analysis for leases when the surface lands are managed by BLM or
                                         owned by a private landowner (see table 6). For Forest Service lands, the
                                         Forest Service takes the lead in preparing the NEPA analysis and
                                         coordinates with BLM so that BLM’s subsequent leasing decision can be
                                         supported by the same analysis. At both agencies the NEPA review
                                         focuses on how the sale of leases may affect the environment and public
                                         health and, according to BLM officials, often includes mitigation measures
                                         that ultimately become stipulations on leases and permits for that tract of
                                         federal land. After the environmental impact statement is completed, BLM
                                         sells the lease to an operator through an auction or by other means.

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

Surface land             Availability for oil and gas
management agency        development                      Role in approving leases                 Role in approving drilling permits
                                             a
BLM                      Generally available              BLM is primary authority for             BLM is primary authority for
                                                          approving leases                         approving drilling permits
Forest Service           Generally availableb             Coordinates with BLM regarding    Forest Service must approve all
                                                          surface issues and must authorize surface disturbing activities before
                                                          the lease                         BLM approves the drilling permit.
Private Landowner        Generally available              No specific role; may participate in Operator generally must reach
                                                          public comment process               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.




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




                                         Page 70                                   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 71                                    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.

Requirements Related to Oil   Operators of wells accessing federal oil and gas also face requirements
and Gas Development           related to activities involved in oil and gas development. Specifically,
Activities                    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



                              Page 72                          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


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




Page 73                              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.


Requirements for Privately   Subject to some restriction, owners of mineral rights that underlie federal
Owned Mineral Rights         lands have the legal authority to explore for oil and gas and, if such
under Federal Surface        resources are found, to develop them. 95 Federal land management
                             agencies’ authorities to control the surface impacts of drilling for privately
Lands
                             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 BLM-
                             managed surface lands. Officials said that BLM would have the same
                             rights as a private surface owner under state law to hold a mineral rights
                             owner to “reasonable surface use.” BLM officials explained that BLM
                             would perform a NEPA analysis prior to issuing the right-of-way grant.
                             According to officials, the agency applies its general regulations for
                             granting rights of way, but BLM did not have specific guidance regarding
                             oversight of private mineral operations on BLM lands.

                             According to Forest Service officials, Forest Service authority related to
                             the development of privately owned minerals is limited because private
                             mineral owners have the legal right to develop such resources. The


                             95
                                In implementing requirements on the development of private mineral rights, agencies
                             must consider the potential applicability of the Fifth Amendment to the U.S. Constitution.
                             The Fifth Amendment prohibits the federal government from taking private property for
                             public use without justly compensating the private property owner. Government regulation
                             may place restrictions on the use of property to the extent that it deprives the owner of its
                             use or economic value. In such cases of “regulatory taking,” the owner may be entitled to
                             just compensation under the Fifth Amendment. Thus, if agency requirements “regulated”
                             the mineral rights to the point that they were deemed to be taken, the agency would have
                             to compensate the owner. See, e.g., Foster v. United States, 607 F.2d 943 (Ct. Cl. 1979)
                             (government’s refusal to allow permit holders of mineral interest on government land any
                             right of access for the purpose of extracting minerals was a compensable taking).
                             96
                               In addition, an agency’s authority may vary depending on whether the private rights
                             were severed from the surface land before the land was conveyed to the United States, or
                             were retained by the owner who conveyed the land to the United States; whether the
                             lands in question are public domain or acquired; and on other factors.




                             Page 74                                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 three-
fourths are producing privately owned minerals. 97 Forest Service officials
explained that the Forest Service evaluates the effects of the
development and, through negotiations with the operator, tries to reach
agreement on certain mitigation measures. Officials explained that these
mitigation measures are generally not as stringent or specific as
mitigation measures used on federal leases. In addition, Forest Service
officials explained that enforcement options are limited for environmental
damage from development of privately owned minerals. Generally, the
Forest Service can work with state oil and gas agencies to have them
enforce any relevant state requirements regarding surface impacts, or the
Forest Service can seek an injunction from the court to stop damaging
actions and then pursue possible damages or restitution via the court.
According to Forest Service officials, development of privately owned
minerals has been a particular challenge in the Alleghany National Forest
in Pennsylvania where privately owned minerals underlie more than 90
percent of the forest. Forest Service officials stated that there are
approximately 1,000 new wells drilled in this forest each year, most of
which are shallow conventional oil development. Officials said that the
pace of this development has made it difficult for the Forest Service to
manage other forest uses, such as recreation and timber extraction.

Regarding lands managed by FWS, we reported in August 2003 that
oversight and management of oil and gas activities varies widely among
wildlife refuges. 98 We noted that some refuges issue permits that
establish operating conditions for oil and gas activities, which give these
refuges greater control over oil and gas activities and protect refuge
resources; other refuges exercise little control or enforcement over oil and
gas activities. According to FWS officials, this situation persists today,


97
  According to Forest Service officials, private mineral ownership is more common in the
eastern United States because most eastern forest lands were acquired through the 1911
Weeks Act, which had different stipulations for mineral rights of lands conveyed to the
Forest Service. See also Minard Run v. U.S. Forest Service, 2009 WL 4937785 at *3
(W.D.Pa.) (discussing the Weeks Act); and GAO, Private Mineral Rights Complicate the
Management of Eastern Wilderness Areas, GAO/RCED-84-101 (Washington, D.C.: July
26, 1984).
98
  See GAO, National Wildlife Refuges: Opportunities to Improve the Management and
Oversight of Oil and Gas Activities on Federal Lands, GAO-03-517 (Washington, D.C.:
Aug. 28, 2003).




Page 75                              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 For example, FWS worked with EPA to respond to a spill
of produced water into a stream on a National Wildlife Refuge in
Louisiana in 2005, in violation of CWA. EPA, the Coast Guard, and the
Department of Justice worked together on the case, and the operator
ultimately paid $425,000 to FWS for the two affected wildlife refuges.
According to agency officials, however, without specific regulations, FWS
faces challenges conducting daily management and oversight of oil and
gas activities on FWS lands.

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




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




Page 76                               GAO-12-874 Unconventional Oil and Gas Development
                            Federal and state agencies reported facing several challenges in
Federal and State           regulating oil and gas development from unconventional reservoirs.
Agencies Reported           Specifically, EPA officials reported that their ability to conduct inspection
                            and enforcement activities and limited legal authorities are challenges. In
Several Challenges          addition, BLM and state officials reported that hiring and retaining staff
Regulating                  and educating the public are challenges.
Unconventional Oil
and Gas Development

Conducting Inspection and   Officials at EPA reported that conducting inspection and enforcement
Enforcement Activities      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 These officials also said that linking groundwater
                            contamination to a specific activity may be difficult even in cases where
                            baseline data are available because of the variability and complexity of
                            geological formations.

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


                            100
                              As discussed earlier in this report, three of the six states we reviewed—Colorado, Ohio,
                            and Pennsylvania—have requirements that encourage or require operators to conduct
                            baseline water testing in certain cases.
                            101
                               As discussed earlier in this report, in 2005, the Energy Policy Act amended SDWA to
                            specifically exempt hydraulic fracturing from the UIC program, unless diesel fuel is used in
                            the hydraulic fracturing process.




                            Page 77                               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 headquarters officials also mentioned that many oil and
gas production sites are not continuously staffed, so EPA needs to
contact operators and ensure that someone will be present before visiting
a site to conduct an inspection. Officials in EPA Region 6 said that the
dispersed nature of the industry, the high level of oil and gas development
in the Region, and the cost of travel have made it difficult to conduct
enforcement activities in their Region.

EPA officials in headquarters said that SDWA is a difficult statute to
enforce because of the variation across states. Specifically, SDWA
authorizes EPA to approve, for states that elect to assume this
responsibility, individual states’ programs as alternatives to the federal
UIC Class II regulatory program. As a result, EPA’s enforcement actions
have to be specific to each state’s program, which increases the
complexity for EPA. In addition, SDWA requires that EPA approve each
state’s UIC program by regulation rather than through an administrative
process, and many of the federal regulations for state UIC programs are
out of date. EPA officials said that this has hindered enforcement efforts,
and some cases have been abandoned because EPA can only enforce



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




Page 78                             GAO-12-874 Unconventional Oil and Gas Development
                             those aspects of state UIC regulations that have been approved by
                             federal regulation.


Limited Legal Authorities    EPA officials also reported that the scope of their legal authorities for
                             regulating oil and gas development is a challenge. For example, EPA
                             officials in headquarters and Regional offices told us that the exclusion of
                             exploration and production waste from hazardous waste regulations
                             under RCRA significantly limits EPA’s role in regulating these wastes. For
                             example, if a hazardous waste permit was required, then EPA would
                             obtain information on the location of well sites, how much hazardous
                             waste is generated at each site, and how the waste is disposed of;
                             however, operators are not required to obtain hazardous waste permits
                             for oil and gas exploration and production wastes, limiting EPA’s role. 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


Hiring and Retaining Staff   Officials at BLM, Forest Service, and state agencies reported challenges
                             hiring and retaining staff. For example, BLM officials in North Dakota said
                             recruiting is a challenge because the BLM pay scale is relatively low
                             compared with the current cost of living near the oil fields in the Bakken
                             formation. Similarly, BLM officials in North Dakota and headquarters both
                             said that retaining employees is difficult because qualified staff are
                             frequently offered more money for private sector positions within the oil
                             and gas industry. BLM officials in Wyoming told us that their challenges
                             related to hiring and retaining staff have made it difficult for the agency to
                             keep up with the large number of permit requests and meet certain
                             inspection requirements. We previously reported that BLM has



                             103
                                EPA officials said that, at present, they could specifically request this type of
                             information, but do not receive it automatically.
                             104
                               EPA Region 8 includes Colorado, Montana, North Dakota, South Dakota, Utah, and
                             Wyoming.




                             Page 79                                 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.


Public Education   BLM and state officials reported that providing information and education to
                   the public is a challenge. Specifically, BLM headquarters officials
                   mentioned that hydraulic fracturing has attracted the interest of the public



                   105
                      GAO, Oil and Gas Management: Interior’s Oil and Gas Production Verification Efforts
                   Do Not Provide Reasonable Assurance of Accurate Measurement of Production Volumes,
                   GAO-10-313 (Washington, D.C.: Mar. 15, 2010).
                   106
                     GAO, Oil and Gas Leasing: Past Work Identifies Numerous Challenges with Interior’s
                   Oversight, GAO-11-487T (Washington, D.C.: Mar. 17, 2011).




                   Page 80                             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
Agency Comments      Agriculture and the Interior for review and comment. The Departments of
and Our Evaluation   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.




                     Page 81                         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 82                        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




Page 83                      GAO-12-874 Unconventional Oil and Gas Development
Appendix I: Objectives, Scope, and
              Appendix I: Objectives, Scope, and
              Methodology



Methodology

              To identify federal and state environmental and public health
              requirements governing onshore oil and gas development from
              unconventional reservoirs, we analyzed federal and state laws,
              regulations, and guidance, as well as reports on federal and state
              requirements. We defined unconventional reservoirs as including shale
              gas deposits, shale oil, coalbed methane, and tight sandstone formations.
              We focused our analysis on requirements that apply to activities on the
              well pad and wastes or emissions generated at the well pad rather than
              on downstream infrastructure such as pipelines or refineries. In particular,
              we identified and reviewed eight key federal environmental and public
              health laws, specifically the Safe Drinking Water Act; Clean Water Act;
              Clean Air Act; Resource Conservation and Recovery Act; Comprehensive
              Environmental Response, Compensation, and Liability Act; Emergency
              Planning and Community Right-to-Know Act; Toxic Substances Control
              Act; and Federal Insecticide, Fungicide, and Rodenticide Act. We also
              reviewed corresponding regulations such as the Environmental Protection
              Agency’s (EPA) New Source Performance Standards and National
              Emission Standards for Hazardous Air Pollutants for the Oil and Gas
              Industry and guidance such as EPA’s Guidance for Implementation of the
              General Duty Clause of the Clean Air Act.

              To identify state requirements, we identified and reviewed laws and
              regulations in a nonprobability sample of six selected states—Colorado,
              North Dakota, Ohio, Pennsylvania, Texas and Wyoming. We selected
              states with current unconventional oil or gas development and large
              reservoirs of unconventional oil or gas. In addition, we ensured that the
              selected states included a variety of types of unconventional reservoirs,
              differing historical experiences with the oil and gas industry, and that
              some of the selected states have significant oil and gas development on
              federal lands. Because we used a nonprobability sample, the information
              that we collected from those states cannot be generalized to all states but
              can provide illustrative examples.

              To complement our analysis of federal and state laws and regulations, we
              interviewed officials in federal and state agencies to discuss how federal
              and state requirements apply to the oil and gas industry (see table 7). In
              particular, we interviewed officials in EPA headquarters and four Regional
              offices where officials are responsible for implementing and enforcing
              programs within the six states we selected, including Region 3 for
              Pennsylvania, Region 5 for Ohio, Region 6 for Texas, and Region 8 for
              Colorado, North Dakota, and Wyoming. We also interviewed state
              officials responsible for implementing and enforcing requirements
              governing the oil and gas industry and environmental or public health


              Page 84                              GAO-12-874 Unconventional Oil and Gas Development
                                          Appendix I: Objectives, Scope, and
                                          Methodology




                                          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                               •    Bureau of Land Management (BLM) headquarters
•  EPA Office of Chemical Safety and Pollution Prevention        •    BLM Colorado State Office
•  EPA Office of Enforcement and Compliance Assurance            •    BLM Dickinson, North Dakota Field Office
•  EPA Office of General Counsel                                 •    BLM Wyoming State Office
•  EPA Office of the Inspector General                           •    Fish and Wildlife Service
•  EPA Office of Solid Waste and Emergency Response              •    Forest Service
•  EPA Office of Research and Development                        •    National Park Service
•  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)




                                          Page 85                              GAO-12-874 Unconventional Oil and Gas Development
                                             Appendix I: Objectives, Scope, and
                                             Methodology




State and regional agencies
•   Colorado Oil and Gas Conservation Commission                    •    Ohio Environmental Protection Agency
•   Colorado Department of Public Health and Environment            •    Division of Air Pollution Control
•   Air Pollution Control Division                                  •    Division of Drinking and Ground Waters
•   Hazardous Materials and Waste Management Division               •    Division of Materials and Waste Management
•   Water Quality Control Division                                  •    Division of Surface Water
•   Delaware River Basin Commission                                 •    Pennsylvania Department of Environmental Protection, Office
•   Ground Water Protection Council                                      of Oil and Gas Management
•   North Dakota Industrial Commission, Oil and Gas Division        •    Railroad Commission of Texas, Oil and Gas Division
•   North Dakota Department of Health, Environmental Health         •    Texas Commission on Environmental Quality
    Section                                                         •    Office of Air
•   Air Quality Division                                            •    Office of Compliance and Enforcement
•   Waste Management Division                                       •    Office of Legal Services
•   Municipal Facilities Division                                   •    Office of the Executive Director
•   Ohio Department of Natural Resources, Division of Oil and       •    Wyoming Oil and Gas Conservation Commission
    Gas Resources Management                                        •    Wyoming Department of Environmental Quality
                                                                    •    Air Quality Division
                                                                    •    Water Quality Division
                                                                    •    Solid and Hazardous Waste Division
Environmental organizations
•   Dakota Resource Council                                         •    Earthworks, Oil and Gas Accountability Project
•   Earthjustice                                                    •    Pennsylvania Environmental Council
Public Health organizations
•  American Lung Association                                        •    National Association of County and City Health Officials
•  Association of State and Territorial Health Officials            •    Southwest Pennsylvania Environmental Health Project
•  Council of State and Territorial Epidemiologists                 •    Trust for America’s Health
Companies and industry organizations
•  American Petroleum Institute                                     •    Independent Petroleum Association of America
•  Chesapeake Energy Corporation                                    •    North Dakota Petroleum Council
•  EOG Resources, Inc.
                                             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



                                             Page 86                               GAO-12-874 Unconventional Oil and Gas Development
Appendix I: Objectives, Scope, and
Methodology




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 also collected testimonial evidence, as
described above, from knowledgeable federal and state officials, as well
as industry, environmental, and public health organizations.

We conducted this performance audit from November 2011 to September
2012 in accordance with generally accepted government auditing
standards. Those standards require that we plan and perform the audit to
obtain sufficient, appropriate evidence to provide a reasonable basis for
our findings and conclusions based on our audit objectives. We believe
that the evidence obtained provides a reasonable basis for our findings
and conclusions based on our audit objectives.




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.




Page 87                              GAO-12-874 Unconventional Oil and Gas Development
Appendix II: Key Requirements and
                    Appendix II: Key Requirements and Authorities
                    under the Safe Drinking Water Act



Authorities under the Safe Drinking Water
Act
                    The Safe Drinking Water Act (SDWA or the Act) was originally passed by
                    Congress in 1974 to protect public health by ensuring a safe drinking
                    water supply. 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         underground through the Underground Injection Control (UIC) program. 2
Injection Control   This program provides safeguards to ensure that wastewater or any other
Program             fluid injected underground does not endanger underground sources of
                    drinking water; these sources are defined by regulation as an aquifer or
                    its portion:

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

                        (ii) Which contains a sufficient quantity of groundwater to supply a
                        public water system; and (A) Currently supplies drinking water for
                        human consumption; or (B) Contains fewer than 10,000 mg/l total
                        dissolved solids; and

                    2) Which is not an exempted aquifer. 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 In particular,
                    the regulations establish that the criterion that an aquifer “cannot now and



                    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.
                    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).




                    Page 88                              GAO-12-874 Unconventional Oil and Gas Development
Appendix II: Key Requirements and Authorities
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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 EPA is currently collecting information about the
location of all exempted aquifers, and an official estimated that there are
1,000-2,000 such designations (including portions of aquifers).

There are six classes or categories of wells regulated through the UIC
program. 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 A state with an approved
program assumes responsibility for implementing the program, including



5
40 C.F.R. § 146.4 (2012).
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).




Page 89                              GAO-12-874 Unconventional Oil and Gas Development
Appendix II: Key Requirements and Authorities
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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 With respect to the six states in this review, Texas, North
Dakota, Colorado, Wyoming, and Ohio have each been granted primacy
for Class II wells under the alternative provisions (SDWA section 1425).
EPA directly implements the entire UIC program in Pennsylvania.

Class II wells include saltwater (brine) disposal wells, enhanced recovery
wells, and hydrocarbon storage wells. These wells are common,
particularly in states with historical oil and gas activity. EPA officials
estimate there are approximately 151,000 Class II UIC wells in operation
in the United States; about 80 percent of these wells are for enhanced
recovery, about 20 percent are for disposal, and there are approximately
100 wells for hydrocarbon storage. In Pennsylvania, the one state in our
review in which EPA directly implements the Class II program, EPA
Region 3 officials stated that there are five active Class II disposal wells.
Recently, Region 3 issued permits for two Class II disposal wells in
Pennsylvania, which were appealed. On appeal, the Environmental
Appeals Board remanded the permits back to EPA for further
consideration, finding that the Region failed to clearly articulate its
regulatory obligations or compile a record sufficient to assure the public



10
   SDWA § 1425, 42 U.S.C. § 300h-4 (2012). As explained by EPA, under this alternative
approval “instead of meeting the Federal Regulations (40 C.F.R. Parts 124, 144, and 145)
and related Technical Criteria and Standards (40 C.F.R. Part 146), a State may
demonstrate that its program meets the more general statutory requirements of Section
1421(b)(1)(A) through (D) and represents an effective program to prevent endangerment
of underground sources of drinking water.” See, e.g., 49 Fed. Reg. 13,040 (Apr. 2, 1984)
(EPA approval of Colorado application). Thus, among other things, the state program
must include adequate recordkeeping and reporting. The statute also provides that
“[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).




Page 90                               GAO-12-874 Unconventional Oil and Gas Development
                            Appendix II: Key Requirements and Authorities
                            under the Safe Drinking Water Act




                            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.


Class II UIC Requirements   Under SDWA, UIC programs are to prohibit underground injection, other
                            than into a well that is authorized by rule or permitted. 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
                            Permits may be conditioned upon a compliance schedule for such
                            corrective actions. According to EPA, in Pennsylvania many old wells




                            11
                             See Environmental Appeals Board, Order, UIC Appeal No. 11-03 (June 28, 2012).
                            12
                             Id.
                            13
                              SDWA §§ 1421(b)(1)(A), 1422(c), 42 U.S.C. §§ 300h(b)(1)(A) (state programs), 300h-
                            1(c) (EPA direct implementation programs); 40 C.F.R. § 144.11 (2012).
                            14
                             See 40 C.F.R. pt. 144 (2012).
                            15
                             40 C.F.R. §§ 146.21 – 146.24 (2012).
                            16
                             40 C.F.R. §§ 146.24, 146.6 (2012).
                            17
                             40 C.F.R. §§ 144.55(a), (b)(2)-(3); 146.7 (2012).




                            Page 91                               GAO-12-874 Unconventional Oil and Gas Development
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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 Officials said that if a seismic event occurs along a fault
line that was not identified or known at the time of the UIC permit
approval, EPA (in direct implementation states) or the state can go back
to the well owner or operator and ask for additional information, which the
owner or operator would be obligated to provide.

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




18
 See Karen Johnson, Chief, Ground Water & Enforcement Branch, EPA Region 3,
Marcellus Shale Educational Webinar, Feb. 18, 2010 (written Q&A).
19
 40 C.F.R. §§ 146.24, 146.24(a)(2) (2012).
20
 40 C.F.R. § 146.22(a) (2012).
21
 See 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).




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Class II UIC Programs and   Historically, UIC programs did not include hydraulic fracturing injections as
Hydraulic Fracturing        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
                            EPA officials said the study showed diesel fuel was the primary risk.
                            Subsequently, in 2003, EPA entered into a memorandum of agreement



                            23
                              See, e.g., Legal Envtl. Assistance Found. Inc. v. EPA, 118 F.3d 1467, 1471 (11th
                            Cir.1997).
                            24
                             Id.
                            25
                             Ala. Admin. Code r. 400-4-5-.04 (filed July 9, 1999; amended Nov. 9, 1999; repealed
                            Apr. 11, 2000).
                            26
                              65 Fed. Reg. 2889 (Jan. 19, 2000); 40 C.F.R. § 147.52 (2012). In May 2000, Alabama
                            repealed the hydraulic fracturing regulations at 400-4-5-.04 and established regulations at
                            400 -3-8-.03. EPA’s regulations reference the state’s repealed regulations.
                            27
                             Legal Envtl. Assistance Found. Inc. v. EPA, 276 F.3d 1253 (11th Cir. 2001).
                            28
                             See Ala. Admin. Code r. 400 -3-8-.03.
                            29
                             69 Fed. Reg. 42,341 (July 15, 2004) (referencing Alabama rule 400 -3-8-.03).
                            30
                              EPA, Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic
                            Fracturing of Coalbed Methane Reservoirs, EPA 816-R-04-003 (2004).




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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 According to EPA officials, the agreement is still in effect
insofar as the agency has not received any termination notices.

EPA officials did not know of any permits issued by Alabama, or any other
state, for hydraulic fracturing injections during this time frame. EPA also
did not modify its direct implementation of Class II UIC programs to
expressly include hydraulic fracturing.

On December 7, 2004, EPA’s Assistant Administrator for Water
responded to a congressional request for information on EPA’s actions on
this issue. 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 2005 34 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



31
  Memorandum of Agreement Between the United States Environmental Protection
Agency and BJ Services Company, Halliburton Energy Services, Inc., and Schlumberger
Technology Corporation, Elimination of Diesel Fuel in Hydraulic Fracturing Fluids Injected
into Underground Sources of Drinking Water During Hydraulic Fracturing of Coalbed
Methane Wells 4(a) (Dec. 12, 2003).
32
  151 Cong. Rec. S7277 (daily ed. June 23, 2005) (letter of Benjamin Grumbles, Assistant
Administrator, Office of Water, EPA, to Senator Jeffords).
33
 Id.
34
  Pub. L. No. 109–58 § 322, 119 Stat. 594 (2005) (modifying SDWA § 1421(d)(1), 42
U.S.C. § 300h(d)(1) (2012)).




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              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’s draft guidance is applicable
              to any oil and gas wells using diesel in hydraulic fracturing (not just
              coalbed methane wells). The draft guidance provides recommendations
              related to permit applications, area of review (for other nearby wells), well
              construction, permit duration, and well closure. The guidance states that it
              does not address state UIC programs, although states may find it useful.

              EPA officials told us that they recently identified wells for which publicly
              available data suggest diesel was used in hydraulic fracturing. EPA
              officials stated the agency also has some information on diesel use in
              hydraulic fracturing of shale formations from a 2011 congressional
              investigation. EPA officials said there are no EPA-issued permits
              authorizing diesel to be used in hydraulic fracturing, and they believe no
              applications for such permits have been submitted to EPA to date. EPA
              officials also said that they were not aware of any state UIC programs that
              had issued such permits.


Enforcement   Generally, EPA is authorized to enforce any applicable requirement of a
              federal or state UIC program as promulgated in 40 C.F.R. pt. 147,
              including Class II UIC programs approved under the alternative




              35
                EPA, Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel
              Fuels—Draft: Underground Injection Control Program Guidance #84 (May 2012 draft); see
              also 77 Fed. Reg. 27,451 (May 10, 2012) (announcing availability of the draft for public
              comment).
              36
               77 Fed. Reg. at 27,452.




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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 In another



37
  SDWA requires that EPA approve state programs and revisions by regulation, in part
147 (rather than through an administrative process). SDWA § 1422(b)(2), (4), 42 U.S.C. §
300h-1(b)(2),(4) (2012).
38
  For federal regulations setting forth EPA-approved state programs, see 40 C.F.R. pt.
147 (2012).
39
 SDWA § 1423(a), 42 U.S.C. § 300h-2(a) (2012).
40
 SDWA § 1423(a)(1), 42 U.S.C. § 300h-2(a)(1) (2012).
41
 SDWA § 1445(b)(1), 42 U.S.C. § 300j-4(b)(1) (2012).
42
  Titusville Oil and Gas, Docket No. SDWA-03-20,11-0170 (July 19, 2011). EPA Region 3
officials noted that Pennsylvania Department of Environmental Protection also issued
several orders at the site, and that the wells are being plugged.




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               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
Imminent and   may pose risk to drinking water supplies, 44 SDWA gives EPA authority to
Substantial    issue imminent and substantial endangerment orders or take other
Endangerment   actions deemed necessary “upon receipt of information that a
               contaminant which is present in or is likely to enter a public water system
Authorities    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 As noted above, the term “underground source
               of drinking water” includes not only active water supplies but also aquifers
               (or portions thereof) with certain physical characteristics.

               EPA has used this imminent and substantial endangerment authority in
               several incidents where oil or gas wells have been alleged to contaminate
               drinking water. For example, EPA Region 8 has conducted long-term
               investigation and monitoring of groundwater contamination from an oilfield
               in Poplar, Montana, of a water supply serving Poplar, as well as the Fort
               Peck Indian Reservation. EPA determined that there are several plumes of
               produced water (brine) in the East Poplar aquifer, which supplies private
               and public drinking water wells. Several pathways of contamination have
               been identified, including unlined pits, spills, and a leaking plugged oil well.



               43
                 In the Matter of EXCO Resources (PA) LLC, Consent Agreement, EPA Docket No.
               SDWA-03-2012-0061 (Mar. 30, 2012).
               44
                 SDWA includes nonregulatory provisions addressing protection of drinking water
               supplies, such as providing incentives and assistance for states and public water systems
               to conduct water quality protection planning. See, e.g., SDWA § 1429, 42 U.S.C. § 300h-8
               (2012).
               45
                SDWA § 1431, 42 U.S.C § 300i(a) (2012).




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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




46
  EPA, Fort Peck East Poplar Oil Field Safe Drinking Water Act Emergency Administrative
Order on Consent, Docket No. SDWA-08-20 12-0019 (Mar. 26, 2012); see also EPA,
Emergency Administrative Order, Docket No. SDWA-08-2011-0006 to Murphy Exploration
& Production Co.-USA, Pioneer Natural Resources USA, Inc., and SGH Enterprises, Inc.
(Dec. 16, 2010).
47
 In the Matter of Range Resources Corporation, Administrative Order, EPA Docket No.
SDWA-06-2011-1208 (Dec. 7, 2010).
48
 United States v. Range Production Co., No. 3:11-cv-00116-F (N.D. Tex. Jan. 18, 2011).
49
  Brief, Range Resources Corporation, et al. v. EPA, No. 11-60040 (5th Cir. Mar. 22,
2011).
50
  See Joint Stipulation of Dismissal Without Prejudice, United States v. Range Production
Co., No. 3:11-CV-00116-F (N.D. Texas Mar. 30, 2012); see also Range Resources
Corporation, et al. v. EPA, No. 11-60040 (5th Cir. Mar. 30, 2012).
51
 Letter, Bracewell & Giuliani to EPA Office of Enforcement & Compliance Assurance,
Mar. 30, 2012.




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

              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 These
              requirements may include Facility Response Plans and Spill Prevention,
              Control, and Countermeasure (SPCC) Plans. EPA also has certain
              response and enforcement authorities relevant to these requirements.

              This review focuses on EPA regulatory activities under these programs
              relevant to unconventional oil and gas development activities.




              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).




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                        CWA is the primary federal law designed to restore and maintain the
National Pollutant      chemical, physical, and biological integrity of the nation’s waters. Among
Discharge Elimination   other things, EPA and delegated states 6 administer CWA’s National
System Program          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 publicly-
                        owned 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.
                        10
                            See http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm




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                             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


Existing Effluent            EPA has developed effluent limitations guidelines for several
Limitations Guidelines for   subcategories of the oil and gas extraction industry. 13 The guidelines
Oil and Gas Extraction       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




                             11
                               Water-quality based effluent limitations are imposed when technology-based limitations
                             are insufficient for receiving waters to meet water quality standards.
                             12
                               See, e.g., 76 Fed. Reg. at 66,288.
                             13
                               40 C.F.R. pt. 435 (2012).
                             14
                               See, e.g., 40 C.F.R. § 435.30 (2012).
                             15
                               40 C.F.R. §§ 435.30-.32 (onshore), 435.50-.52 (agricultural and wildlife water use),
                             435.60-.61 (stripper wells) (2012). EPA also has developed effluent limitation guidelines
                             for the subcategories offshore wells and coastal wells; because this report is focused on
                             onshore wells, we do not discuss the guidelines for the offshore subcategory. See 40
                             C.F.R. §§ 435.10-.15 (offshore), 435.40-.47 (coastal) (2012). EPA’s original 1979 rule
                             included coastal wells in the subcategory for onshore wells. Following a court order, EPA
                             in 1982 suspended the applicability of the guidelines for the onshore category to coastal
                             wells. 44 Fed. Reg. 22,069 (Apr. 13, 1979), 47 Fed. Reg. 31,554 (July 21, 1982). See also
                             American Petroleum Institute v. EPA, 661 F.2d. 340 (5th Cir. 1981).
                             16
                               In 1976, EPA issued interim final regulations establishing effluent limitation guidelines
                             for the oil and gas extraction category and, in 1979, EPA replaced these with final
                             guidelines. 44 Fed. Reg. 22,069 (Apr. 13, 1979); see also 47 Fed. Reg. 31,554 (July 21,
                             1982).




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For the onshore and agricultural and wildlife water use subcategories,
EPA established effluent limitations guidelines for direct dischargers. EPA
did not establish guidelines for stripper wells, explaining that
unacceptable economic impacts would occur from use of the then-
evaluated technologies, and that the agency could revisit this decision at
a later date. 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 EPA
officials also told us that the coalbed methane process is fundamentally
different than traditional oil and gas exploration because of the volume of
water that must be removed from the coalbed before production can
begin, which they see as a significant distinction for potentially applicable
technology. As will be discussed later in this appendix, in October 2011,
EPA announced its intention to develop effluent limitations guidelines and
standards for wastewater discharges from the coalbed methane industry.

When an oil and gas well proposing to discharge pollutants to a surface
water is not covered by the existing guidelines, effluent limitations
included in the permit are determined on a case-by-case basis by the




17
   41 Fed. Reg. 44,942, 44,946-47 (Oct. 13, 1976). EPA has also noted that the stripper
subcategory may be used to exclude a well from other subcategories. In effect, the
existence of the subcategory authorizes a permit writer to set case-specific permit
limitations for a well that falls within the stripper subcategory, as it has no specific effluent
limitations, rather than use those for the onshore subcategory. 44 Fed. Reg. at 22,073.
18
  By definition, such requirements would be inapplicable to the agricultural and wildlife use
subcategory.
19
  76 Fed. Reg. 66,286, 66,293 (Oct. 26, 2011).
20
  EPA, Technical Support Document for the 2006 Effluent Guidelines Program Plan, EPA-
821R-06-018, 6-1 (2006).




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                                                relevant permitting authority, using best professional judgment 21 and any
                                                applicable state rules or guidance. EPA officials were not aware of any
                                                other unconventional oil and gas extraction processes, besides coalbed
                                                methane extraction, that are not covered by the existing effluent
                                                limitations guidelines.

                                                Table 8 summarizes the coverage and key requirements of the existing
                                                guidelines.

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

                                                  Covered by existing effluent limitations
Subcategory of oil or gas well                    guideline                                            Permit requirement
Wells included in an existing segment subcategory
Onshore wells that do not fit into any of the     Yes – direct dischargers                             No discharge
other subcategories                               No – indirect dischargers (no pretreatment
                                                  requirements established)
Agricultural and Wildlife Water Use               Yes                                                  Discharge of produced water allowed
subcategory                                                                                            where conditions met, and subject to max
                                                                                                       daily limit for oil and grease
Stripper wells                                    Subcategory created, but no effluent                 Case-by-case
                                                  limitations or pretreatment requirements
                                                  established
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).


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




                                                21
                                                  EPA has noted that permit writers are to develop technology-based limits on a case-by-
                                                case basis using their best professional judgment, and considering the same statutory
                                                factors EPA would use in promulgating a national categorical effluent limitation guideline.
                                                See 40 C.F.R. §§ 122.44(a)(1),125.3(d) (2012). EPA, Technical Support Document for the
                                                2006 Effluent Guidelines Program Plan, EPA-821R-06-018, 6-3 (2006).




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                                       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
                                                                                                                           22
                                       treatment (i.e., produced water, drilling muds, drill cuttings, and produced sand).

                                  Because an NPDES permit is only required where a facility discharges or
                                  proposes to discharge a pollutant, and as the technology-based
                                  requirement of “no discharge” must be applied in the permit, facilities
                                  subject to a “no discharge” limit are not required to apply for such permits.

                                  According to the 1976 Federal Register Notice of the Proposed Rule,
                                  technologies for managing produced water to achieve no discharge to
                                  surface waters were expected to include evaporation ponds, or
                                  underground injection, either for enhanced recovery of oil or gas in the
                                  producing formation or for disposal to a deep formation. 23 Further, EPA
                                  indicated that drilling muds, drill cuttings, well treatment wastes, and
                                  produced sands would be disposed by land disposal so as not to reach
                                  navigable waterways.

Agricultural and Wildlife Water   The effluent limitations guideline for the Oil and Gas Extraction point
Use Subcategory                   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.” 24

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




                                  22
                                   40 C.F.R. § 435.32 (2012) (emphasis added).
                                  23
                                   41 Fed. Reg.44,942, 44,946 (Oct. 13, 1976).
                                  24
                                   44 Fed. Reg. 22,069, 22,072 (Apr. 13, 1979).




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     “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
                  25
     and grease.

At oil and gas well sites meeting the conditions of location, produced
water quality, and use of produced water for wildlife or livestock watering
or agricultural use, the produced water may be discharged to waters of
the United States. In terms of water quality, the produced water must be
“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 is responsible for oversight and has not issued
guidance on this topic.

EPA has not revised the guildeines, such as to add limitations for
additional pollutants, to define “good enough” water quality, or to establish
potentially more stringent guidelines. EPA officials stated that it has not
done so because in certain locations the produced water from oil and gas
development is high quality, and because treatment would cost more than
injection, thus discouraging the beneficial use of this water.

With respect to the subcategories of oil and gas wells covered by the
effluent limitations guidelines, discharges are authorized only for oil and
gas wells under the Agricultural and Wildlife Water Use and Stripper well
subcategories. These well sites that discharge wastewater to surface
waters must, as noted above, obtain a NPDES permit from the permitting
authority (state, tribe, or EPA). The permit is to incorporate the applicable
effluent limitations guideline, if one exists, and include effluent monitoring
and reporting requirements. Officials also stated that individual permits
may contain limits for pollutants other than oil and grease.




25
 40 C.F.R. §§ 435.50-52 (2012).
26
 40 C.F.R. § 435.51(c) (2012).
27
 EPA issues permits in a small number of states that do not have responsibility for the
NPDES program, and on tribal lands.




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                             According to EPA, 349 discharge permits in the Agricultural and Wildlife
                             Water Use subcategory have been issued. Most of these permitted
                             discharges are located in Wyoming, Montana, and Colorado.


Anticipated Rulemaking to    On October 26, 2011, EPA announced in its Final 2010 Effluent
Develop Effluent             Limitations Program Plan that the agency will develop effluent limitations
Limitations Guidelines for   guidelines and standards for wastewater discharges from the coalbed
                             methane extraction industry. 28
Oil and Gas Extraction
from Coalbed Methane         With respect to coalbed methane extraction, as noted above, there is no
Formations                   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 According to EPA officials,
                             most coalbed methane wastewater discharges have NPDES permits.

                             Following the study, EPA concluded that some of the waters discharged
                             to surface waters have high total dissolved solids, and that there are
                             readily available technologies to treat this produced water and decided to


                             28
                              76 Fed. Reg. 66,286 (Oct. 26, 2011).
                             29
                               76 Fed. Reg. at 66,293. See also
                             http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm
                             30
                              EPA, Coalbed Methane Extraction: Detailed Study Report, EPA-820-R-10-022 (2010).
                             31
                               Id. at Appendix A. See also EPA, Technical Support Document for the 2006 Effluent
                             Guidelines Program Plan, EPA-821R-06-018, 6-5 (2006) (listing numbers of coalbed
                             methane discharge permits derived from state permit databases).




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                         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.


Generally Applicable     Facilities discharging industrial wastewater to publicly-owned treatment
Pretreatment Standards   works (POTW) treatment plants are subject to general pretreatment
and POTW Obligations     requirements. In addition, the POTW receiving such industrial
                         wastewaters also has responsibilities related to its own permit and to
                         receiving these wastewaters.

General standards        EPA has issued general pretreatment requirements applicable to all
                         existing and new indirect dischargers of pollutants (other than of purely
                         domestic, or sanitary, sewage) to a POTW, including any dischargers of
                         wastewaters associated with oil and gas wells. 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 According to EPA officials, in produced water,



                         32
                          76 Fed. Reg. at 66,294.
                         33
                           See http://yosemite.epa.gov/opei/RuleGate.nsf/byRIN/2040-AF35?opendocument#1,
                         RIN 2040-AF35, docket no. EPA-HQ-OW-2011-0334.
                         34
                          See generally 40 C.F.R. pt. 403 (2012).
                         35
                          40 C.F.R. § 403.5(a)(1) (2012).
                         36
                           Pass through means a discharge that exits the POTW into waters of the United States in
                         quantities or concentrations which, alone or in conjunction with a discharge or discharges
                         from other sources, is a cause of a violation of any requirement of the POTW’s NPDES
                         permit. 40 C.F.R. § 403.3(p) (2012). Interference is a discharge which, alone or in
                         conjunction with a discharge or discharges from other sources, both (1) inhibits or disrupts
                         the POTW, its treatment processes or operations, or its sludge processes, use or
                         disposal; and (2) therefore is a cause of a violation of any requirement of the POTW’s
                         NPDES permit or prevents sewage sludge use or disposal in compliance with relevant
                         laws. 40 C.F.R. § 403.3(k) (2012).
                         37
                          40 C.F.R. § 403.5(b)(2) (2012).




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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 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


38
  See also 74 Fed. Reg. 58,784, 58,803 (Nov. 13, 2009) (in the context of SPCC
regulations, stating “Information reviewed by the Agency and presented in the public
docket (EPA–HQ–OPA–2007–0584–0015) showed corrosion as a common cause of oil
and produced water discharges at onshore oil production facilities. The higher salt content
of produced water fluids as compared to crude oil may lead to the increased corrosion rate
of metallic components of the produced water storage system.”).
39
  Memorandum from EPA Office of Wastewater Management to EPA Regions with
answers to frequently asked questions about wastewater issues resulting from shale gas
extraction (2012), available at http://cfpub.epa.gov/npdes/hydrofracturing.cfm
40
  NPDES permits held by POTWs do typically require monitoring for whole effluent
toxicity, intended to measure whether the effluent is harmful to aquatic life. Some POTWs
in Pennsylvania have previously accepted produced water; EPA Region 3 officials were
unsure if data are available regarding whether these POTWs had problems with their
whole effluent toxicity tests.
41
 In the Matter of New Castle Sanitation Authority, Findings of Violation Order for
Compliance and Request for Information, EPA. Docket No. CWA-03-2011-0272 DN.




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                   production wastewater until completing an evaluation and sampling, and
                   to eliminate and prevent recurrence of the violations.

POTW Obligations   Generally, local governments operating POTWs are responsible for
                   ensuring that indirect dischargers comply with any applicable national
                   pretreatment standards. 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 EPA or states may be responsible for
                   ensuring these POTWs meet their obligations and for approving the
                   POTW’s pretreatment plans.

                   According to EPA, regardless of pass through or interference, POTWs
                   should not accept indirect discharges of produced water if the
                   wastewaters have different characteristics than those for which the
                   POTW was originally permitted, without providing adequate notice to the
                   permitting authority. 44 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




                   42
                     See EPA, Introduction to the National Pretreatment Program, EPA-833-B-11-001,3-3
                   (2011).
                   43
                    C.F.R. § 403.8(a) (2012); see also http://cfpub.epa.gov/npdes/faqs.cfm?program_id=3
                   44
                     Memorandum from EPA Office of Wastewater Management to EPA Regions with
                   Answers To Frequently Asked Questions About Wastewater Issues Resulting From Shale
                   Gas Extraction, Attachment at 9 (Mar. 16, 2011), available at
                   http://cfpub.epa.gov/npdes/hydrofracturing.cfm




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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 officials indicated
that if a POTW is accepting types of wastewater that were not on its
original application, EPA could require a modification of the POTW’s
NPDES permit, or object to a NPDES renewal that did not address these
wastewaters and the facility’s ability to treat them. POTWs may also
initiate inclusion of these wastewaters in their permits or permit renewals.
For example, EPA Region 3 officials stated that four POTW operators in
Pennsylvania in the NPDES renewal process have indicated the intent to
continue accepting oil and gas wastewater. In addition, in cases with pass
through or interference, EPA could require a POTW to develop a
pretreatment program.

EPA’s website indicates the agency plans to supplement the existing
Office of Water questions and answers document with additional
guidance directed to permitting authorities, pretreatment control
authorities and POTWs, to provide assistance on how to permit POTWs
and other centralized wastewater treatment facilities by clarifying existing
CWA authorities and obligations. 48 Specifically, EPA plans to issue two
guidance documents, one for permit writers and another for POTWs.




45
 76 Fed. Reg. 66,286, 66,297 (Oct. 26, 2011).
46
  Memorandum from EPA Office of Wastewater Management to EPA Regions with
Answers To Frequently Asked Questions About Wastewater Issues Resulting From Shale
Gas Extraction (Mar. 16, 2011), available at
http://cfpub.epa.gov/npdes/hydrofracturing.cfm
47
 Id. at 9; see also 40 C.F.R. § 122.42(b)(1) (2012).
48
 http://www.epa.gov/hydraulicfracture/#swdischarges




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Anticipated Rulemaking to   With respect to shale gas extraction, the effluent limitations guideline for
Develop Pretreatment        the onshore subcategory in effect since 1979 has prohibited direct
Standards for Gas           discharges of associated wastewaters; however, EPA has not established
                            pretreatment standards for indirect discharges of such wastewaters. EPA
Extraction from Shale       requested and received comments on whether to initiate a rulemaking for
Formations                  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 For example, the state of Pennsylvania requested that
                            operators of Marcellus shale gas wells stop delivering produced water to
                            POTWs, potentially avoiding the issue. EPA officials stated that other
                            states may nonetheless have a need to utilize POTWs to address these
                            wastewaters and hence could benefit from pretreatment standards.

                            EPA is in the preproposal stage of this rulemaking, and EPA’s website
                            indicates the projected date for publication of the proposed rule is 2014.



                            49
                              See, e.g., 76 Fed. Reg. at 66,292, 66,295, 74 Fed. Reg. 68,599 (Dec. 28, 2009).
                            50
                              76 Fed. Reg. at 66,295-96. According to EPA, POTWs typically have permits that do not
                            contain limits for the pollutants of concern in shale gas wastewater; the secondary
                            treatment requirements do not address such pollutants, and is it uncommon for these
                            permits to contain water quality based limitations for such pollutants. Id. at 66,297. Thus,
                            such wastewaters likely pass through the POTWs receiving such wastewaters and the
                            POTWs may not monitor for these pollutants in their effluent.
                            5151
                                 Id. at 66,297.
                            52
                              Id.
                            53
                              Id. at 66,298.




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NPDES for Stormwater         In 1987, the Water Quality Act amended CWA to establish a specific
Discharges                   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

Stormwater from Industrial   Generally, industrial sites obtain coverage for stormater through a general
Activities                   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
                                                                                                  59
                                  contact with, or do not come into contact with, any overburden, raw material,




                             54
                               See generally Water Quality Act of 1987, Pub. L. No. 100-4 § 405, 101 Stat. 7, 69-71
                             (adding CWA § 402(p), codified at 33 U.S.C. § 1342(p) (2012)).
                             55
                              Id., 55 Fed. Reg. 47,990, 47,992 (Nov. 16, 1990) (Phase 1 rule).
                             56
                              55 Fed. Reg. at 47,990.
                             57
                              See Multisector General Permit at App. C.
                             58
                              See EPA, 2012 Construction General Permit Fact Sheet at 6-7, 36.
                             59
                               Subsequently, EPA added to its regulations a definition of overburden: “any material of
                             any nature, consolidated or unconsolidated, that overlies a mineral deposit, excluding
                             topsoil or similar naturally-occurring surface materials that are not disturbed by mining
                             operations.” 40 C.F.R. § 122.26(b)(10) (2012).




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     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 including Texas, and



60
  Water Quality Act of 1987, § 401, 101 Stat. 65-66 (codified at 33 U.S.C. § 1342(l)(2)
(2012)).
61
 55 Fed. Reg. at 48,029, 40 C.F.R. §§ 122.26(b)(14)(iii), (c)(1)(iii) (2012).
62
  Id. The reporting requirements triggering a permit are listed in 40 C.F.R. §§ 117.21,
302.6, 110.6 (2012). Note that the generally applicable industrial stormwater regulations
also provide a conditional exclusion for discharges composed entirely of stormwater if
there is no exposure of industrial materials and activities to rain, snow, snowmelt and
runoff, and where additional conditions are satisfied. 40 C.F.R. § 122.26(g) (2012).
63
 The states are Idaho, Massachusetts, Texas, Oklahoma, and Alaska.




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                        identified some stormwater general permit notifications for facilities that
                        could be well sites. 64

Stormwater from         EPA regulations require permits for stormwater discharges from
Construction Activity   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




                        64
                          Specifically, EPA officials identified approximately 34 notifications from facilities with
                        Standard Industrial Classification codes that could indicate that the facility is a well site for
                        example, codes 1381 (drilling oil and gas) and 1389 (hydraulic fracturing services).
                        65
                          CWA §§ 402(l)(2), 502(24), 33 U.S.C. §§ 1342(l)(2), 1362(24); 55 Fed. Reg. 47,990,
                        48,065 (Nov. 16, 1990) (amending 40 C.F.R. § 122.26; see § 122.26(a)(1)(ii), (b)(14)(x)).
                        66
                          In 2005, EPA revised its regulation to extend the deadline for permits for contaminated
                        stormwater discharges associated with small construction activity—generally including
                        clearing, grading and excavating that results in land disturbance more than 1 acre but less
                        than 5 acres—at oil and gas sites to June 12, 2006. 70 Fed. Reg. 11,560, 11,563 (Mar. 9,
                        2005) (amending 40 C.F.R. § 122.26(e)(8)). Other industry sites requiring permit coverage
                        for small construction activity were required to comply by March 2003.
                        http://cfpub.epa.gov/npdes/stormwater/cgp.cfm




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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 with the proposal expected in 2013.

According to EPA officials, during construction, oil and gas well sites
would have no permit requirement because of the statutory exemption.


67
 Water 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)).
69
   71 Fed. Reg. 33,628 (June 12, 2006) (amending 40 C.F.R. § 122.26(a)(2)(ii) (2006)). As
stated in EPA’s fact sheet for the 2006 revisions, permits would be required only in “very
limited instances.”
70
 Natural Resources Defense Council v. EPA, 526 F.3d 591 (9th Cir. 2008).
71
  Id. See also
http://cfpub.epa.gov/npdes/regresult.cfm?program_id=6&type=1&sort=name&view=all
72
 Compare 40 C.F.R. § 122.26 (2012) with 40 C.F.R. § 122.26 (2005).




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NPDES Enforcement          For violations of the law, or applicable regulations or permits, EPA has
                           authority to issue administrative orders requiring compliance, impose
                           administrative penalties, as well as to bring suit and, in conjunction with
                           the Department of Justice, to impose civil penalties. 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.


Imminent and Substantial   CWA section 504 provides EPA an imminent and substantial
Endangerment Authorities   endangerment authority, authorizing EPA to bring suit to restrain a person
                           to stop the discharge of pollutants causing or contributing to pollution, or to



                           73
                            CWA § 309, 33 U.S.C. § 1319 (2012).
                           74
                             Id., CWA § 301(a), 33 U.S.C. § 1311(a) (2012). As explained above, however,
                           discharges of pollutants via stormwater from a well site generally does not require a
                           permit, and thus such discharges without a permit would not be considered unauthorized,
                           except in limited circumstances.
                           75
                            CWA § 308(a), 33 U.S.C. § 1318(a) (2012).
                           76
                            CWA § 308(a)(B)(i), 33 U.S.C. § 1318(a)(B)(i) (2012).
                           77
                            American Petroleum & Environmental Consultants, Inc., Cease and Desist
                           Administrative Order, EPA Docket No. CWA-06-2012-1760 (Dec. 12, 2011).
                           78
                            BP America Production Company, Combined Complaint and Consent Agreement, EPA
                           Docket No. CWA-08-2012-0014 (May 15, 2012).




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                       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.



Oil and Hazardous
Substances Spill
Prevention,
Reporting, and
Response

Spill Prevention and   EPA’s Oil Pollution Prevention regulations, promulgated and amended
Response Plans         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 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




                       79
                        CWA § 504, 33 U.S.C. § 1364 (2012).
                       80
                        40 C.F.R. pt. 112 (2012); see also 67 Fed. Reg. 47,042 (July 17, 2002).
                       81
                        Id.




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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 These amendments included several
provisions easing requirements for oil production sites, such as excluding
them from loading/unloading rack requirements, providing alternative


82
  40 C.F.R. § 112.2 (2012) (For purposes of the SPCC rule, “[t]he term ‘navigable waters’
of the United States means ‘navigable waters’ as defined in section 502(7) of the FWPCA,
and includes: (1) all navigable waters of the United States, as defined in judicial decisions
prior to the passage of the 1972 amendments of the Federal Water Pollution Control Act,
(FWPCA) (Pub. L. No. 92-500) also known as CWA and tributaries of such waters as; (2)
interstate waters; (3) intrastate lakes, rivers, and streams that are utilized by interstate
travelers for recreational or other purposes; and (4) intrastate lakes, rivers, and streams
from which fish or shellfish are taken and sold in interstate commerce.”).
83
  40 C.F.R. § 112.10 (2012).
84
  Id.
85
 40 C.F.R. § 112.7(g) (2012). See also U.S. Chemical Safety and Hazard Investigation
Board, Investigative Study Final Report: Public Safety at Oil and Gas Storage Facilities,
Report No. 2011-H-1 at 8 (September 2011).
86
  73 Fed. Reg. 74,236 (Dec. 5, 2008).




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qualified facility eligibility criteria (for streamlined compliance with self-
certification 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 EPA
explained that, in consideration of relevant facts and public comments,
there was either no basis for the exclusion or the exclusion will not
effectively protect the environment from discharges. For example, with
respect to the alternative qualified facility criteria provision, EPA stated
that the agency

     reviewed the spill data for the oil production sector contained in its study of the
     exploration and production sector…While these data do not characterize the extent of
     environmental damage caused by oil discharges from small oil production facilities,
     they demonstrate that the volume of oil discharged from onshore oil production facilities
     [is] increasing, and the number of oil discharges on a yearly basis has remained the
     same, despite a decline in crude oil production. In addition, oil production facilities are
     often unattended, and typically located in remote areas, which potentially increases the
     risk of environmental damage from an oil discharge of oil. 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.




87
 74 Fed. Reg. 58,784, 58,799-803 (Nov. 13, 2009).
88
 Id. at 58,799-803, 58,809-811.
89
  Id. at 58,802. See also Considerations for the Regulation of Onshore Oil Exploration
and Production Facilities Under the Spill Prevention, Control, and Countermeasure
Regulation (40 C.F.R. part 112)) (available at www.regulations.gov document EPA–HQ–
OPA–2007–0584–0015).




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EPA has developed guidance related to SPCC applicability and
compliance for oil production, drilling, and workovers. 90 According to
officials, EPA is currently developing a “frequently asked questions”
document about the SPCC program and hydraulic fracturing. This
document is being developed in response to an influx of questions about
how the SPCC rule applies to gas well sites, particularly from companies
active in the Marcellus shale. According to EPA officials, while the SPCC
is focused on oil, wet gas wells involve condensates, some of which have
traditionally been deemed liquid hydrocarbons and included in the
program. In particular, questions have arisen over the lightest
condensates (C2 and C4 hydrocarbons), which are usually in gaseous
form at standard temperatures and pressures and hence are not included
in the SPCC program, whereas storage of heavier condensates, such as
C6+ hydrocarbons, has been included (as liquids) in the SPCC program.

EPA directly administers the SPCC program. 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 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).


90
  See 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).
91
  The Clean Water Act does not provide EPA with the authority to authorize states to
implement the program in its place.
92
 GAO-08-482.
93
  See 40 C.F.R. § 112.3(a)(1) (2012); see generally 40 C.F.R. § 112.3(a)(1)-(3) (2012)
(establishing deadlines for SPCC plans).




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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
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.


94
  40 C.F.R. § 112.20 (2012).
95
  Id. at (f)(1), 40 C.F.R. Pt. 112, App. C, Att. C-1.
96
  40 C.F.R. §§ 112.20(b)(1), (c), (f) (2012).
97
  Id. at (e).
98
  Id. at (f)(1), App. C, Att. C-1 (2012). For new facilities, the facility response plan is to be
submitted before startup, for facilities commencing operation after Aug. 30, 1994; time
frames are different for facilities required to submit a plan due to changes in operation,
among other things. See 40 C.F.R. § 112.20(a)(2)(ii) (2012).
99
  Id. at (h).




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Spill Prohibition and   CWA established the policy of the United States that there should be no
Reporting               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 With respect to



                        100
                            CWA § 311(b)(1), (3), 33 U.S.C. § 1321(b)(1), (3) (2012). The scope of jurisdiction for
                        the section 311 oil spill program is broader than that for the NPDES program. The section
                        311 oil spill program and the NPDES program both have jurisdiction over navigable waters
                        of the United States; Section 311 also provides jurisdiction over spills of oil or hazardous
                        substances into or on adjoining shorelines or that may affect natural resources of the
                        United States, among others.
                        101
                          Id. at (b)(3)-(5).
                        102
                           40 C.F.R. § 116.4 (2012), see also CWA § 311(b)(2)(A), 33 U.S.C. § 1321(b)(2)(A)
                        (2012).
                        103
                          CWA § 311(b)(2)(A), (4), 33 U.S.C. § 1321(b)(2)(A), (4) (2012), 40 C.F.R. pt. 110, pt.
                        116-17 (2012).
                        104
                          CWA § 311(b), 33 U.S.C. § 1321(b) (2012), 40 C.F.R. 110.6 (2012). See also 33
                        C.F.R. § 153.203 (2012).
                        105
                           40 C.F.R. §§ 110.6, 110.3, 110.1 (2012),
                        http://www.epa.gov/osweroe1/content/reporting/faq_subs.htm#pelist




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                           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


Spill Response Authority   EPA, as well as other relevant federal agencies, has various response
                           authorities to ensure effective and immediate removal of a discharge, and
                           mitigation or prevention of a substantial threat of a discharge, of oil or a
                           hazardous substance to U.S. navigable waters or onto adjoining
                           shorelines. 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 For example, according to
                           EPA Region 5, in conjunction with the state of Ohio, the Region has
                           responded to several incidents in which orphan wells were found to be
                           leaking or discharging crude oil into waterways.

                           Under CWA section 311, as required to carry out its purposes including
                           spill prevention and response, EPA also has authority to require the
                           owner or operator of a facility subject to the Oil Pollution Prevention
                           Regulation, among other provisions, to establish and maintain such
                           records; make such reports; install, use, and maintain such monitoring
                           equipment and methods; provide such other information deemed
                           necessary; and for entry and inspection of such facilities. 109


Enforcement of SPCC and    For violations of the law, or applicable regulations or permits, EPA has
Spill Prohibition and      authority to issue administrative orders requiring compliance, impose
Reporting Requirements     administrative penalties, as well as to bring suit, in conjunction with the
                           Department of Justice, to impose civil penalties. 110 Section 311 also gives
                           EPA the authority to access records and inspect facilities, and the ability



                           106
                              40 C.F.R. §§ 117.3; § 116.4 at table 116.4A; see also 40 C.F.R. § 302.4 at table 302.4
                           (2012).
                           107
                             CWA § 311(c), 33 U.S.C. § 1321(c) (2012).
                           108
                             Id., 40 C.F.R. pt. 300 (2012).
                           109
                             CWA § 311(m)(2), 33 U.S.C. § 1321(m)(2) (2012).
                           110
                             Id. at (b)(6)-(7), (c), (e)(1)(B) (2012).




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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.




111
  Id. at (m)(2) (2012).
112
  EPA Region 8, Oil and Gas Environmental Assessment Effort 1996 – 2002, v (2003).
113
  Id. at 7.
114
  Id. at 8.
115
  Id. at 8.
116
  EPA Region 8, Summary Report, Oil and Gas Environmental Assessment Activities in
Wyoming during 2004-2006.




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Imminent and Substantial   CWA section 311 provides EPA authority to address certain releases of
Endangerment Authority     oil or hazardous substances to U.S. navigable waters and adjoining
for Spills                 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




                           117
                              CWA § 311(e)(1), 33 U.S.C. § 1321(e)(1) (2012). EPA also may, through the
                           Department of Justice, file a civil action to secure any relief from any person, including the
                           facility owner or operator, as may be necessary to abate such endangerment.




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



Authorities under the Clean Air Act

              The Clean Air Act (CAA or the Act) is the primary law with the purpose to
              protect and enhance the nation’s air quality. 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 With respect to oil and gas production as a
              stationary source, EPA has identified various components of oil and gas
              production that may be relevant to emissions:

                  Production components may include, but are not limited to, wells and related casing
                  head, tubing head and ‘‘Christmas tree’’ piping, as well as pumps, compressors, heater
                  treaters, separators, storage vessels, pneumatic devices and dehydrators. Production
                  operations also include the well drilling, completion and workover processes and includes
                                                                                                  5
                  all the portable non-self-propelled apparatus associated with those operations.




              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.




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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 Each of these key
programs is described below as it may apply to oil and gas well sites.

Mobile sources associated with oil and gas production may include trucks
bringing fuel, water, and supplies to the well site; construction vehicles; and
truck-mounted pumps and engines. That is, oil and gas wells may be
served by a variety of road and nonroad vehicles and engines. EPA
regulates emissions from an array of mobile sources by imposing emission
limits on such vehicles and engines; these generally applicable regulations
are not specific to the oil and gas industry and are not discussed here.

Finally, the Act includes provisions addressing accidental releases of
dangerous pollutants to the air. 11 Oil and gas wells are unlikely to trigger
the planning aspects of these provisions, according to EPA; however, the


6
 NRDC, Drilling Down: Protecting Western Communities from the Health and
Environmental Effects of Oil and Gas Production 11 (2007).
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).
10
    CAA § 502, 42 U.S.C. § 7661a (2012), 40 C.F.R. §§ 70.3, 71.3 (2012).
11
    CAA § 112(r), 42 U.S.C. § 7412(r) (2012).




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                                            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
                      Specific rule for oil and gas production sector,              Likely applicability to emissions at oil and gas
CAA program           applicable to well sites?                                     well sites
National Emission     Yes, addressing glycol dehydrators and storage                Data not available regarding the extent to which well
Standards for         vessels with potential for flash emissions at major           sites comprise major or area sources subject to the
Hazardous Air         sources and only triethylene glycol dehydrators at            NESHAP, but the NESHAPs may apply at few well sites.
Pollutants            area sourcesa
(NESHAP)
New Source            Yes, addressing gas well completions, pneumatic               Gas wells that are fractured are subject to flaring and
Performance           controllers, and some storage vessels                         phased-in green completion requirements, focused on
Standards (NSPS)                                                                    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 No (generally applicable)                                         Unknown; most likely is nonattainment NSR in severe
(NSR)                                                                               areas, which have lowest threshold potential to emit.
                                                                                    Programs are generally implemented by states and
                                                                                    features vary.
Title V Operating    No. The oil and gas NESHAP and NSPS specifically               Unknown.
Permits              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.
Accidental Releases: No (generally applicable)                                      Unlikely; regulated substances in oil and gas that meet
Risk Management                                                                     the definition of “naturally occurring hydrocarbon
Program                                                                             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: No (generally applicable)                                      Applies; no threshold; EPA has used provision to
General Duty Clause                                                                 conduct inspections and require control of leaks.
Greenhouse Gas       Yes                                                            Applies with threshold at the basin-level, EPA estimates
Reporting                                                                           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.




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National Emission
Standards for
Hazardous Air
Pollutants

Hazardous Air Pollutants   The 1990 CAA amendments significantly expanded the hazardous air
                           pollutants program; they identified 189 specific HAPs to be regulated,
                           required EPA to list categories of sources to be regulated, and
                           established implementation timelines. 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 In a 1993 report to Congress,


                           12
                              Clean Air Act Amendments of 1990, Pub. L. No. 101-549, Title III, § 301, 104 Stat. 2399,
                           2531; Joint resolution to make a technical correction in Public Law 101-549, Pub. L. No.
                           102-187, 105 Stat. 1285 (1991). Of the 189 HAPs, two have since been delisted, so the
                           list now includes 187 HAPs.
                           13
                             The listed HAPs are also known as air toxics.
                           14
                              In other regulatory contexts, hydrogen sulfide is considered hazardous; for example, it is
                           a hazardous substance under CERCLA. 40 C.F.R. § 302.4 table 302.4, (2012). See also
                           EPA, Report to Congress on Hydrogen Sulfide Emissions Associated with the Extraction
                           of Oil and Gas, EPA-453-R-93/045 (1993) (stating that hydrogen sulfide “is toxic and care
                           should be exercised in its presence;” EPA officials noted that the purpose of this report
                           was not to examine whether or not hydrogen sulfide should included in the HAPs list.).
                           Some have argued that hydrogen sulfide, of which oil and gas well emissions may be a
                           significant source, should be a HAP. See NRDC, Drilling Down, at 13. While it was on the
                           list initially enacted in the 1990 amendments, by a joint resolution, Congress corrected the
                           inadvertent addition of hydrogen sulfide to the list. See page 2 of GAO, Clean Air Act: EPA
                           Should Improve the Management of Its Air Toxics Program, 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).
                           15
                             CAA § 112(b)(2), 42 U.S.C. § 7412(b)(2) (2012).
                           16
                             40 C.F.R. § 68.130 (2012).




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                             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.


NESHAPs Overview and         EPA is required to promulgate and periodically revise NESHAPs for
Statutory Provisions         source categories the agency has identified. 20 NESHAPs may include
Restricting Aggregation of   standards for major sources and for area sources, which are any sources
                             not major. 21 Major source NESHAPs are based on the maximum
Oil and Gas Production
                             achievable control technology (MACT), while EPA may use a different
Sources                      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



                             17
                               The HAP provision also provided for EPA to submit a report to Congress in 1992
                             assessing the hazards to public health and the environment resulting from the emission of
                             hydrogen sulfide associated with the extraction of oil and natural gas resources, and any
                             recommendations, and directed EPA to, as appropriate, develop and implement a control
                             strategy for such emissions using existing authorities. CAA § 112(n)(5), 42 U.S.C. §
                             7412(n)(5) (2012).
                             18
                               Letter 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.
                             19
                              Id. at 11.
                             20
                              CAA § 112(d)(1), (d)(6), 42 U.S.C. §§ 7412(d)(1), (d)(6) (2012).
                             21
                              Id. at § 7412(a)(1)-(2).
                             22
                              Id. at § 7412(d)(5).




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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.




23
 Id. at § 7412(a)(1), 76 FR 52,741 (Aug. 23, 2011).
24
  40 C.F.R. § 63.2 (2012) (defining major source); see also 64 Fed. Reg. 32,610, 32,613
(June 17, 1999).
25
 CAA § 112(n)(4)(a), 42 U.S.C. § 7412(n)(4)(a) (2012).
26
 40 C.F.R. § 63.760(d) (2012).
27
 64 Fed. Reg. at 32,619.
28
 Id.; 40 C.F.R. § 63.761 (defining “associated equipment”).




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NESHAPs for Oil and      EPA originally promulgated the NESHAPs for Oil and Natural Gas
Natural Gas Production   Production source subcategory in two parts: the standard for major
Facilities               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

Major Sources            The NESHAPs for major sources apply to emission points of HAPs
                         located at oil and natural gas production facilities (including wells,
                         gathering stations, and processing plants) that are major sources. 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 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.


                         29
                           64 Fed. Reg. 32,610 (June 17, 1999) (the notice also announced final rules for the
                         category of natural gas transmission and storage facilities), 72 Fed. Reg. 26 (Jan. 3,
                         2007); 40 C.F.R. pt. 63 Subpt. HH.
                         30
                          77 Fed. Reg. 49,490 (Aug. 16, 2012). The notice of the final rule was signed by the
                         Administrator and a prepublication copy released to the public in April 2012.
                         31
                           40 C.F.R. §§ 63.760(a)(1), 63.761 (2012).
                         32
                           77 Fed. Reg. 49,490 , 49,501, 49,569 (Aug. 16, 2012) (revising 40 C.F.R. § 63.760,
                         63.761 to define major source such that “[f]or facilities that are production field facilities,
                         only HAP emissions from glycol dehydration units and storage vessels shall be
                         aggregated for a major source determination.”). Storage vessels are defined as a tank or
                         other vessel that is designed to contain an accumulation of crude oil, condensate,
                         intermediate hydrocarbon liquids, or produced water and that is constructed primarily of
                         nonearthen materials (e.g., wood, concrete, steel, plastic) that provide structural support.
                         Id. at 49,569.
                         33
                           64 Fed. Reg. 32,610, 32613 (June 17, 1999), 40 C.F.R. 63.760 (2012) (small sources
                         are those, prior to the point of custody transfer, with a facility-wide actual annual average
                         natural gas throughput less than 18.4 thousand standard cubic meters per day and a
                         facility-wide actual annual average hydrocarbon liquid throughput less than 39,700 liters
                         per day).




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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 For existing and new storage vessels with
the potential for flash emissions, the standard is to be equipped with a



34
  In addition to interviewing EPA officials in the Clean Air program and in four Regions,
GAO conducted sample searches on the EPA Air Facility System database.
35
  Large glycol dehydrators are those with an actual annual average natural gas flowrate
equal to or greater than 85 thousand standard cubic meters per day and actual annual
average benzene emissions equal to or greater than 0.90 Mg/yr. 77 Fed. Reg. 49,490 ,
49,568-69 (Aug. 16, 2012) (revising 40 C.F.R. §§ 63.761, 63.760(b)).
36
  64 Fed. Reg. 32,610, 32,613-14 (June 17, 1999).
37
  40 C.F.R. § 63.765 (2012).
38
  40 C.F.R. § 63.765 (2012), 64 Fed. Reg. 32,610, 32,613-14 (June 17, 1999).




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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 However, these standards only apply at
sites that are deemed major sources, and as outlined above, it appears
likely that few well sites reach the key threshold emissions level.

The April 2012 amendments added one more emission source to the
NESHAP major source rule: small glycol dehydrators. 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 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




39
 40 C.F.R. § 63.766 (2012).
40
 77 Fed. Reg. 49,490 ,49,568-71 (Aug. 16, 2012).
41
 Id. at 49,570-71.
42
 Id. at 49,568-60 (amending 40 C.F.R. 63.760(f)).
43
  Id. at 49,503; see also EPA, Summary of Requirements for Processes and Equipment
at Natural Gas Well Sites.
44
 76 Fed. Reg. 52,738, 52,769 (Aug. 23, 2011).
45
 77 Fed. Reg. 49,490 , 49,503, 49,528-29 (Aug. 16, 2012).




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               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 The effect of this
               change (i.e., revision to the definition of “associated equipment”) is that
               emissions from all storage vessels and all glycol dehydrators now will be
               counted toward determining whether a facility is a major source under the
               NESHAP for Oil and Natural Gas Production. EPA documents do not
               indicate the extent to which the change in definition will result in additional
               oil and gas wells being subject to the MACT requirement.

Area Sources   CAA prohibits EPA from listing oil and gas production wells (with its
               associated equipment) as a specific “area source” category, unless the
               area source category is for oil and gas production wells located in any
               metropolitan statistical area or consolidated metropolitan statistical area
               with a population in excess of 1 million, and the EPA Administrator
               determines that emissions of HAPs from such wells present more than a
               negligible risk of adverse effects to public health. 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 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



               46
                Id. at 49,503.
               47
                Id. at 49,501, 49,569 (revising 40 C.F.R. § 63.761).
               48
                CAA § 112(n)(4)(B), 42 U.S.C. § 7412(n)(4)(B) (2012).
               49
                72 Fed. Reg. 26 (Jan. 3, 2007).
               50
                40 C.F.R §§ 63.764(d), 63.765(a) (2012).
               51
                 EPA defines these control areas with reference to parameters used by the U.S. Census
               Bureau to identify densely settled areas. See 72 Fed. Reg. 26, 28 (2007).




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                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.


Other NESHAPs   In addition, EPA has promulgated other NESHAPs, the applicability of
                which to oil and gas well sites depends upon the particular equipment—
                and factors such as capacity or emission rate—used at a well site.
                Although some published materials suggest several NESHAPs may
                apply, based on discussions with EPA, the primary NESHAP that officials
                believe could apply at oil and gas well sites is the Boilers and Process
                Heaters NESHAP for major sources. 56




                52
                  72 Fed. Reg. 26, 28 (Jan. 3, 2007), 40 C.F.R §§ 63.764(d), 63.765(a) (2012).
                53
                  40 C.F.R § 63.764(d) (2012).
                54
                  40 C.F.R. § 63.775(c) (2012); see also 72 Fed. Reg. 26, 30 (Jan. 3, 2007).
                55
                  For example, GAO searched EPA’s Air Facility System database to identify 40 C.F.R. pt.
                63 Subpt. HH MACT area sources with the Standard Industrial Classification code for oil
                and gas extraction. Some of the facilities identified in the search results have “well” in the
                facility name, but may include other facilities downstream of the well pad; the database
                does not have information to distinguish the well sites among the facilities.
                56
                  40 C.F.R. pt. 63 Subpt. DDDDD, §§ 63.7480-7575 (2012).




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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 Officials stated that some glycol
              dehydrators at well sites could be over the trigger heat input and would be
              subject to the Boiler NESHAP requirements if the oil and gas site were a
              major source subject to the rule. As noted above, it is not known how
              many, if any, well sites are major sources.

              Where a gas well has a compressor, the compressor engine may be
              subject to standards for stationary engines. 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
New Source    reconstructed facilities and (2) facilities that have undergone
Performance   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
Standards     emitted by such source or which results in the emission of any air
              pollutant not previously emitted. 60 These rules are implemented by EPA



              57
               40 C.F.R. § 63.7485, 76 Fed. Reg. 15,608, 15,619 (Mar. 21, 2011).
              58
                40 C.F.R. § 63.7500, pt. 63 Subpt. DDDDD Tables 1-2 (Boiler NESHAP); cf. 40 C.F.R.
              pt. 63 Subpt. HH App. Table 1, 64 Fed. Reg. 32,610 (June 17, 1999) (Oil and Gas
              NESHAP for major sources). The NESHAP for Oil and Gas Production Facilities is
              focused on BTEX and n-hexane.
              59
               40 C.F.R. pt. 63, Subpt. ZZZZ (Stationary Reciprocating Internal Combustion Engines).
              60
               CAA § 111(a)(2), (4), 42 U.S.C. § 7411(a)(2), (4). (2012).




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                           or by states through delegation. 61 For the oil and gas production industry,
                           the NSPS primarily regulates VOCs (as an ozone precursor).

                           In 1985, EPA promulgated NSPS for the oil and gas industry focused on
                           natural gas processing plants, but did not include any standards for
                           emissions from preprocessing production activities. 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.


April 2012 Amendments to   In April 2012, EPA promulgated amendments to the NSPS for the Oil and
NSPS                       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 In particular, the
                           new standards establish operational standards applicable to selected



                           61
                            Id. at § 7411(c).
                           62
                            40 C.F.R. pt. 60, subparts KKK, LLL.
                           63
                             77 Fed. Reg. 49,490 , 49,542-67 (Aug. 16, 2012) (adding 40 C.F.R. pt. 60 subpt.
                           OOOO, consisting of §§ 60.5360 to 60.5430).
                           64
                            Id.
                           65
                             See Consent Decree, Document 25, and Third Stipulation of the Parties to Modify
                           Consent Decree, Document 28, Wildearth Guardians et al. v. Jackson, No. 1:09-cv-00089-
                           CKK (Dist. D.C. 2011). See also CAA §§ 111(b)(1)(B), 112(d)(6), (f)(2), 42 U.S.C. §§
                           7411(b)(1)(B), 7412(d)(6), (f)(2) (2012).
                           66
                            American Petroleum Institute, Request for Administrative Reconsideration and an
                           Administrative Stay of Targeted Elements of EPA’s Final Rule “Oil and Natural Gas
                           Sector: New Source Performance Standards and National Emission Standards for
                           Hazardous Air Pollutants Reviews,” Aug. 16, 2012.
                           67
                             77 Fed. Reg. 49,490, 49,497-98, 49,543 (Aug. 16, 2012) (adding, e.g., 40 C.F.R. §
                           60.5365).




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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

                                                                                                                        Well logs,
                                                                                                  Duty to minimize      compliance
                                                Green completions                                 releases to the air   demonstration,
Natural gas well                                (routing gas to the     Combustion of             (flowback and         records and
subcategory            Completion date          flow line)              flowback emissions        recovery)             reporting
Provisionsb                                     40 C.F.R. §              40 C.F.R. §              40 C.F.R. §           40 C.F.R. §
                                                60.5375(a)(1)-(2)       60.5375(a)(3)             60.5375(a)(4)         60.5375(b)-(e)
New wells              Completions with                                 √                         √                     √
constructed after      hydraulic fracturing
Aug. 23, 2011          before Jan. 1, 2015
                       Completions with         √                       √ (only for emissions     √                     √
                       hydraulic fracturing                             that cannot be directed
                       after Jan. 1, 2015                               to the flow line)
Wells existing as of   Completions with                                 √                         √                     √
Aug. 23, 2011          hydraulic fracturing
                       before Jan. 1, 2015
                       Completions with         √                       √ (only for emissions     √                     √
                       hydraulic fracturing                             that cannot be directed
                       after Jan. 1, 2015                               to the flow line)
                       Alternative to avoid     √                       √ (only for emissions     √                     √
                       new source status                                that cannot be directed
                       before Jan. 1, 2015a                             to the flow line)




                                              68
                                                See EPA, Regulatory Impact Analysis: Final New Source Performance Standards and
                                              Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil
                                              and Natural Gas Industry at 3-12 (April 2012). EPA projected these numbers of affected
                                              wells for the year 2015, when the rule will be fully in effect, and the number of wells
                                              affected may actually vary from year to year. At the time of the proposed rule, EPA
                                              estimated that over 20,000 completions and recompletions annually would be subject to
                                              the proposed requirements. 76 Fed. Reg. 52,738, 52,747 (Aug. 23, 2011).




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                                                                                                                          Well logs,
                                                                                                  Duty to minimize        compliance
                                            Green completions                                     releases to the air     demonstration,
Natural gas well                            (routing gas to the           Combustion of           (flowback and           records and
subcategory          Completion date        flow line)                    flowback emissions      recovery)               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


                                       69
                                         For pneumatic controllers, an affected source is a single continuous bleed natural gas-
                                       driven pneumatic controller operating at a natural gas bleed rate greater than 6 standard
                                       cubic feet per hour located between the wellhead and the point of custody transfer to the
                                       natural gas transmission and storage segment and not located at a natural gas processing
                                       plant or oil pipeline. 77 Fed. Reg. at 49,543 (adding 40 C.F.R. § 60.5365(d)(i)).For storage
                                       vessels, the threshold for coverage is 6 tons per year of VOC. 77 Fed. Reg. at 49,543,
                                       49,556 (adding 40 C.F.R. §§ 60.5365(e), 60.5430).
                                       70
                                         EPA, Regulatory Impact Analysis: Final New Source Performance Standards and
                                       Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil
                                       and Natural Gas Industry (April 2012) at 3-12.
                                       71
                                         EPA also regulated centrifugal and reciprocating compressors at downstream sites, but
                                       those located at a well site, or an adjacent well site and servicing more than one well site,
                                       are not covered. 77 Fed. Reg. at 49,543 (adding 40 C.F.R. § 60.5365(b), (c)).




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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


Other NSPS   EPA has issued equipment-focused NSPS for certain equipment that may
             be used at oil and gas well sites. These include NSPS for Volatile Organic
             Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels). 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 EPA officials said that,
             while there are tanks at well sites, they are often smaller than the
             threshold in this rule. Specifically, while the standards apply to tanks
             greater than 75 cubic meters (about 475 barrels, according to EPA), an
             individual tank typically found at oil and gas sites is often between 250 –
             400 barrels, hence avoiding coverage under this rule.

             Other NSPS that have been identified as potentially relevant include
             those for gas turbines and steam generators. 75 EPA officials said,
             however, that typical activity at well sites is not enough to trigger
             thresholds for coverage under this rule, either.




             72
               77 Fed. Reg. at 49,543 (adding 40 C.F.R. § 60.5370(c)) (provided the facility is not
             otherwise required by law to obtain a Title V operating permit or new source review
             permit).
             73
              40 C.F.R. pt. 60, subpt. Kb (2012).
             74
              40 C.F.R. § 60.110b(d)(3) (2012).
             75
              40 C.F.R. pt. 60, subpt. D to Dc (2012). See also EPA, Sector Notebook Project: Oil and
             Gas Extraction, at 100 (2000).




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                    CAA New Source Review (NSR) provisions require a source to obtain a
New Source Review   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
                    contaminants 77 at or above certain threshold levels established in the NSR
                    regulations. For a new source, NSR is triggered only if the emissions would
                    cause the source to qualify as major. For an existing major source making
                    a modification, NSR is triggered only if the modification will result in a
                    significant increase in emissions and a significant net emissions increase of
                    that pollutant. Relevant to NSR, the emission profile for oil and gas wells
                    would include hydrogen sulfide and VOCs, among others. In most areas,
                    states implement the NSR permitting programs.

                    The major NSR program is actually composed of the following two
                    separate programs:

                    •     Nonattainment NSR applies to emission of specific pollutants from
                          sources located in areas designated as nonattainment for those
                          pollutants because they do not meet the pollutant-specific national
                          ambient air quality standards.

                    •     Prevention of Significant Deterioration (PSD) applies to emissions of
                          all other regulated pollutants from sources located in attainment areas
                          where such standards are met or in areas unclassifiable for such
                          standards.

                    For PSD, the major source threshold is generally 250 tons per year of any
                    regulated air pollutant. 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 While a



                    76
                      CAA §§ 165(a), 173(a), 42 U.S.C. §§ 7475(a), 7503(a) (2012); see generally CAA §§
                    160-169, 171-189, 42 U.S.C. §§ 7470-7479 (Prevention of Significant Deterioration),
                    7501-7513 (NSR nonattainment) (2012).
                    77
                      Potential to emit generally means the maximum capacity of a stationary source to emit
                    any air pollutant under its physical and operational design, taking into account any
                    federally enforceable limitations.
                    78
                        CAA §§ 169(1), 165(a), 42 U.S.C. §§ 7479(1), 7475(a) (2012).
                    79
                        40 C.F.R. § 52.21(b)(5)-(6) (2012).




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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
Title V Operating   for the operation of
Permits
                    •     any major source 84 determined based on the facility’s actual
                          emissions or “potential to emit;”

                    •     any source, including a nonmajor source, subject to a NSPS;

                    •     any source, including an area source, subject to a NESHAP, among
                          others; and

                    •     any source required to obtain a PSD or NSR permit. 85



                    80
                      EPA, Report to Congress on Hydrogen Sulfide Emissions Associated with the Extraction
                    of Oil and Gas, EPA-453-R-93/045 at IV-37 (1993).
                    81
                     Gina McCarthy, AA Office of Air and Radiation, Memorandum, “Withdrawal of Source
                    Determinations for Oil and Gas Industries” (Sept. 22, 2009).
                    82
                        40 C.F.R. § 51.165 (2012).
                    83
                        40 C.F.R. § 51.165 (2012).
                    84
                      Major source for Title V purposes is defined more broadly than for NESHAP purposes.
                    Cf. CAA § 501(2) to § 112(a)(1), 42 U.S.C. § 7661(2) to § 7412(a)(1) (2012).




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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 may need to add
monitoring, reporting, or other requirements but generally do not add new
emissions control requirements (rather they consolidate requirements from
throughout CAA programs and contain conditions to assure compliance
with such requirements). According to EPA officials, the permits help
operators and the public to understand what the requirements are for
compliance with CAA and help assure compliance with such requirements.

Title V permits are generally issued by states and, in some instances,
EPA Regional offices. As of August 2012, EPA officials were unaware of
any Title V permits issued solely on the basis of oil and gas well site
emissions alone. EPA officials stated that some oil and gas well sites
have adopted federally enforceable emissions limits such that the sites do
not need a Title V permit, which they would otherwise have triggered. In
addition, EPA identified a March 2012 case in which a state
environmental agency alleged, among other things, that an oil and gas
production site had VOC emissions of over 600 tpy, which would require
a Title V permit. The operator disputed the violations but agreed to submit
an application for a Title V permit.




85
  CAA § 501(2), 42 U.S.C. § 7661(2) (2012), 40 C.F.R. §§ 70.3(a), 70.5(a)(1)(ii), 71.3(a),
71.5(a)(1)(ii) (2012).
86
  EPA has the authority to exempt through rulemaking area sources or non-major sources
from the Title V permit requirement if they are not otherwise subject to Title V. CAA
§ 502(a), 42 U.S.C. §7661a(a) (2012). Major sources under Title V may not be exempted.
87
 40 C.F.R. §§ 70.3(c)(1), 71.3(c)(1) (2012).
88
 40 C.F.R. §§ 70.3(c)(2) 71.3(c)(2) (2012).




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                         Applicable to both NSR and related determinations for Title V, EPA
Source                   regulations specify three factors that must be met in source
Determinations and       determinations—whether the emissions points are under common control,
                         belong to the same major industrial grouping, 89 and are located on
Aggregation Issues for   contiguous or adjacent properties. 90 Thus, in contrast to the NESHAPs, in
Title V and NSR          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 In addition,
                         EPA Regions may be responsible for source determinations in areas where
                         they are responsible for permitting.

                         Aggregation of emissions from the oil and gas industry generally,
                         including production facilities, has received recent attention. 93 For


                         89
                           All oil and gas emission units are in the same major industrial grouping.
                         90
                           40 C.F.R. §§ 71.2, 70.2 (2012) (definition of major source for Title V permitting), §§
                         51.165(a)(1)(i)-(ii), (iv) (definition of major stationary source for NSR), 51.166(b)(5)-(6),
                         52.21(b)(5)-(6) (definitions of stationary source for NSR) (2012).
                         91
                           See, e.g., Letter, Cheryl L. Newton, EPA Air and Radiation Division, to Scott Huber,
                         Summit Petroleum Corporation (Oct. 18, 2010) (aggregating gas wells, a sweetening
                         plant, and associated flares as constituting a single source for purpose of Title V
                         permitting).
                         92
                          Gina McCarthy, AA Office of Air and Radiation, Memorandum, “Withdrawal of Source
                         Determinations for Oil and Gas Industries” at 2 (Sept. 22, 2009).
                         93
                           See, e.g., Roger Martella et al, Aggregation of Oil and Gas Wells Under the Clean Air
                         Act: New Horizons from EPA and the Courts, Natural Resources and Environment (Fall
                         2011); http://www.natlawreview.com/article/oil-gas-activities-agencies-are-air-air-
                         regulations




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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 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



94
  See Id.; William Wehrum, Memorandum, “Source Determinations for Oil and Gas
Industries” (Jan. 12, 2007).
95
  Gina McCarthy, AA Office of Air and Radiation, Memorandum, “Withdrawal of Source
Determinations for Oil and Gas Industries” (Sept. 22, 2009).
96
  See Summit Petroleum Corp. v. EPA, Nos. 09-4348, 10-4572, slip op. (6th Cir. August
7, 2012).
97
  See EPA, Order Responding To Petitioners’ Request That The Administrator Object To
Issuance Of A State Operating Permit, Petition Number: VIII-2010-4 (Feb. 2, 2011).
98
 WildEarth Guardians et al. v. Jackson, No.11-9527 (10th Cir).




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                 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,
Greenhouse Gas   providing a framework for the greenhouse gas reporting program and
Reporting Rule   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




                 99
                  In re BP America Production Co., Florida River Compression Facility, Environmental
                 Appeals Board Appeal No. CAA 10–04.
                 100
                    Wildearth 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).
                 101
                      74 Fed. Reg. 56,260 (Oct. 30, 2009), 40 C.F.R. pt. 98.
                 102
                    See, e.g., EPA, Economic Impact Analysis for the Mandatory Reporting of Greenhouse
                 Gas Emissions Under Subpart W Supplemental Rule (GHG Reporting), Final Report 2-1 –
                 2-2 (2009).




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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
equivalent 106 per year to report certain data to EPA. Specifically, oil and
gas production facilities are to report annual emissions of carbon dioxide,
methane, and nitrous oxide from

•     equipment leaks and venting,

•     gas flaring, and

•     stationary and portable combustion. 107

Reporting is to begin in September 2012, for calendar year 2011. 108




103
  75 Fed. Reg. 74,458 (Nov. 30, 2010), 76 Fed. Reg. 59,533 (Sept. 27, 2011), 76 Fed.
Reg. 73,886 (Nov. 29, 2011), 76 Fed. Reg. 80,554 (Dec. 23, 2011); 40 C.F.R. pt. 98
Subpt. W. See also http://www.epa.gov/climatechange/emissions/subpart/w.html
104
   EPA, Quantifying Greenhouse Gas Emissions from Key Industrial Sectors in the United
States 12-2 (Working Draft May 2008).
105
   EPA, Economic Impact Analysis for the Mandatory Reporting of Greenhouse Gas
Emissions Under Subpart W Supplemental Rule (GHG Reporting), Final Report 1-10
(2009).
106
   Carbon dioxide equivalent measures the total greenhouse gases, accounting for the
relative ability of each greenhouse gas to trap heat in the atmosphere, known as the
global warming potential.
107
   40 C.F.R. § 98.232(c), (c)(12)-(13) (well flaring during testing and production), (c)(21)
(leaks), (c)(22) (combustion) (2012).
108
    76 Fed. Reg. 73,886, 73,889, 73,899 (Nov. 29, 2011) (amending 40 C.F.R. § 98.3).




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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-transportation-
                      related equipment, and leased, rented or contracted equipment or storage
                      facilities), used in the production, extraction, recovery, lifting, stabilization,
                      separation, or treating of petroleum and/or natural gas (including
                      condensate). 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
Accidental Releases   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


                      109
                        75 Fed. Reg. 74,458, 74,461 (Nov. 30, 2010), 40 C.F.R. § 98.230(a)(2) (2012).
                      110
                         40 C.F.R. §§ 98.238, 98.236(c)(10)-(11) (2012) ( “Facility with respect to onshore
                      petroleum and natural gas production for purposes of reporting under this subpart and for
                      the corresponding subpart A requirements means all petroleum or natural gas equipment
                      on a single well-pad or associated with a single well-pad and CO2EOR operations that are
                      under common ownership or common control including leased, rented, or contracted
                      activities by an onshore petroleum and natural gas production owner or operator and that
                      are located in a single hydrocarbon basin as defined in §98.238. Where a person or entity
                      owns or operates more than one well in a basin, then all onshore petroleum and natural
                      gas production equipment associated with all wells that the person or entity owns or
                      operates in the basin would be considered one facility.”).
                      111
                        75 Fed. Reg. 74,458, 74,467 (Nov. 30, 2010).
                      112
                        75 Fed. Reg. 74,458, 74,479 (Nov. 30, 2010).




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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


Accidental Release    Whether and the extent to which a facility is subject to the Risk
Prevention (Risk      Management Program requirements depends on the regulated
Management Program)   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 As amended, the following chemicals that may
                      be found at oil and gas sites are excluded from threshold determinations:




                      113
                         CAA § 112(r)(7), (r)(2)(A), 42 U.S.C. § 7412(r)(7), (r)(2)(A) (2012) (defining accidental
                      release as “an unanticipated emission of a regulated substance or other extremely
                      hazardous substance into the ambient air from a stationary source.”).
                      114
                         Id. at § 7412(r)(3).
                      115
                         40 C.F.R. § 68.130 (2012).
                      116
                         CAA § 112(r)(6), 42 U.S.C. § 7412(r)(6), (6)(C) (2012).
                      117
                         Id. at § 7412(r)(1).
                      118
                         40 C.F.R. § 68.12 (2012).
                      119
                         63 Fed. Reg. 640 (Jan. 6, 1998); 65 Fed. Reg. 13,243, 13,244 (Mar. 13, 2000).




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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 and

•     a flammable substance when the substance is used as a fuel. 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


120
    40 C.F.R § 68.115(b)(2)(iii), 68.3 (2012); 63 Fed. Reg. 640, 641 (Jan. 6, 1998).
121
    40 C.F.R § 68.115(b)(2)(ii) (2012); 63 Fed. Reg. 640, 641 (Jan. 6, 1998).
122
    40 C.F.R § 68.126 (2012).
123
    63 Fed. Reg. 640, 641 (Jan. 6, 1998).
124
    65 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.


General Duty to Prevent   Section 112(r) also provides, in relevant part:
Accidental Releases
                                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
                                                                                                    128
                                minimize the consequences of accidental releases which do occur.

                          Known as the “general duty clause,” the provision is analogous to a
                          negligence standard, according to EPA officials. In other words, if there is
                          a known risk and a way to mitigate it, then the operator should conduct
                          risk mitigation. As explained in an EPA report, “responsibilities include the
                          conduct of appropriate hazard assessments and the design, operations,



                          125
                              Pub. L. No. 106–40 § 2,113 Stat. 207 (1999) (Section 2 of the Act immediately
                          removed EPA’s authority to ‘‘list a flammable substance when used as a fuel or held for
                          sale as a fuel at a retail facility * * * solely because of the explosive or flammable
                          properties of the substance, unless a fire or explosion caused by the substance will result
                          in acute adverse health effects from human exposure to the substance, including the
                          unburned fuel or its combustion byproducts, other than those caused by the heat of the
                          fire or impact of the explosion.’’
                          126
                             65 Fed. Reg. at 13,247.
                          127
                             40 C.F.R. § 68.115(b)(2)(iii) (2012).
                          128
                             CAA § 112(r)(1), 42 U.S.C. § 7412(r)(1) (2012).




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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.


Imminent and Substantial   Section 112(r) also provides EPA with the authority to issue orders as
Endangerment Authority     may be necessary to protect the public health when the EPA
Respecting Accidental      Administrator determines that there may be an imminent and substantial
                           endangerment to human health or welfare or the environment because of
Releases                   an actual or threatened accidental release of a regulated substance. 131




                           129
                             EPA, Report to Congress on Hydrogen Sulfide Emissions Associated with the
                           Extraction of Oil and Gas, EPA-453-R-93/045 at IV-35 (1993).
                           130
                             See http://www.epa.gov/oem/publications.htm#alerts
                           131
                             CAA § 112(r)(9)(A), 42 U.S.C. § 7412(r)(9)(A) (2012).




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Chemical Safety Board   The Chemical Safety Board, established by section 112(r), is charged
                        with investigating and publicly reporting on accidental releases resulting
                        in a fatality, serious injury, or substantial property damages. The board is
                        authorized, among other things, to make recommendations to EPA. In
                        September 2011, the Chemical Safety Board released a report
                        investigating three incidents involving fatality and injuries at oil and gas
                        storage tanks located at well sites and surveyed an additional 23 such
                        incidents that occurred between 1983 and 2010. 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
                        CWA 133 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 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




                        132
                          U.S. Chemical Safety and Hazard Investigation Board, Investigative Study Final
                        Report: Public Safety at Oil and Gas Storage Facilities, Report No. 2011-H-1 (September
                        2011) [hereinafter Chemical Safety Board Report].
                        133
                           Note that the Clean Water Act spill prevention control, and countermeasure (SPCC)
                        rule requires oil and gas production facilities meeting applicability thresholds to prepare
                        SPCC plans generally by November 2011, or before commencing operation. 40 C.F.R. pt.
                        112 (2012). However, oil production facilities are excluded from the SPCC regulations’
                        security provisions. Id. at § 112.7(g).
                        134
                          Chemical Safety Board Report at 8. See 40 C.F.R. § 112.7(g) (2012).
                        135
                          Chemical Safety Board Report at 52.
                        136
                           See 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




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                  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
EPA Enforcement   oversight and enforcement authority. For example, EPA may initiate an
Authorities       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
Imminent and      present an imminent and substantial endangerment to public health or
Substantial       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
Endangerment      necessary action. 141 EPA must first consult with state and local authorities
Authority         and attempt to confirm the accuracy of information before taking such
                  actions.




                  137
                     Regarding the four specific items the Board recommended for inclusion, EPA stated
                  that it will address three, but the fourth item is under the jurisdiction of another agency.
                  138
                     Chemical Safety Board Report at 52-54.
                  139
                    CAA § 113(a)(1) and (3), 42 U.S.C. § 7413(a)(1) and (3) (2012); see generally CAA §
                  113, 42 U.S.C. § 7413 (2012).
                  140
                     CAA § 114(a), 42 U.S.C. § 7414(a) (2012).
                  141
                     CAA § 303, 42 U.S.C. § 7603 (2012).




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


Authorities under the Resource Conservation
and Recovery Act
                  In 1976, Congress passed the Resource Conservation and Recovery Act
                  (RCRA), generally establishing EPA authority to regulate the generation,
                  transportation, treatment, storage, and disposal of hazardous waste, 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
Subtitle C –      “cradle-to-grave” management of hazardous wastes. RCRA defines
Hazardous Waste   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,
                                                                             5
                      transported, or disposed of, or otherwise managed.

                  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).




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                            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


Exemption of Certain Oil    Notwithstanding the provisions for identifying hazardous wastes, the Solid
and Gas Production          Waste Disposal Act Amendments of 1980 created a separate process for
Wastes from Regulation as   certain oil and gas exploration and production wastes. Under the statute,
                            these wastes would not be subject to regulation as hazardous waste under
Hazardous Waste under       RCRA Subtitle C unless specific actions were taken. 8 The amendments
RCRA Subtitle C             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).
                            10
                                Id.




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     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
                                                                                        14
     Subtitle C permitting burden for State and Federal hazardous waste programs.




11
 42 U.S.C. § 6921(b)(2)(B)-(C) (2012).
12
  53 Fed. Reg. 25,446, 25,447 (July 6, 1988). The study, titled “Management of Wastes
from the Exploration, Development, and Production of Crude Oil, Natural Gas, and
Geothermal Energy “ was submitted to Congress in December 1987. See also
Clarification of the Regulatory Determination for Wastes From the Exploration,
Development and Production of Crude Oil, Natural Gas and Geothermal Energy, 58 Fed.
Reg. 15,284 (Mar. 22, 1993).
13
 53 Fed. Reg. at 25,450.
14
 Id. at 25,446.




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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 EPA’s work with states featured
audits that ultimately led to the State Review of Oil and Natural Gas


15
 Id. at 25,447.
16
 Id.
17
 Id.
18
 Id. at 25,457.
19
 EPA, Exploration & Production Waste and RCRA, presented at ASTSWMO Annual
Meeting (Oct. 26, 2011).




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Environmental Regulations (STRONGER) program. 20 EPA also worked
with industry representatives to develop best management practices for
exploration and production wastes, but these efforts did not culminate in
any document or guidance.

On September 8, 2010, the Natural Resources Defense Council
submitted a petition requesting regulation of waste associated with the
exploration, development, or production of oil, natural gas, and
geothermal energy. 21 The petition asserts that EPA can and should revisit
the determination not to regulate these wastes because, among other
things, the underlying assumptions—concerning the availability of
alternative disposal practices, the adequacy of state regulations, and
economic harm to the oil and gas industry—are no longer valid. The
petition requests that EPA promulgate regulations applying to wastes
from the exploration, development and production of oil and natural gas
under Subtitle C of RCRA.

EPA officials told us the petition is currently under consideration and that
the agency has not established a time frame for its decision. 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 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


20
  The STRONGER program is conducted through the Ground Water Protection Council
and brings together stakeholders to examine state oil and gas regulations and make
recommendations for improvement.
21
  Letter, NRDC to EPA, Petition for Rulemaking Pursuant to Section 6974(a) of the
Resource Conservation and Recovery Act Concerning the Regulation of Wastes
Associated with the Exploration, Development, or Production of Crude Oil or Natural Gas
or Geothermal Energy (Sept. 8, 2010); see also RCRA § 7004(a), 42 U.S.C. § 6974(a)
(2012).
22
  See RCRA § 7004(a), 42 U.S.C. § 6974(a) (2012) (requiring only that EPA shall take
action on a petition to promulgate regulations “within a reasonable time following receipt”
of the petition.)
23
 EPA, Exploration & Production Waste and RCRA, presented at ASTSWMO Annual
Meeting (Oct. 26, 2011).




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                           issue, the agency intends to issue a proposed response to the petition.
                           The proposed response will be printed in the Federal Register, and EPA
                           will establish an electronic docket and provide an opportunity for public
                           comment. Although EPA has not yet sought public comment on the
                           petition, the agency has received several unsolicited comment letters,
                           including from two industry associations, the STRONGER program, and
                           two states.

                           If EPA revises the regulatory determination for some or all exploration
                           and production wastes, the agency would conduct a full regulatory
                           process to propose the regulations. Under the key RCRA provision, the
                           regulations would not become effective until authorized by congressional
                           action. Should the exemption be lifted, not all exploration and production
                           wastes would necessarily be hazardous. Rather, whether particular
                           exploration and production wastes would be hazardous and subject to
                           regulation would depend on whether those particular wastes meet the
                           regulatory definition of hazardous (i.e., are a listed waste or exhibit a
                           characteristic of hazardous waste).


Oil and Gas Exploration    While well sites wastes originating within the well or generated by field
and Production Wastes      operations such as water separation, demulsifying, degassing, and
That Are Not Exempt from   storage are exempt, RCRA Subtitle C regulations generally apply to other
                           wastes that may be generated at oil and gas wells, such as discarded
Regulation                 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;




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•      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 as well as


24
    40 C.F.R. § 261.5, pt. 262 (2012).
25
    Id. at § 261.5(a).
26
    Id. at (g)(2).




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general requirements to determine which wastes are hazardous 27 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
hazardous 31 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 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




27
  Id. at § 262.11.
28
  Id. at § 261.5(g)(3). If the facility generates a subset of hazardous waste known as acute
hazardous waste, it is subject to additional requirements for that waste. Id. at § 261.5(f)(3).
29
  Id. at §§ 261.5(b), 262.12.
30
  Id. at § 261.34.
31
  Id. at § 262.11.
32
  Id. at g)(3). If the facilities generate a subset of hazardous waste known as acute
hazardous waste, it is subject to additional requirements for that waste. Id. at § 261.5(f)(3).
33
  Id. at §§ 262.12, 262.20.
34
  Id. at § 262.12(a) (a generator, other than a conditionally exempt small quantity
generator, is essentially required to obtain an identification number before storing the
waste or offering it to a transporter.).




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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 conducting
compliance assurance activities such as inspections, and investigating
alleged problems.

EPA has not undertaken a specific assessment of the extent to which oil
and gas well sites are generating small amounts of regulated hazardous
wastes and consequently are regulated as small quantity generators or
conditionally exempt small quantity generators. EPA officials were
unaware of the extent to which oil and gas well sites generate nonexempt
hazardous waste (e.g., hazardous wastes other than exempt exploration
and production wastes) in quantities significant enough to require an EPA
ID number. EPA Region 8 officials were unaware of any instances in
which a well site requested an EPA ID number. A challenge in
understanding the extent to which oil and gas well sites are regulated
stems in part from the use of North American Industry Classification
System (NAICS) codes. While there is a code at the six-digit level that
generally corresponds with oil and gas production, 37 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




35
  See EPA Form 8700-12.
36
  Biennial reports are only required of large quantity generators. The reports are to
include, among other things, a description of the generated hazardous wastes and the
quantities shipped off-site to a U.S. treatment, storage, or disposal facility. 40 C.F.R.
§ 262.41 (2012).
37
  NAICS code 211111, Crude Petroleum and Natural Gas Extraction. A further
complication in the context of this report is our scope is focused on unconventional
resources produced using land-based wells, where the NAICS code at the six-digit level
does not reflect these distinctions and includes other resources and offshore wells.




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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
Subtitle D – Solid   solid wastes even if they are exempt from hazardous waste requirements
Waste                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 role 41 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



                     38
                       EPA officials from one Region believed some well sites may be small quantity
                     generators of hazardous waste.
                     39
                       See, e.g., RCRA §§ 1003(a)(1)-(3), 4001, 42 U.S.C. §§ 6902(a)(1)-(3), 6941 (2012).
                     40
                       See, e.g., RCRA § 1008, 42 U.S.C. § 6907 (2012), 40 C.F.R. pt. 243 (2012) (Guidelines
                     for the Storage and Collection of Residential, Commercial, and Institutional Solid Waste,
                     containing guidelines that are recommended but not required for states).
                     41
                       In addition, for two types of solid waste disposal facilities (those receiving conditionally
                     exempt small quantity generator waste and household hazardous wastes), RCRA
                     provided that states must implement an EPA-approved system to assure the facilities
                     comply with EPA criteria, or the facilities would be subject to EPA hazardous waste
                     enforcement authorities. RCRA § 4005(c)(1)(A)-(B), 42 U.S.C. § 6945(c)(1)(A)-(B) (2012)
                     (providing that each State shall adopt and implement a permit program or other system of
                     prior approval and conditions to assure that each solid waste management facility within
                     such State which may receive hazardous household waste or hazardous waste [from
                     small quantity generators] will comply with,” respectively, the applicable initial and revised
                     criteria established by EPA), RCRA § 4005(c)(1)(C), 42 U.S.C. § 6945(c)(1)(C) (2012)
                     (EPA shall determine if each program is adequate); see 40 C.F.R. pts. 239, 257 subpt. B;
                     258 (2012).
                     42
                       RCRA §§ 1008(a)(3), 4004, 42 U.S.C. §§ 6907(a)(3), 6944, 40 C.F.R. § 257.1, pt. 257,
                     § 258.1(g), pt. 258 (2012). See also 53 Fed. Reg. 25,446 (July 6, 1988) (noting that “[t]he
                     existing Federal standards under Subtitle D of RCRA provide general environmental
                     performance standards for disposal of solid wastes, including oil, gas, and geothermal
                     wastes, but these standards do not fully address the specific concerns posed by oil and
                     gas wastes. Nevertheless, EPA has authority under Subtitle D to promulgate more tailored
                     criteria.”).
                     43
                       RCRA § 4005(a), 42 U.S.C. §§ 6945(a) (2012).




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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.
Enforcement   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 These orders may require the person
              to come into compliance immediately or by a specific time frame and/or


              44
                RCRA §§ 3007, 3008, 3013, 42 U.S.C. §§ 6927, 6928, 6934 (2012).
              45
                Cf. RCRA § 1004(5), 42 U.S.C. § 6903(5) (2012) with 40 C.F.R. §§ 261.3,-4 (2012).
              46
                RCRA § 3008, 42 U.S.C. § 6928 (2012).
              47
                EPA also has authorities to require corrective action or such other response measure as
              necessary to protect human health or the environment from past and present
              contamination, at RCRA permitted or interim status facilities—that is, where the facility is a
              storage, treatment, or disposal facility and has or should have a Subtitle C hazardous
              waste permit. EPA can use this corrective action authority only at facilities that are RCRA
              permitted or interim status facilities, and cannot require a corrective action at a generator-
              only facility. Interim status facilities are facilities that treat, store, or dispose of hazardous
              waste and have begun the process of applying for a RCRA permit. See RCRA §§ 3004(u)-
              (v), 3008(h), 42 U.S.C. §§ 6924(u)-(v), 6928(h) (2012).




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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
EPA officials did not provide any examples of EPA using its section 3007
authority at oil or gas well sites.

Section 3013 authorizes EPA to issue an order requiring monitoring,
testing, analysis, and reporting if the EPA Administrator determines, upon
receipt of any information, that the presence or release of any hazardous
waste at a facility or site at which hazardous waste is, or has been,
stored, treated, or disposed of may present a substantial hazard to
human health or the environment. 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




48
  RCRA § 3007(a), 42 U.S.C. § 6927(a) (2012).
49
  Id. at § 6927(e) (2012).
50
  See, e.g., 53 Fed. Reg. 25,446, 25,457 (1988) (“EPA believes this [section 3007]
authority does not limit information collection to “hazardous” waste identified under
Subtitle C, but also authorizes the collection of information on any solid waste that the
Agency reasonably believes may pose a hazard when improperly managed. (EPA may
also use this authority in preparing enforcement actions.)”).
51
  RCRA § 3013(a), 42 U.S.C. § 6934(a) (2012).
52
  Id. 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
Imminent and   both hazardous and solid wastes. Section 7003 authorizes EPA to issue
Substantial    administrative orders and to file suit in federal district court. In addition,
               “upon receipt of evidence that the past or present handling, storage,
Endangerment   treatment, transportation or disposal of any solid waste or hazardous
Authority      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



               53
                 RCRA § 7002, 42 U.S.C. § 6972 (2012). RCRA section 7002 authorizes citizen and
               state suits including against any person who is alleged to be in violation of any permit,
               standard, regulation, condition, requirement, prohibition, or order which has become
               effective pursuant to RCRA, or who has contributed or is contributing to the past or
               present handling, storage, treatment, transportation, or disposal of any solid or hazardous
               waste which may present an imminent and substantial endangerment to health or the
               environment. Citizen suits are subject to various conditions, such as a requirement for
               advance notice to EPA and the state, and that neither EPA nor the state is taking certain
               actions to address the problem.
               54
                RCRA § 7003, 42 U.S.C. § 6973 (2012).
               55
                Id. at § 6973(a).
               56
                Id. at § 6973(b).




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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 Nonetheless, EPA officials noted that a section
7003 action is distinct from, for example, the agency’s Subtitle C
enforcement authorities because the objective of such an action is to
abate the imminent and substantial endangerment, rather than to enforce
specific RCRA requirements. Whether RCRA section 7003 authority is
applicable to a given situation requires a fact-based determination that
the facts establish the statutory elements, including the existence of
conditions that may present an imminent and substantial endangerment.

EPA has issued section 7003 orders at several facilities handling wastes
from oil and gas well sites. For example, as previously discussed, EPA
Region 8 participated in an effort with the FWS, states, and tribes, after
the FWS expressed concerns about migratory birds landing on open pits
that contained oil and water, which killed or harmed the birds. 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 EPA Region 8 has issued section 7003 orders to several
commercial oilfield waste disposal facility operators in Wyoming, finding




57
 RCRA § 1004(5), (27), 42 U.S.C. § 6903(5), (27) (2012).
58
  See EPA. Office of Enforcement and Compliance Assurance, Guidance on the Use of
Section 7003 of RCRA (October 1997).
59
 EPA Region 8, Oil and Gas Environmental Assessment Effort 1996 – 2002, at v (2003).
60
 Id. at 8.
61
 Id.




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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




62
  In the Matter of Jim’s Water Service, Initial Administrative Order, EPA Docket No.
RCRA-08-2011-0002 (June 23, 2011); In the Matter of Pure Petroleum LLC,
Administrative Order, EPA Docket No. RCRA-08-2011-0003 (Sept. 16, 2011). See also
Consent Decree, United States of America v. High Plains Resources, Inc., No. 2:09-cv-
00087 (Wy. Nov. 3, 2010).
63
  West Bay Exploration, Agreement and Remediation Plan, EPA Docket No. RCRA-06-
2005-0913 (Sept. 14, 2005).




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

under the Comprehensive Environmental
                          Liability Act



Response, Compensation, and Liability Act

                          In 1980, Congress passed the Comprehensive Environmental Response,
                          Compensation, and Liability Act (CERCLA), often referred to as
                          “Superfund,” to address the cleanup of releases of hazardous
                          substances, pollutants, and contaminants nationwide and, in so doing,
                          protect human health and the environment from their effects. 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.


Relevant Exclusions and   Under a provision known as the petroleum exclusion, CERCLA’s
Definitions               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.




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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 The statutory definition for such federally permitted
releases exempt from CERCLA liability and reporting also includes:

    any injection of fluids or other materials authorized under applicable State law (i) for the
    purpose of stimulating or treating wells for the production of crude oil, natural gas, or
    water, (ii) for the purpose of secondary, tertiary, or other enhanced recovery of crude
    oil or natural gas, or (iii) which are brought to the surface in conjunction with the
                                                                        8
    production of crude oil or natural gas and which are reinjected.

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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CERCLA Hazardous    Where there has been a release of a hazardous substance, CERCLA
Substance Release   section 103 requires a person in charge of a facility to report such
Reporting           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 Oil and gas well operators would be required to report any
                    releases to the environment of other hazardous substances, for example,
                    if a stored hazardous substance was accidentally spilled onto the ground,
                    or if hazardous substances above the reportable quantity were injected
                    but not authorized by state law.

                    The National Response Center—managed by the U.S. Coast Guard—
                    receives release reports and forwards them to EPA Regions. When
                    receiving a report, according to EPA Regional staff will screen the report
                    for such factors as what was spilled and in what quantity and whether the
                    spill threatens surface waters, to determine if EPA needs to respond and,
                    if appropriate, will obtain additional information on the event, and/or send
                    an on-scene coordinator to the site. EPA officials also noted they use the
                    release reports to refer sites to program enforcement offices, such as the
                    Clean Water Act’s SPCC program, for follow-up. Although release reports
                    are publicly available, the available search terms do not readily
                    differentiate oil and gas well sites from other types of oil and gas facilities.
                    EPA officials noted that there had been approximately 200 reports of oil
                    spills from oil facilities in the last 5 years. EPA Region 5 officials stated
                    that oil spills are more often related to pipelines, tank sites, or trucking
                    accidents, with few occurring at well sites.




                    10
                       CERCLA § 103(a), 42 U.S.C. § 9603(a) (2012). The National Response Center is the
                    sole federal point of contact for reporting all hazardous substances and oil spills that
                    trigger federal notification requirements under several laws. Information reported to the
                    Center is disseminated to other agencies, such as EPA, as well as to states.
                    11
                      40 C.F.R. pt. 302, § 302.4 at table 302.4 (2012).
                    12
                      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).




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Relevant EPA Authorities   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 responsible 14 for
                           contaminating sites—via releases of hazardous substances—to clean
                           them up, as well as to enter into agreements with such parties for them to
                           conduct the cleanup. In addition, EPA can itself conduct response
                           actions, which may include investigations and cleanup activities, and then
                           seek reimbursement from the responsible parties.

                           The Superfund cleanup process involves a series of steps during which
                           specific activities—such as investigations and cleanups—take place or
                           decisions are made. The CERCLA program has two basic types of
                           cleanup: (1) cleanups under the removal process, which generally
                           address short-term threats, and (2) cleanups under the remedial action
                           process, which are generally longer-term cleanup actions. 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


                           13
                             Through Executive Order 12580, Superfund Implementation (1987), EPA was delegated
                           key regulatory and enforcement authorities CERCLA granted to the President. In addition,
                           CERCLA, as amended, granted certain authorities directly to the EPA Administrator.
                           14
                             Under CERCLA, potentially responsible parties generally include current or former
                           owners and operators of a site or the generators or transporters of the hazardous
                           substances.
                           15
                             40 C.F.R. § 300.5 (2012) (defining removal as including containment and removal of
                           hazardous substances or other actions as may be necessary to minimize or mitigate
                           damage to the public health or welfare of the United States or to the environment, and
                           defining remedial action as including actions consistent with permanent remedy to prevent
                           or minimize the release so that they do not migrate to cause substantial danger to present
                           or future public health or welfare or the environment.) For more information, see 40 C.F.R.
                           § 300.415 (removals), 300.430, 300.435 (remedial actions).
                           16
                            EPA, Memorandum, “Use of Non-Time Critical Removal Authority in Superfund
                           Response Actions” (2000).




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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




17
    CERCLA § 104(a)(1), (b), 42 U.S.C. § 9604(a)(1), (b) (2012).
18
    Id.
19
    Id. at § 9604(e).
20
    Id. at § 9604(e)(1)-(2).
21
    Id. at § 9604(e)(3)-(4).
22
    Id. at § 9604(e)(4)-(5).
23
    Id. at § 9604(e)(5).




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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 EPA also can issue an administrative
      order requiring a potentially responsible party to take response


24
  Id. at § 9604(a). In addition to removal actions, EPA may also conduct remedial actions
at nonfederal sites which are listed on the National Priorities List, but it is somewhat
unlikely an oil and gas well site would be listed on the National Priorities List in light of the
petroleum exclusion, among other factors. CERCLA §§ 104(a), (c)(1), 111(e), 42 U.S.C.
§§ 9604(a), (c)(1), 9611(e) (2012). The National Priorities List includes sites that EPA
determines are among the nation’s most seriously contaminated hazardous waste sites to
receive attention under the federal Superfund program.
25
    CERCLA § 101(23), 42 U.S.C. § 9601(23) (2012).
26
  See id. at § 9601(33) . EPA cannot, however, recover its response costs associated with
these releases.
27
  EPA has promulgated regulations comprising the National Oil and Hazardous
Substances Pollution Contingency Plan. 40 C.F.R. pt. 300 (2012). This plan outlines
procedures and standards for implementing the Superfund program.
28
    CERCLA § 106(a), 42 U.S.C. § 9606(a) (2012).




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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
EPA is using CERCLA section 104(b) authority to conduct groundwater



29
 Id. at § 9606(a).
30
 See, e.g., CERCLA §§ 107, 122, 42 U.S.C. §§ 9607, 9622 (2012).
31
 See DOJ, news release (Sept. 23, 1999).
32
  See DOJ, news release (Sept. 23, 1999). See also, United States of America v. BP
Exploration (Alaska) Inc., Plea Agreement (Sept. 23, 1999), Stipulation of Settlement and
Order (Sept. 23, 1999), Docket no. 3:99-cv-00549-JKS (D. Alaska).
33
  See Richard M. Fetzer, On-Scene Coordinator EPA, Action Memorandum to Dennis
Carney, Associate Division Director, Hazardous Site Cleanup Division, EPA, re: Request
for Funding for a Removal Action at the Dimock Residential Groundwater Site, Jan. 19,
2012.




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contamination investigations at Pavillion, Wyoming. 34 EPA officials also
referenced CERCLA section 104(e) authority in requesting information
from operators of wells proximate to the Pavillion site.

EPA has used CERCLA section 104(e) in conjunction with other
authorities in several “multimedia” information requests, where EPA
seeks information under multiple statutes and for multiple media—air,
land, water—that may be affected. In 2011, for example, EPA used
CERCLA and other authorities to request information concerning a
blowout at a Marcellus shale natural gas well in Bradford, Pennsylvania.
In this instance, a well blowout during hydraulic fracturing resulted in the
release of flowback fluids to a tributary of the Susquehanna River, as well
as combustible gases to the atmosphere. 35




34
 See EPA, Draft Report, Investigation of Ground Water Contamination near Pavillion,
Wyoming, EPA 600/R-00/000 (December 2011) at xi, 1.
35
 Agency for Toxic Substances and Disease Registry, Health Consultation, Chesapeake
ATGAS 2H Well Site, Leroy Hill Road, Leroy Township, Bradford County, PA (2011).




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


Authorities under the Emergency Planning
and Community Right-to-Know Act
                         The Emergency Planning and Community Right-to-Know Act of 1986
                         (EPCRA) provides a mechanism to help communities plan for
                         emergencies involving extremely hazardous substances, and to provide
                         individuals and communities with access to information regarding the
                         storage and releases of certain toxic chemicals, extremely hazardous
                         substances, and hazardous chemicals in their communities. 1


Generally Applicable     EPCRA imposes a set of generally applicable requirements to report
Chemical Information,    information on the uses, inventories, and releases into the environment of
Inventory, and Release   hazardous and toxic chemicals above threshold quantities. 2 Regarding
                         releases, EPCRA section 304 requires owners or operators of facilities
Reporting
                         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 Where there is overlap,
                         EPCRA’s procedures ensure state and local authorities receive this




                         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.
                         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.




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                          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


Requirements under        Well sites are subject to EPCRA sections 304, 311, and 312, among
EPCRA That May Be         others, and may be subject to reporting requirements to the extent that
Triggered at Well Sites   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 For example, if the



                          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).
                          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).




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aggregate amount of hydrofluoric acid, an extremely hazardous chemical
with a threshold planning quantity of 100 pounds, at a well site exceeds
that threshold then the facility must report under sections 311 and 312. As
another example, if a well stores or uses more than 10,000 pounds of drip
gas or natural gas condensate at any one time, then the facility must
report under sections 311 and 312.

The extent to which these requirements are triggered at oil and gas well
sites depends on the presence and quantities of listed chemicals at such
sites, among other things. We did not locate any publicly available data
on the quantity of chemicals stored at actual or typical well sites, but
FracFocus 10 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 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


10
  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.
11
  Cf. http://fracfocus.org/chemical-use/what-chemicals-are-used and 40 C.F.R. § 302.4
(2012).
12
  EPCRA sections 311 and 312, 42 U.S.C. §§ 11021, 11022 (2012), require reporting to
the state and local emergency planning authorities and to the local fire department with
jurisdiction over the facility; EPA does not receive these reports.




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                          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.


Toxic Release Inventory   EPCRA also requires some facilities in listed industries to report to EPA
                          their releases of listed toxic chemicals to the environment; 14 at present,
                          these requirements do not apply to oil and gas well operations.


                          13
                            EPA also provided information from an example of a section 312 form from a field
                          service provider for the provider’s facility where larger quantities of chemicals are stored
                          and then loaded on trucks to service the wells.




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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 (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

14
  The Pollution Prevention Act of 1990, Pub. L. No. 101–508 , Title VI, 104 Stat. 1388–
321 (1990) (codified at 42 U.S.C. ch. 133 (2012)) requires facilities subject to EPCRA
section 313 to also report annually toxic chemical source reduction and recycling
activities. 42 U.S.C. § 13106(a)-(b) (2012).
15
 EPCRA § 313(g)(1)(C), 42 U.S.C. § 11023(g)(1)(C) (2012).
16
 Id. at (i).
17
 Pollution Prevention Act, § 6607, 42 U.S.C. § 13106 (2012).
18
 EPCRA § 313(h), 42 U.S.C. § 11023(h) (2012).
19
  Full-time employee is defined as 2,000 hours per year of full-time equivalent
employment. A facility would calculate the number of full-time employees by totaling the
hours worked during the calendar year by all employees, including contract employees,
and dividing that total by 2,000 hours. 40 C.F.R.§ 372.3 (2012).




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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 Oil and gas extraction industries were not included on
the statutory list of Standard Industrial Classification codes and hence
were not subject to the rule.

EPA has since expanded the list of covered industries, but it has not
included oil and gas extraction. 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 groups 26 to the list of
industries required to report releases in a rulemaking known as the Industry


20
  Community Right-to-Know; Toxic Chemical Release Reporting Using NAICS, 71 Fed.
Reg. 32,464, 32,465 (June 6, 2006); see generally
http://www.epa.gov/tri/lawsandregs/naic/ncodes.htm
21
  EPCRA § 313(b)(1)(B), 42 U.S.C. § 11023(b)(1)(B) (2012). EPA can also add individual
facilities. EPCRA § 313(b)(2), 42 U.S.C. § 11023(b)(2) (2012).
22
  53 Fed. Reg. 4500 (Feb. 16, 1988).
23
   Id. at 4503 (stating “EPA has discretionary authority to modify the coverage of facilities
under section 313(b)(1)(B). The report of the congressional conference committee for Title
III states that any such modifications are limited “* * * to adding [Standard Industrial
Classification] codes for facilities which, like facilities within the manufacturing sectors
Standard Industrial Classification codes 20 through 39, manufacture, process or use toxic
chemicals in a manner such that reporting by these facilities is relevant to the purposes of
this section… The Agency is choosing not to modify the facility coverage of the rule at this
time...The Agency must carefully evaluate additional types of facilities that may be
manufacturing, processing, or using listed toxic chemicals as well as facilities in [Standard
Industrial Classification] codes 20 through 39 that do not handle such chemicals.”).
24
  See KWWSZZZHSDJRYWULODZVDQGUHJVQDLFQFRGHVKWP
25
 EPA Office of Compliance, Sector Notebook Project: Profile of the Oil and Gas
Extraction Industry 114 (October 2000).
26
  These industries included metal mining, coal mining, electrical utilities that combust coal
and/or oil for the purpose of generating power for distribution in commerce, certain
hazardous waste processing or destruction facilities regulated by EPA, chemical
wholesalers, petroleum terminals and bulk stations and solvent recovery services.




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Expansion Rule. 27 Oil and gas exploration and production was among nine
candidate industries considered in EPA’s screening process. The preamble
to the proposed Industry Expansion Rule stated in part:

     One industry group, oil and gas extraction classified in [Standard Industrial
     Classification] code 13, is believed to conduct significant management activities that
     involve EPCRA section 313 chemicals. EPA is deferring action to add this industry
     group at this time because of questions regarding how particular facilities should be
     identified. This industry group is unique in that it may have related activities located
     over significantly large geographic areas.

     While together these activities may involve the management of significant quantities of
     EPCRA section 313 chemicals in addition to requiring significant employee
     involvement, taken at the smallest unit (individual well), neither the employee nor the
     chemical thresholds are likely to be met. EPA will be addressing these issues in the
             28
     future.

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




27
  Addition of Facilities in Certain Industry Sectors; Revised Interpretation of Otherwise
Use; Toxic Release Inventory Reporting; Community Right-to-Know, 62 Fed. Reg. 23,834
(May 1, 1997) (known as the Industry Expansion Rule). In announcing the rule, EPA
stated, “EPA believes that [section 313(b)(1)(B)] grants the Agency broad, but not
unlimited, discretion to add industry groups to the facilities subject to EPCRA section 313
reporting requirements where EPA finds that reporting by these industries would be
relevant to the purposes of EPCRA section 313.” See also 71 Fed. Reg. 32,464, 32,465
(June 6, 2006).
28
 61 Fed. Reg. 33,588, 33,592 (June 27,1996).
29
 62 Fed. Reg. 23,834, 23,855 (1997).




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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 EPA officials explained that
the agency has not changed its assessment of the oil and gas sector as it
pertains to TRI reporting since the 1996 proposed rule and stated that
adding oil and gas well sites would likely provide a substantially
incomplete picture of the chemical uses and releases at these sites, and
would therefore be of limited utility in providing information to
communities.

EPCRA section 313 also specified the chemicals subject to the reporting
requirement and provided a process and criteria for EPA to add or delete
chemicals from the list. 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 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,


30
 http://exchange.regulations.gov/exchange/topic/trisectorsrule/agencyintro/tri-exchange
31
  In July 2012, EPA officials stated that if the sector is not proposed to be added to the
TRI, the agency does not anticipate placing documents related to EPA’s consideration of
the oil and gas production sector in the docket for any possible TRI rulemaking.
32
  See, e.g., 75 Fed. Reg. 72,727 (Nov. 6, 2010) (EPA’s most recent addition to the TRI list
of chemicals, adding 16 chemicals reasonably expected to be carcinogenic).
33
 61 Fed. Reg. 33,588, 33,592 (June 27,1996).




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              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


Enforcement   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




              34
               76 Fed. Reg. 64,022 (Oct. 17, 2011).
              35
               Id. at 64,025.
              36
               EPCRA § 325, 42 U.S.C. § 11046 (2012).
              37
               Id. at § 11046(c)(1), (2), (4).
              38
                   Id. at § 11046( b).




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


Authorities under the Toxic Substances
Control Act
              To help protect human health and the environment, the Toxic Substances
              Control Act (TSCA) authorizes EPA to regulate the manufacture,
              processing, use, distribution in commerce, and disposal of chemical
              substances and mixtures. 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).




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chemicals on the FracFocus 5 list of “chemicals used most often” which
are on the TSCA inventory. 6 These examples, which EPA chose as
representative of different product function categories, are as follows:

•   Hydrochloric acid – Acid;

•   Peroxydisulfuric acid, ammonium salt – Breaker;

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

•   Methanol – Corrosion Inhibitor; and

•   2-Propenamide, homopolymer – Friction Reducer.

As part of EPA’s Study on the Potential Impacts of Hydraulic Fracturing
on Drinking Water Resources, EPA is currently analyzing information
provided by nine hydraulic fracturing service companies, including a list of
chemicals the companies identify as used in hydraulic fracturing
operations. EPA officials said that they expect most of these chemicals
disclosed by the service companies to appear on the TSCA inventory list,
provided that chemicals are not classified solely as pesticides. EPA does
not expect to be able to compare the list of chemicals provided by the
nine hydraulic fracturing service companies to the TSCA inventory until
the release of a draft report of the Study on the Potential Impacts of
Hydraulic Fracturing on Drinking Water Resources for peer review,
expected in late 2014. For those chemicals that are listed, some hydraulic
fracturing service companies may be manufacturers, processors, or
distributors, and could be subject to certain TSCA reporting provisions.




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 multi-
state government agency that promotes the conservation and efficient recovery of
domestic oil and natural gas resources while protecting health, safety, and the
environment. http://www.fracfocus.org
6
 See http://www.epa.gov/oppt/existingchemicals/pubs/tscainventory,
http://fracfocus.org/chemical-use/what-chemicals-are-used.




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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.
10
  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.
11
  Stephen A. Owens, Assistant Administrator EPA, Letter to Deborah Goldberg,
Earthjustice, Re: TSCA Section 21 Petition Concerning Chemical Substances and
Mixtures Used in Oil and Gas Exploration or Production, Nov. 23, 2011.




Page 190                               GAO-12-874 Unconventional Oil and Gas Development
Appendix VIII: Key Requirements and
Authorities under the Toxic Substances
Control Act




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




12
 TSCA § 8(a)(1)-(2), 15 U.S.C. § 2607(a)(1)-(2) (2012).
13
 TSCA § 8(d), 15 U.S.C. § 2607(d) (2012).
14
 TSCA §§ 16(a)(1), 15, 15 U.S.C. §§ 2615(a)(1), 2614 (2012).
15
 TSCA § 5(a)(1), 15 U.S.C. § 2604(a)(1) (2012). See also 40 C.F.R. pt. 720 (2012).
16
 TSCA § 15(2), 15 U.S.C. § 2614(2) (2012).




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Appendix IX: Selected State Requirements
              Appendix IX: Selected State Requirements




              All six states we reviewed have state agencies responsible for
              implementing and enforcing environmental and public health
              requirements, which include overseeing oil and gas development (see
              table 11). In five of the six states we reviewed, this responsibility is split
              primarily between two different agencies. In general, one of these
              agencies has primary responsibility for regulating oil and gas
              development activities such as drilling that occur on the well pad and for
              managing and disposing of certain wastes generated on-site, while the
              other agency has a broader mandate for implementing and enforcing
              environmental or public health requirements, some aspects of which may
              affect oil and gas development. For example, the Colorado Oil and Gas
              Conservation Commission regulates activities such as drilling, hydraulic
              fracturing, and disposal of produced water in Class II UIC wells, while the
              Colorado Department of Public Health and Environment regulates
              discharges to surface waters, commercial solid waste facilities, and
              certain air emissions. In contrast, oil and gas development in
              Pennsylvania is primarily governed by one agency—the Pennsylvania
              Department of Environmental Protection.

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

               State                     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);



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                                            Appendix IX: Selected State Requirements




                                            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 ¼ mile of a proposed coalbed methane well, the
            two closest water wells within a ½ 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 ¼ mile, or if access is denied to such wells, then a
            water well within ¼ mile, or, failing that, within ½ 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.




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                                            Appendix IX: Selected State Requirements




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 ¼ 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).




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                                             Appendix IX: Selected State Requirements




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




                                             Page 195                                GAO-12-874 Unconventional Oil and Gas Development
                                                Appendix IX: Selected State Requirements




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



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                                           Appendix IX: Selected State Requirements




        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).




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                                            Appendix IX: Selected State Requirements




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).



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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).




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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
                       g
         whipstocking 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).




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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, field-
                                           specific, or play-specific by permit condition, to ensure protection of public health or safety or the
                                           environment. Ohio Admin. Code Ann. 1501:9-1-08(B) (2012).
                                           d
                                            Surface casing is cemented into bedrock and serves to shut out shallow water formations and as a
                                           foundation for well control during drilling.
                                           e
                                            A casing shoe is a cylinder or ring of hard steel with a cutting edge attached to the bottom of a string
                                           of well casing.
                                           f
                                           American Petroleum Institute, “API RP 10B-2 (R2010) Recommended Practice for Testing Well
                                           Cements.” July 2005.
                                           g
                                            Whipstocking is a long wedge dropped into or placed in a well to deflect the drill to one side of some
                                           obstruction.
                                           h
                                            Pennsylvania requires operators to provide information about the vertical and horizontal paths of
                                           unconventional wells through its permitting process.
                                           i
                                            See also 16 Tex. Admin. Code § 3.86, relating to horizontal drainhole wells.




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                                             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




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                                           Appendix IX: Selected State Requirements




     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
                                                          a
     elements made viewable by the FracFocus website. 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
                                                                                                b
     services, and operators on whose wells hydraulic fracturing treatments are completed. 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




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     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).




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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).




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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



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        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.




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                                             Appendix IX: Selected State Requirements




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).




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                                              Appendix IX: Selected State Requirements




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.




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                                             Appendix IX: Selected State Requirements




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.




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                                              Appendix IX: Selected State Requirements




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.
                                                c
         16 Tex. Admin. Code § 3.8 (2012).
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 ¼ 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).



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                                              Appendix IX: Selected State Requirements




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




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                                              Appendix IX: Selected State Requirements




             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 regulationsf that require facilities to construct appropriate containment or
         diversionary structures or equipment to prevent discharged oil from reaching waters of the United States. Liquids in pits must
         be kept at a level that takes into account extreme precipitation events and prevents overtopping and unpermitted discharges.
         055-000-004 Code Wyo. R. §§ 1, 4 (2012).
Pit closure requirements
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



                                              Page 213                               GAO-12-874 Unconventional Oil and Gas Development
                                           Appendix IX: Selected State Requirements




     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).




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                                         Appendix IX: Selected State Requirements




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.




                                         Page 215                                        GAO-12-874 Unconventional Oil and Gas Development
                                             Appendix IX: Selected State Requirements




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 (¼ mile to ½ 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).




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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.i Surface casing shall
        be installed and cemented from the surface to at least 50 feet below the base of the lowermost protected aquifer, and for
        brine disposal wells, install long string casing and tubing extending to the injection zone and cement to a point 50 feet above
        the injection zone. Design shall consider the depth to injection zone, depth to the bottom of the aquifer, and the estimated
        injection pressures. 40 C.F.R. §§ 146.22,147.1955 (2012).
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).




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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
                                                                                                                                b
        compiled monthly and filed annually. (See also mechanical integrity testing.) Ohio Admin. Code Ann. 1501:9-3-07 (2012).
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
                                                                                        b
        surveys; or other approved test. Ohio Admin. Code Ann. 1501:9-3-07 (2012).
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).




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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).




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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
                                                                    l
        geologic and geophysical data prior to any permit approval.
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.




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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).




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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).




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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



                                              Page 223                                 GAO-12-874 Unconventional Oil and Gas Development
                                           Appendix IX: Selected State Requirements




     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.




                                           Page 224                                     GAO-12-874 Unconventional Oil and Gas Development
Appendix X: Crosswalk between Selected
                                             Appendix X: Crosswalk between Selected
                                             Requirements from EPA, States, and Federal
                                             Lands


Requirements from EPA, States, and Federal
Lands
                                             Table 20 is intended to show representative areas of regulation, focused
                                             on substantive requirements specific to oil and gas wells. The table
                                             includes EPA’s environmental and public health requirements,
                                             requirements from the six states included in our review, and additional
                                             requirements that apply for the development of federally-owned mineral
                                             resources. Other activities at oil and gas well sites may also be subject to
                                             federal or state regulation.

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

                                           EPA environmental and         Requirements of six states       Additional requirements for
Area of regulation                         public health requirements    reviewed                         federal minerals
Siting and site preparation
                                           Noa                           b
Comprehensive environmental                                                                               Yes
assessment prior to drilling
Identification or testing of water wells   No                            1 of 6 (Wyoming)                 Yes – identification
prior to drilling of production wells                                    [identification alone]           No – testing
                                                                         2 of 6 (Colorado, Ohio)
                                                                                                      c
                                                                         [identification and testing]
Required setbacks from water sources       Nod                           5 of 6 (Colorado, North          Yes
                                                                         Dakota, Pennsylvania, Ohio,
                                                                         Wyoming)
Erosion control, site preparation, surface Effectively noe               6 of 6 [any]                     Yes
disturbance minimization, and                                            4 of 6 (Colorado, North
stormwater management                                                    Dakota, Pennsylvania,
                                                                         Wyoming) [stormwater
                                                                         permitting]f
Drilling, casing, and cementing
Requirements relating to                   Nog                           6 of 6h                          Yes
cementing/casing plans
Prescribed placement of surface casing     Nog                           6 of 6                           Yes
relative to groundwater zones
Prescribed cementation techniques for      Nog                           6 of 6                           No; instead the Bureau of
surface casing                                                                                            Land Management (BLM)
                                                                                                          has performance standards
Requirement for cement waiting period      Nog                           6 of 6                           Yes
and/or integrity tests
Blowout preventeri requirements            Nog                           5 of 6j (Colorado, North         Yes
                                                                         Dakota, Pennsylvania,
                                                                         Texas, Wyoming)
Hydraulic fracturing
Prior authorization/notice/inspection      No                            4 of 6 (Colorado, Ohio,          Not currently, but in BLM
requirements                                                             Pennsylvania, Wyoming)           proposed rule
Requirements to disclose information on Nok                              6 of 6                           Not currently, but in BLM
fracturing fluids                                                                                         proposed rule




                                             Page 225                              GAO-12-874 Unconventional Oil and Gas Development
                                              Appendix X: Crosswalk between Selected
                                              Requirements from EPA, States, and Federal
                                              Lands




                                            EPA environmental and            Requirements of six states      Additional requirements for
Area of regulation                          public health requirements       reviewed                        federal minerals
Pressure monitoring, testing, limitations   No                               4 of 6 (Colorado, North         Not currently, but in BLM
or other mechanical integrity                                                Dakota, Ohio, Wyoming)          proposed rule
requirements specific to hydraulic
fracturing
Well plugging
Requirements for notification, plugging     Nol                              6 of 6                          Yes
plan or method, witnessing, and
reporting
Programs to plug wells that are not         No                               6 of 6                          Yesm
properly plugged and have been
abandoned
Site reclamation
Requirements for backfilling, regrading, No                                  6 of 6                          Yes
recontouring, and alleviating compaction
of soil
Revegetation requirements                   No                               5 of 6 (Colorado, North         Yes
                                                                             Dakota, Ohio, Pennsylvania,
                                                                             Wyoming)
Waste management
Options for waste disposal:
   Underground injection                    Yes (Safe Drinking Water         5 states have their own         In the permit application,
                                            Act)                             requirements (Colorado,         operators must describe the
                                                                             North Dakota, Ohio, Texas,      final disposal of waste
                                                                             Wyoming); EPA implements        materials.
                                                                             the program in Pennsylvania
   Direct discharge to surface water        Yes (Clean Water Act—            Surface discharges are          In the permit application,
                                            certain discharges prohibited,   allowed in certain cases in 3   operators must describe the
                                            others subject to conditions     western states (Colorado,       final disposal of waste
                                            and permits)                     Texas, Wyoming)                 materials.
   Requirements for discharge to            Pretreatment standards for       Disposal at POTWs is an         In the permit application,
                                                                                                 n
   publicly-owned treatment works           shale gas wastewater under       option in two states (Ohio,     operators must describe the
   (POTWs) or Centralized Waste             development (Clean Water         Pennsylvania)                   final disposal of waste
   Treatment Facilities (CWT)               Act)                             Disposal at CWT facilities is   materials.
                                                                             an option in 3 states
                                                                             (Colorado, Pennsylvania,
                                                                             Wyoming)
   Recycling or other reuse                 Yes (Clean Water Act—            6 of 6 states allow recycling   In the permit application,
                                            certain produced water           or other reuseo                 operators must describe the
                                            discharges)                                                      final disposal of waste
                                                                                                             materials.
   Solid waste disposal                     Effectively nop                  Yes                             In the permit application,
                                                                                                             operators must describe the
                                                                                                             final disposal of waste
                                                                                                             materials.




                                              Page 226                                GAO-12-874 Unconventional Oil and Gas Development
                                            Appendix X: Crosswalk between Selected
                                            Requirements from EPA, States, and Federal
                                            Lands




                                          EPA environmental and                       Requirements of six states       Additional requirements for
Area of regulation                        public health requirements                  reviewed                         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   Nor                                         6 of 6                           No specific requirements but
sensitive areas)                                                                                                       pits must be approved
Pit lining requirements                   No                                          5 of 6s (Colorado, North         Not currently, but BLM
                                                                                      Dakota, Pennsylvania,            proposed rule would require
                                                                                      Texas, Wyoming)                  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                       5 of 6 states have permitting    No
                                          provisions apply                            or registration programs
                                                                                      (Colorado, North Dakota,
                                                                                      Ohio, Texas, Wyoming)t
Requirements for hazardous air            Certain Clean Air Act                       State permitting or              No
pollutants                                provisions apply                            registration programs may
                                                                                      address hazardous air
                                                                                      pollutants
Requirements related to hydrogen          No specific requirementsu                   6 of 6                           Yes
sulfide gas
Requirements related to flaring           Under new New Source                        6 of 6                           Yes
                                          Performance Standards,
                                          most hydraulically fractured
                                          gas wells must do green
                                          completions
                                            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.




                                            Page 227                                               GAO-12-874 Unconventional Oil and Gas Development
Appendix X: Crosswalk between Selected
Requirements from EPA, States, and Federal
Lands




e
 Oil and gas well sites are only required to get permits for stormwater discharges if the facility has had
a discharge of contaminated stormwater that includes a reportable quantity of a pollutant or
contributes to the violation of a water quality standard, rather than prior to commencing construction
or causing discharges.
f
    Ohio and Texas state regulations address stormwater in other ways.
g
 Generally federal environmental laws do not have drilling, cementing, or casing requirements related
to drilling production wells. However, according to EPA officials, if the well is to be hydraulically
fractured with diesel fuel, it is subject to regulation as a Class II well under the underground injection
control (UIC) program authorized by the Safe Drinking Water Act, and be subject to cementing and
casing requirements. See 40 C.F.R. §§ 144.52 and 146.22. In May 2012, EPA published draft
guidance on how its UIC permit writers should address hydraulic fracturing with diesel in the context
of the Class II UIC program. To date, however, EPA officials are unaware of any wells that were
regulated in this way.
h
 Colorado, North Dakota, Ohio, Pennsylvania, and Wyoming require cementing/casing plans. Texas
requires cementing/casing plans if an operator proposes a method of freshwater protection other than
those prescribed by state regulations.
i
Blowout preventers are devices placed on wells to help maintain control over pressures in the well
and prevent the well from spewing oil, gas, or other formation fluids in the case of a blowout.
j
North Dakota, Texas, and Wyoming require blowout preventers; Colorado and Pennsylvania require
blowout preventers in certain circumstances.
k
 Under TSCA, to the extent a hydraulic fracturing fluid is a chemical substance or mixture,
manufacturers (including importers), processors, and distributors of such fluids generally would be
subject to applicable reporting requirements. Generally, well site operators would not be subject to
any such applicable TSCA reporting requirements.
l
Generally federal environmental laws do not have requirements related to well plugging. However,
according to EPA officials, if the well is to be hydraulically fractured with diesel fuel, it is subject to
regulation as a Class II UIC well under the SDWA UIC program, as discussed in table note g above.
m
    According to BLM officials, BLM periodically conducts orphan and idle well operations.
n
 Disposal at a POTW is currently available in Pennsylvania and Ohio. Discharges may be authorized
from a POTW in Pennsylvania if preceded by treatment at a CWT. The Ohio Environmental
Protection Agency recently prohibited disposal at a POTW in the state, but an administrative review
commission removed the prohibition as beyond the agency’s authority. The Ohio Department of
Natural Resources may take separate action to prohibit the practice. We are also aware that the city
of Forth Worth, Texas had a pilot program within the last several years under which it accepted
flowback for disposal through its POTW, but current information suggests that the city is no longer
accepting flowback water.
o
    For example, four states allow operators to reuse certain types of fluid waste for road applications.
p
 The existing federal regulations under RCRA solid waste provisions apply to nonhazardous waste
disposal facilities and practices, including those involving oil and gas wastes, and prohibit open
dumping of solid waste. However, EPA has a limited role in the enforcement of RCRA solid waste
provisions.
q
 Per EPA’s 1988 regulatory determination, oil and gas exploration and production wastes—including
wastes originating in the well or associated field operations—are not regulated as hazardous. Small
amounts of other hazardous waste may be at well sites (such as discarded, unused hydraulic
fracturing fluids) but we could not identify any instances where these wastes were available in high
enough quantities to trigger RCRA requirements.
r
 Under Section 404 of the Clean Water Act, a permit from the U.S. Army Corps of Engineers is
required to fill waters of the United States, such as wetlands.
s
 Colorado, North Dakota, Pennsylvania, and Wyoming have specific pit lining requirements. Texas
regulations provide for pit lining requirements to be addressed in permits.
t
 In addition, Pennsylvania is in the process of developing an inventory for oil and gas emissions
information.
u
 Although there are no specific requirements, owners and operators are subject to the Clean Air Act
general duty clause to take steps to prevent accidental releases of listed and other substances to the
air; these include hydrogen sulfide.




Page 228                                       GAO-12-874 Unconventional Oil and Gas Development
Appendix XI: Comments from the
             Appendix XI: Comments from the Department
             of Agriculture



Department of Agriculture




             Page 229                           GAO-12-874 Unconventional Oil and Gas Development
Appendix XII: Comments from the
             Appendix XII: Comments from the Department
             of the Interior



Department of the Interior




             Page 230                            GAO-12-874 Unconventional Oil and Gas Development
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
                  Appendix XIII: GAO Contact and Staff
                  Acknowledgments



Acknowledgments

                  David C. Trimble, (202) 512-3841 or trimbled@gao.gov
GAO Contact
                  In addition to the individual named above, Barbara Patterson, Assistant
Staff             Director; Elizabeth Beardsley; David Bieler; Antoinette Capaccio; Cindy
Acknowledgments   Gilbert; Armetha Liles; Alison O’Neill; and Janice Poling made key
                  contributions to this report.




(361347)
                  Page 233                               GAO-12-874 Unconventional Oil and Gas Development
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