Hydraulic Fracturing: Selected Legal Issues

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R43152

Hydraulic Fracturing: Selected Legal Issues

Summary

Hydraulic fracturing is a technique used to recover oil and natural gas from underground low

permeability rock formations, such as shales and other unconventional formations. Its use along

with horizontal drilling has been responsible for an increase in estimated U.S. oil and natural gas

reserves. Hydraulic fracturing and related oil and gas production activities have been

controversial because of their potential effects on public health and the environment. Several

environmental statutes have implications for the regulation of hydraulic fracturing by the federal

government and states.

An amendment to the Safe Drinking Water Act (SDWA) passed as a part of the Energy Policy Act

of 2005 (EPAct 2005) clarified that the Underground Injection Control (UIC) requirements found

in the SDWA do not apply to hydraulic fracturing, although the exclusion does not extend to the

use of diesel fuel in hydraulic fracturing operations. The underground injection of wastewater

generated during oil and gas production (including hydraulic fracturing) does require a UIC

permit under the SDWA, as do injections for enhanced oil and gas recovery operations. Under the

Clean Water Act (CWA), parties seeking to discharge produced water may have to apply for a

permit under the National Pollutant Discharge Elimination System. Under the Clean Air Act

(CAA), the Environmental Protection Agency (EPA) has issued new rules covering emissions of

volatile organic compounds from hydraulic fracturing operations.

Provisions of the Resource Conservation and Recovery Act (RCRA) exempt drilling fluids,

produced waters, and other wastes associated with the exploration, development, or production of

crude oil, natural gas, or geothermal energy from regulation as hazardous wastes under Subtitle C

of RCRA. However, these wastes are subject to other federal laws (such as the SDWA and the

CWA), as well as to state requirements. Facility owners and operators and other potentially

responsible parties could potentially face liability under the Comprehensive Environmental

Response, Compensation, and Liability Act (CERCLA) for cleanup costs, natural resource

damages, and the costs of federal public health studies, if hydraulic fracturing results in the

release of hazardous substances at or under the surface in a manner that may endanger public

health or the environment.

The National Environmental Policy Act (NEPA) requires federal agencies to consider the

environmental impacts of proposed federal actions before proceeding with them. An agency

would be obligated to consider the impacts of an action that involves hydraulic fracturing if that

action takes place on federal lands or when there is otherwise a sufficient federal nexus to

hydraulic fracturing.

Under the Emergency Planning and Community Right-to-Know Act (EPCRA), owners or

operators of facilities where certain hazardous hydraulic fracturing chemicals are present above

certain thresholds may have to comply with emergency planning requirements; emergency release

notification obligations; and hazardous chemical storage reporting requirements. In August 2011,

environmental groups petitioned EPA to promulgate rules under the Toxic Substances Control Act

(TSCA) for chemical substances and mixtures used in oil and gas exploration or production.

While the federal government’s oversight of hydraulic fracturing generally is limited to protection

of the environment and public health pursuant to the aforementioned statutes, it does have some

authority to regulate oil and natural gas exploration and production on federal lands. Whether this

authority extends to particular regulations governing hydraulic fracturing is currently in dispute.

The Bureau of Land Management published a rule on hydraulic fracturing on federal and Indian

lands in March 2015; however, the rule was struck down by a U.S. District Court in June 2016.

The matter is currently on appeal.

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Hydraulic Fracturing: Selected Legal Issues

At the state level, hydraulic fracturing tort litigation has raised questions about causation; whether

hydraulic fracturing is an abnormally dangerous activity; and whether hydraulic fracturing may

constitute a subsurface trespass to land. Also, several municipalities have attempted to ban

hydraulic fracturing through zoning restrictions and other local laws, creating potential conflicts

with oil and gas industry regulation at the state level.

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Contents

Introduction ..................................................................................................................................... 1

The Safe Drinking Water Act and the Federal Role in Regulation of Underground

Injection........................................................................................................................................ 1

Review of Relevant SDWA UIC Provisions ............................................................................. 1

The Debate over Regulation of Hydraulic Fracturing Under the SDWA ........................................ 3

The LEAF Challenge to the Alabama UIC Program and EPA’s Interpretation of the

SDWA .................................................................................................................................... 3

Energy Policy Act of 2005: A Legislative Exemption for Hydraulic Fracturing............................. 5

EPA Guidance for Permitting Hydraulic Fracturing Using Diesel Fuels .................................. 6

Clean Water Act ............................................................................................................................... 7

Clean Air Act ................................................................................................................................... 8

Resource Conservation and Recovery Act .................................................................................... 10

The Bentsen Amendment and EPA’s 1988 Regulatory Determination ................................... 10

Natural Resources Defense Council Petition to Regulate E&P Wastes Under Subtitle

C ........................................................................................................................................... 12

Comprehensive Environmental Response, Compensation, and Liability Act ............................... 12

Petroleum and Natural Gas Exclusion .................................................................................... 13

Exemption for Federally Permitted Releases .......................................................................... 14

Examples of Application of CERCLA Response Authority .................................................... 14

National Environmental Policy Act ............................................................................................... 15

Drilling in the Monterey Shale: Federal Oil and Gas Leases .................................................. 16

Delaware River Basin Commission: Proposed Regulations on Natural Gas

Development ........................................................................................................................ 17

The Debate over Public Disclosure of the Chemical Composition of Hydraulic Fracturing

Fluids .......................................................................................................................................... 19

Toxic Substances Control Act ....................................................................................................... 20

Occupational Safety and Health Act.............................................................................................. 22

Emergency Planning and Community Right-to-Know Act ........................................................... 23

Emergency Release Notification and Hazardous Chemical Storage Reporting

Requirements ....................................................................................................................... 23

Earthworks Petitioners’ Request for the Oil and Gas Extraction Industry to Report

Under the Toxics Release Inventory .................................................................................... 25

State Preemption of Municipal Land Use and Zoning Powers ..................................................... 26

State Court Cases .................................................................................................................... 27

Alternatives to Preemption ...................................................................................................... 29

State Tort Law ............................................................................................................................... 29

Hydraulic Fracturing on Federal Lands ......................................................................................... 31

BLM Final Rule ...................................................................................................................... 31

Final Rule Set Aside in Wyoming v U.S. Dep’t of the Interior ................................................ 32

BLM Venting and Flaring Rule ............................................................................................... 33

Legislation in the 114th Congress .................................................................................................. 33

Conclusion ..................................................................................................................................... 34

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Contacts

Author Contact Information .......................................................................................................... 35

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Introduction

Hydraulic fracturing is a technique used to recover oil and natural gas from underground low

permeability rock formations.1 Hydraulic fracturing involves pumping fluids (primarily water and

a small portion of chemicals, along with sand or other proppant) under high pressure into rock

formations to crack them and allow the resources inside to flow to a production well.2 The

technique has been the subject of controversy because of the potential effects that hydraulic

fracturing and related oil and gas production activities may have on the environment and health.3

This report focuses on selected legal issues related to the use of hydraulic fracturing. It examines

some of the requirements for hydraulic fracturing contained in major federal environmental laws.4

It also provides an overview of issues involving state preemption of local zoning authority, as

well as state tort law.

The Safe Drinking Water Act and the Federal Role

in Regulation of Underground Injection

Review of Relevant SDWA UIC Provisions5

The Safe Drinking Water Act (SDWA), among other things, directs EPA to regulate the

underground injection of fluids (including solids, liquids, and gases) to protect underground

sources of drinking water.6 Part C of the SDWA establishes the national regulatory program for

the protection of underground sources of drinking water, including the oversight and limitation of

underground injections that could affect aquifers, through the establishment of underground

injection control regulations. Section 1421 of the SDWA directs the EPA Administrator to

promulgate regulations for state underground injection control (UIC) programs, and mandates

that the EPA regulations “contain minimum requirements for programs to prevent underground

injection that endangers drinking water sources.” Section 1421(b)(2) specifies that EPA

National Energy Technology Laboratory, Modern Shale Gas Development in the United States: An Update, U.S.

Department of Energy, September 2013, http://www.netl.doe.gov/research/oil-and-gas/natural-gas-resources.

Id. Hydraulic fracturing often is referred to as “fracing” within the industry and as “fracking” by others.

For a review of the literature on potential environmental impacts associated with unconventional oil and gas

production and hydraulic fracturing and related state and federal measures, see National Energy Technology

Laboratory, Environmental Impacts of Unconventional Natural Gas Development and Production, U.S. Department of

Energy, DOE/NETL-2-14/1651, May 29, 2014, http://www.netl.doe.gov/research/oil-and-gas/publications.

This report does not provide an overview of additional requirements that may apply on federal lands. The report also

does not address in detail tribal, state, or local requirements pertaining to the use of hydraulic fracturing. For an

overview of selected state and federal regulatory actions, including the Bureau of Land Management (BLM) proposed

hydraulic fracturing rule, see CRS Report R43148, An Overview of Unconventional Oil and Natural Gas: Resources

and Federal Actions, by (name redacted) and (name redacted)

This brief review of relevant sections of Part C of the SDWA is intended to provide the necessary background for

discussion of legal issues associated with regulation of hydraulic fracturing under the act. For further discussion of the

SDWA generally, see CRS Report RL31243, Safe Drinking Water Act (SDWA): A Summary of the Act and Its Major

Requirements, by (name redacted).For a more detailed review of Part C of the SDWA, UIC program, and its application

to hydraulic fracturing and related activities, see CRS Report R41760, Hydraulic Fracturing and Safe Drinking Water

Act Regulatory Issues, by (name redacted) and (name redacted)

42 U.S.C. §§300h-300h-5.

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may not prescribe requirements for state UIC programs 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, unless

such requirements are essential to assure that underground sources of drinking water

will not be endangered by such injection.7

As noted, Section 1421 of the SDWA states that UIC regulations must “contain minimum

requirements for effective programs to prevent underground injection which endangers drinking

water sources.”8 Known as the “endangerment standard,” this statutory standard is a major

driving force in EPA regulation of underground injection. This endangerment language focuses on

protecting groundwater that is used or may be used to supply public water systems. This focus

parallels the general scope of the statute, which addresses the quality of water provided by public

water systems and does not address private, residential wells. The endangerment language has

raised questions as to whether EPA regulations can reach underground injection activities to

protect groundwater that is not used by public water systems.

The SDWA directs EPA to protect against endangerment of an “underground source of drinking

water” (USDW). The regulations define a USDW to mean an aquifer or part of an aquifer that

either:



supplies a public water system; or

contains a sufficient quantity of groundwater to supply a public water system;

and

currently supplies drinking water for human consumption; or

contains fewer than 10,000 milligrams per liter (mg/L) total dissolved solids; and

is not an “exempted aquifer.”9

To implement the UIC program as mandated by the provisions of the SDWA described above,

EPA has established six classes of underground injection wells based on categories of materials

that are injected into the ground by each class. In addition to the similarity of fluids injected in

each class of wells, each class shares similar construction, injection depth, design, and operating

techniques. The wells within a class are required to meet a set of appropriate performance criteria

for protecting underground sources of drinking water. Class II wells feature the injection of brines

and other fluids associated with oil and gas production, and hydrocarbons for storage. The wells

inject fluids beneath the lowermost USDW. If hydraulic fracturing were to be regulated under the

SDWA, it is likely that most hydraulic fracturing operations would be characterized as Class II

wells.

Under the SDWA, states may take on primary responsibility for administration and enforcement.

Section 1422 of the SDWA authorizes EPA to delegate primary enforcement authority for UIC

programs to the states, provided that the state program meets EPA requirements promulgated

42 U.S.C. §300h(b)(2) (emphasis added).

42 U.S.C. §300h(b)(1).

40 C.F.R. §144.3. According to EPA regulations, an exempted aquifer is an aquifer, or a portion of an aquifer, that

meets the criteria for a USDW, for which protection has been waived under the UIC program. Under 40 C.F.R. Part

146.4, an aquifer may be exempted if it is not currently being used—and will not be used in the future—as a drinking

water source, or it is not reasonably expected to supply a public water system due to a high total dissolved solids

content. The SDWA does not mention aquifer exemption, but EPA explains that without aquifer exemptions, certain

types of energy production, mining, or waste disposal into USDWs would be prohibited. EPA, typically at the Region

level, makes the final determination on granting all exemptions.

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under Section 1421 and prohibits any underground injection that is not authorized by a state

permit or rule.10 If a state’s UIC program plan is not approved, or the state has chosen not to

assume program responsibility, then EPA must implement the UIC program in that state.

Alternatively, Section 1425 authorizes EPA to approve the portion of a state’s UIC program that

relates to “any underground injection for the secondary or tertiary recovery of oil or natural gas”

if the state program meets certain requirements of Section 1421 and represents an effective

program to prevent underground injection which endangers drinking water sources.11 Under this

provision, states may demonstrate to EPA that their existing programs for oil and gas injection

wells are effective in preventing endangerment of underground sources of drinking water. This

provides states with an alternative to meeting the specific requirements contained in EPA

regulations promulgated under Section 1421.

The Debate over Regulation of Hydraulic Fracturing

Under the SDWA

From the date of the SDWA’s enactment in 1974 until the late 1990s, hydraulic fracturing was not

regulated under the act by either EPA or any of the states who had chosen to take on

responsibility for administration of the SDWA. However, in the last 15 years a number of

developments called into question the extent to which hydraulic fracturing would be considered

an “underground injection” to be regulated under the SDWA. One trigger for this debate was a

challenge to the Alabama UIC program brought by the Legal Environmental Assistance

Foundation (LEAF).

The LEAF Challenge to the Alabama UIC Program

and EPA’s Interpretation of the SDWA

In 1994, LEAF petitioned EPA to initiate proceedings to have the agency withdraw its approval of

the Alabama UIC program because the program did not regulate hydraulic fracturing operations

in the state associated with production of methane gas from coalbed formations.12 The State of

Alabama had previously been authorized by EPA to administer a UIC program pursuant to the

terms of the SDWA.13 EPA denied the LEAF petition in 1995 based on a finding that hydraulic

fracturing did not fall within the definition of “underground injection” as the term was used in the

SDWA and the EPA regulations promulgated under that act.14 According to EPA, that term

applied only to wells whose “principal function” was the placement of fluids underground.15

LEAF challenged EPA’s denial of its petition in the U.S. Court of Appeals for the Eleventh

Circuit, arguing that EPA’s interpretation of the terms in question was inconsistent with the

language of the SDWA.16

42 U.S.C. §300h-1. The minimum requirements for a state UIC program can be found at 40 C.F.R. Part 145.

42 U.S.C. §300h-4.

Legal Environmental Assistance Foundation, Inc. v. U.S. Environmental Protection Agency, 118 F.3d 1467, 1471

(11th Cir. 1997) (“LEAF I”).

Id. at 1470.

Id. at 1471.

Id.

Id. at 1472.

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The court rejected EPA’s claim that the language of the SDWA allowed it to regulate only those

wells whose “principal function” was the injection of fluids into the ground. EPA based this claim

on what it perceived as “ambiguity” in the SDWA regarding the definition of “underground

injection” as well as a perceived congressional intent to exclude wells with primarily noninjection functions.17 The court held that there was no ambiguity in the SDWA’s definition of

“underground injection” as “the subsurface emplacement of fluids by well injection,” noting that

the words have a clear meaning and that:

The process of hydraulic fracturing obviously falls within this definition, as it involves

the subsurface emplacement of fluids by forcing them into cracks in the ground through a

well. Nothing in the statutory definition suggests that EPA has the authority to exclude

from the reach of the regulations an activity (i.e. hydraulic fracturing) which

unquestionably falls within the plain meaning of the definition, on the basis that the well

that is used to achieve that activity is also used—even primarily used—for another

activity (i.e. methane gas production) that does not constitute underground injection. 18

The court therefore remanded the decision to EPA for reconsideration of LEAF’s petition for

withdrawal of Alabama’s UIC program approval.19

Following the LEAF I decision, in 1999 Alabama submitted a revised UIC program to EPA.20

Alabama sought approval for the revised UIC program under Section 1425 of the SDWA rather

than Section 1422(b). As mentioned above, Section 1425 differs from Section 1422(b) in that

approval under Section 1425 is based on a showing by the state that the program meets the

generic requirements found in Section 1421(b)(1)(A)-(D) of the SDWA and that the program

“represents an effective program (including adequate recordkeeping and reporting) to prevent

underground injection which endangers drinking water sources.” In contrast, approval of a state

program under Section 1422(b) requires a showing that the state’s program satisfies the

requirements of the UIC regulations promulgated by EPA.21

EPA approved Alabama’s revised UIC program in 2000,22 and LEAF appealed EPA’s decision to

approve to the U.S. Court of Appeals for the Eleventh Circuit.23 In its challenge, LEAF made

three arguments. First, LEAF claimed that EPA should not have approved state regulation of

hydraulic fracturing under Section 1425 of the SDWA because it does not “relate to ...

underground injection for the secondary or tertiary recovery of oil or natural gas,” one of the

requirements for approval under Section 1425.24 The court rejected this argument, finding that the

phrase “relates to” was broad and ambiguous enough to include regulation of hydraulic fracturing

as being related to secondary or tertiary recovery of oil or natural gas.25

Second, LEAF challenged the Alabama program’s regulation of hydraulic fracturing as “Class IIlike” wells not subject to the same regulatory requirements as Class II wells.26 The court agreed

Id. at 1473-74.

Id. at 1474-75.

Id. at 1478.

See 64 Fed. Reg. 56986 (Oct. 22, 1999).

42 U.S.C. at §300h-1(b)(1)(A).

65 Fed. Reg. 2889 (Jan 19, 2000).

Legal Environmental Assistance Foundation, Inc. v. U.S. Environmental Protection Agency, 276 F.3d 1253, 1257

(11th Cir. 2001).

Id. at 1256.

Id. at 1259-61.

Id. at 1256.

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with LEAF on this point, noting that in its decision in LEAF I, it had held that methane gas

production wells used for hydraulic fracturing are “wells” within the meaning of the statute.27 As

a result, the court found that wells used for hydraulic fracturing must fall under one of the five

classes set forth in the EPA regulations at 40 C.F.R. Section 144.6.28 Specifically, the court found

that the injection of hydraulic fracturing fluids for recovery of coalbed methane “fit squarely

within the definition of Class II wells,” and as a result the court remanded the matter to EPA for a

determination of whether Alabama’s updated UIC program complied with the requirements for

Class II wells.29

Finally, LEAF alleged that even if Alabama’s revised UIC program was eligible for approval

under Section 1425 of the SDWA, EPA’s decision to approve it was “arbitrary and capricious”

and therefore a violation of the Administrative Procedure Act.30 The court rejected this

argument.31

Energy Policy Act of 2005: A Legislative Exemption

for Hydraulic Fracturing

The decision by the U.S. Court of Appeals for the Eleventh Circuit in LEAF I highlighted a

debate over whether the SDWA, as it read at the time, required EPA to regulate hydraulic

fracturing. Although the Eleventh Circuit’s decision applied only to hydraulic fracturing for

coalbed methane production in Alabama, the court’s reasoning—in particular, its finding that

hydraulic fracturing “unquestionably falls within the plain meaning of the definition [of

underground injection]”32—raised the issue of whether EPA could be required to regulate

hydraulic fracturing generally under the SDWA.

Before this question was resolved through agency action or litigation, Congress passed an

amendment to the SDWA as a part of the Energy Policy Act of 2005 (EPAct 2005; P.L. 109-58)

that addressed this issue. Section 322 of EPAct 2005 amended the definition of “underground

injection” in the SDWA as follows:

The term “underground injection”—(A) means the subsurface emplacement of fluids by

well injection; and (B) excludes—(i) the underground injection of natural gas for

purposes of storage; and (ii) the underground injection of fluids or propping agents (other

than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or

geothermal production activities.

This amendment clarified that the UIC requirements found in the SDWA do not apply to

hydraulic fracturing, although the exclusion does not extend to the use of diesel fuel in hydraulic

fracturing operations. This amended language is the definition of “underground injection” found

in the SDWA as of the date of this report.33

Id. at 1262.

Id. at 1263.

Id. at 1263-64.

Id. at 1256 (referring to 5 U.S.C. §706(2)(A)).

Id. at 1265.

LEAF I, 118 F.3d at 1475.

42 U.S.C. §300h.

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EPA Guidance for Permitting Hydraulic Fracturing Using

Diesel Fuels

As noted above, the 2005 amendment to the definition of “underground injection” in the SDWA

excluded injections as part of hydraulic fracturing operations, but such injections involving the

use of diesel fuels were not made part of the exclusion, meaning that injections for purposes of

hydraulic fracturing involving the use of diesel fuel might still be made subject to regulation

under the SDWA. It was not clear to states or the regulated community how EPA would address

the EPAct 2005 amendment, and for several years EPA took no official position regarding the

regulation of hydraulic fracturing using diesel fuel under the SDWA.34

In February 2014, EPA issued final diesel permitting guidance, which states that “under the 2005

amendments to the SDWA, a UIC Class II permit must be obtained prior to conducting the

underground injection of diesel fuels for hydraulic fracturing.”35 As described earlier in this

report, injections subject to UIC Class II requirements must comply with a number of regulatory

requirements. These include permitting requirements, and testing and monitoring obligations with

respect to the well.36 The guidance is intended for EPA permit writers and is relevant where EPA

directly implements the UIC Class II program. EPA notes that “[t]o the extent that states may

choose to follow some aspects of EPA guidance in implementing their own programs, it may also

be relevant in areas where EPA is not the permitting authority.”37

There had been considerable debate regarding how EPA would define “diesel fuels” in the final

guidance. The draft guidance recommends using six Chemical Abstracts Service Registry

Numbers (CASRNs) for determining whether diesel fuels are used in hydraulic fracturing

operations.38 These six CASRNs collectively include various types of diesel fuels, home heating

oils, kerosene, crude oil, and a range of other petroleum compounds.39 Also at issue was whether

the final guidance would specify a de minimis amount of diesel fuel content for hydraulic

fracturing fluids; the draft guidance did not do so. The final document covers five of the six

proposed CASRNs (no longer including crude oil), and does not establish a de minimis

concentration of “diesel” in fracturing fluid that would be exempt from permitting requirements.

In January 2011, an investigation led by Representatives Waxman, Markey and DeGette of the House Committee on

Energy and Commerce found that “oil and gas service companies have injected over 32 million gallons of diesel fuel or

hydraulic fracturing fluids containing diesel fuel in wells in 19 states between 2005 and 2009.”

http://democrats.energycommerce.house.gov/index.php?q=news/waxman-markey-and-degette-investigation-findscontinued-use-of-diesel-in-hydraulic-fracturing-f/.

U.S. Environmental Protection Agency, Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using

Diesel Fuels: Underground Injection Control Program Guidance #84, EPA 816-R-14-001, February 2014, p. 1,

http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/hydraulic-fracturing.cfm.

40 C.F.R. §124 and §§144-147.

“Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft,” 77 Fed. Reg.

27,541 (May 10, 2012).

EPA explains that “diesel fuels may be used in hydraulic fracturing operations as a primary base (or carrier) fluid, or

added to hydraulic fracturing fluids as a component of a chemical additive to adjust fluid properties (e.g., viscosity and

lubricity) or act as a solvent to aid in the delivery of gelling agents. Some chemicals of concern often occur in diesel

fuels as impurities or additives. Benzene, toluene, ethylbenzene, and xylene compounds (BTEX) are highly mobile in

ground water and are regulated under national primary drinking water regulations because of the risks they pose to

human health.” Source: FACT SHEET: Underground Injection Control (UIC) Program Permitting Guidance for Oil

and Gas Hydraulic Fracturing Activities Using Diesel Fuels, UIC Program Guidance #84—Draft, EPA 816-K-12-001.

77 Fed. Reg.27,453 (May 10, 2012). EPA explains that these CASRNs were selected “because either their primary

name, or their common synonyms contained the term “diesel fuel” and they meet the chemical and physical properties

of “diesel fuel” as provided in the Toxic Substances Control Act (TSCA) Inventory.

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Clean Water Act

Hydraulic fracturing is a water-intensive practice. After a well is hydraulically fractured, a

substantial portion of the injected fluid returns to the surface as “flowback.” This flowback

typically contains proppant (sand) and chemical residues from the frac fluid, as well as salts,

metals, and potentially significant amounts of naturally occurring radioactive materials (NORM)

that may be present in the water produced from the geologic formations.40 Additionally, oil and

gas wells generally continue to produce formation water throughout their production lives.

Flowback water and production brine that are not reused will require proper disposal, either

through underground injection or treatment and surface discharge.

Often this flowback is injected into wells for disposal. However, if underground injection is not

feasible or not employed for other reasons, drilling companies may opt to transfer the wastewater

to publicly owned treatment works (POTW) that discharge into navigable waters in compliance

with the Clean Water Act (CWA).41 Section 301(a) of the CWA prohibits “the discharge of any

pollutant” into “navigable waters” except as permitted pursuant to other sections of the CWA.42

Under Section 304(m), EPA sets national standards for discharges of industrial wastewater based

on best available technologies that are economically achievable. States incorporate these limits

into discharge permits. Current effluent limitation guidelines (ELGs) and standards for the Oil

and Gas Extraction Point Source Category prohibit direct discharges of onshore oil and gas

wastewater into surface waters. However, current ELGs do not include standards for “indirect

discharges” of these wastewaters to POTWs.

On June 28, 2016, EPA promulgated final regulations establishing a “zero discharge”

pretreatment standard to prohibit discharges to POTWs of wastewater resulting from

unconventional oil and gas production.43 In the proposed regulations, EPA had noted that, while

states are not approving requests for such discharges to POTWs, the proposed zero discharge

standard would “provide regulatory certainty and would eliminate the burden on POTWs to

analyze such requests.”44

See, for example, E.L. Rowan, M.A. Kirby, and C.S. Kirby et al., Radium Content of Oil- and Gas-Field Produced

Waters in the Northern Appalachian Basin—Summary and Discussion of Data, U.S Geological Survey, USGS

Scientific Investigations Report 2011-5135, 2011, 31 p., available at http://energy.usgs.gov/HealthEnvironment/

EnergyProductionUse/ProducedWaters.aspx.

33 U.S.C. §§1251 et seq.

33 U.S.C. §1311(a).

Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category, Final Rule, 81

Federal Register 41,845 (June 28, 2016). For purposes of this rule, the term “unconventional oil and gas” refers to oil

and gas produced from low permeability formations (e.g., shale gas and tight oil). The rule does not apply to the

coalbed methane extraction industry. Because of the salinity of oil and gas production wastewater, discharge to POTWs

generally is not available, as most municipal POTWs are not designed and engineered to handle the high levels of total

dissolved solids (TDS), fracturing fluid additives, metals, and naturally occurring radioactive materials (NORMs) in the

wastewater. To minimize the need for wastewater disposal, many companies are employing on-site treatment

technologies to reuse or recycle a portion of the flowback and produced water.

EPA also had been considering regulatory options to control direct discharges of coalbed methane (CBM) wastewaters.

On August 7, 2013, EPA proposed to delist CBM from the ELG rulemaking plan, having determined that no

economically achievable technology was currently available. Preliminary 2012 Effluent Guidelines Program Plan and

2011 Annual Effluent Guidelines Review Report, 78 Federal Register 48159.

Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category, Proposed

Rule, 80 Fed. Reg. 18,561 (April 7, 2015).

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Clean Air Act

As this report has explained, the definition of “underground injection” found in the SDWA

prevents regulation of hydraulic fracturing pursuant to that statute unless the fracking fluid

contains diesel fuel. However, other federal environmental statutes do not contain similar

reservations of jurisdiction, and EPA has sought to regulate certain environmental impacts of

hydraulic fracturing pursuant to these statutes. One such avenue is regulation of emissions

associated with the hydraulic fracturing process via the Clean Air Act (CAA). On August 16,

2012, EPA issued new regulations covering, among other things, emissions of volatile organic

compounds (VOCs) from onshore natural gas hydraulic fracturing operations.

The impetus for the new regulations was a legal challenge filed by environmental organizations.

In 2009, WildEarth Guardians and the San Juan Citizens Alliance filed a petition in the U.S.

District Court for the District of Columbia alleging that EPA had failed to review and revise its

New Source Performance Standards (NSPSs) for oil and gas operations every eight years as

required by Section 111(b)(1)(B) of the CAA.45 Specifically, the environmental groups alleged

that EPA had failed to update existing standards and adopt new standards for emissions from oil

and natural gas production as well as natural gas transmission and storage.

The challenge and subsequent settlement triggered a new rulemaking by EPA in which it not only

updated existing standards for certain natural gas processing plants, but also established new

standards for emissions from certain types of natural gas operations not covered at all in the

existing standards.46 Among the new standards were requirements applicable to new onshore

natural gas hydraulic fracturing operations as well as refracturing operations.

The new regulations direct the industry to adopt a process known as “green completions” or

“reduced emissions completions” for hydraulically fractured gas wells. (Hydraulically fractured

oil wells are exempt from the 2012 NSPS requirements.) In a “green completion,” the natural gas

that would otherwise be vented or flared during the completion process is captured and cleaned

for reuse in another process that does not involve direct release into the atmosphere. In order to

allow the industry time to make the needed changes, the rulemaking established two phases for

compliance. During Phase 1, which lasted from the effective date of the rulemaking (October 15,

2012) until January 1, 2015, industry had to reduce VOC emissions at new hydraulic fracturing

sites either by using a “completion combustion device” in a technique commonly referred to as

“flaring,”47 or by employing the green completion process.48 As of January 1, 2015, all

hydraulically fractured wells had to employ a green completion.49 These requirements apply both

to new hydraulic fracturing operations and to refracturing of existing wells.50 The regulations also

establish reporting requirements for owners and operators of hydraulically fractured and

refractured wells prior to the start of well completion.51

42 U.S.C. §7411(b)(1)(B).

Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air

Pollutants Reviews, 77 Fed. Reg. 49,490 (Aug. 16, 2012).

This process burns off the gas that would otherwise escape during the well completion process.

77 Federal Register at 49,499.

Id.

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There are some exceptions in these regulations for certain types of wells. Exploratory or

“wildcat” drilling operations and “delineation wells” used to determine the borders of a reservoir,

and low-pressure wells do not need to employ green completions.52 The 2012 NSPS requires

operators of these types of wells to use completion combustion devices unless hazardous or

prohibited under state or local law or regulations.53

On June 3, 2016, EPA promulgated several CAA rules affecting the oil and natural gas production

industry, including amendments to the NSPS standards for the oil and natural gas source category

to establish new emissions standards for methane (a short-lived greenhouse gas) and VOCs.54

Briefly, the rules do the following:55

1. Build on the 2012 NSPS “to set first-ever controls for methane emissions and

extend controls for VOC emissions beyond the existing requirements to include

new or modified hydraulically fractured oil wells, pneumatic pumps, compressor

stations, and leak detection and repair at well sites, gathering and boosting

stations, and processing plants.” The final rule also includes the issuance for

public comment of an Information Collection Request (ICR) that would require

companies to provide extensive information that is instrumental for developing

comprehensive regulations to reduce methane emissions from existing oil and gas

sources.56 EPA notes the new NSPS does not add requirements for operations

covered by the 2012 rule but it expands coverage to include other sources.57

2. Revise permitting requirements applicable to stationary sources in the oil and

natural gas sector.58 The rule establishes in regulation a specific meaning of the

term “adjacent” for this sector, which was previously defined in guidance

documents.

3. Limit emissions from oil and gas production in Indian country.59

Further, EPA has issued rules or guidelines to strengthen the Greenhouse Gas Reporting Program

to require reporting in all segments of the industry (promulgated on October 22, 2015)60 and

extend VOC reduction requirements to existing oil and gas sources in ozone nonattainment areas

and states in the Ozone Transport Region (released on August 18, 2015).61

Id.

EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Final Rule,”

81 Fed. Reg. 35,824 (June 3, 2016).

See CRS Report R42986, An Overview of Air Quality Issues in Natural Gas Systems, by (name redacted)

EPA, “Proposed Information Collection Request; Comment Request; Information Collection Effort for Oil and Gas

Facilities,” 81 Fed. Reg. 35,763 (June 3, 2016).

Id.

EPA, “Source Determination for Certain Emission Units in the Oil and Natural Gas Sector; Final Rule,” 81 Fed. Reg.

35622 (June 3, 2016).

EPA, “Federal Implementation Plan for True Minor Sources in Indian Country in the Oil and Natural Gas Production

and Natural Gas Processing Segments of the Oil and Natural Gas Sector; Amendments to the Federal Minor New

Source Review Program in Indian Country to Address Requirements for True Minor Sources in the Oil and Natural Gas

Sector; Final Rule,” 81 Fed. Reg. 35,944 (June 3, 2016).

EPA, “Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and

Natural Gas Systems; Final Rule,” 80 Fed. Reg. 64,262 (October 22, 2015).

EPA, “Control Techniques Guidelines for the Oil and Natural Gas Industry (Draft),” EPA-453/P-15-001, August

2015, http://www.epa.gov/airquality/oilandgas/pdfs/og_ctg_draft_081815.pdf.

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Resource Conservation and Recovery Act62

Federal and state authorities to regulate wastes are established under the Solid Waste Disposal Act

of 1965, as amended by the Resource Conservation and Recovery Act of 1976 (RCRA).63 Subtitle

C of RCRA established a framework for EPA, or authorized states, to regulate waste identified as

“hazardous.”64 Specifically, EPA was required to develop criteria necessary to identify hazardous

wastes and to promulgate regulations applicable to hazardous waste generators and transporters

and to facilities that treat, store, and dispose of such wastes.65 EPA has primary authority to

implement the federal hazardous waste program,66 but was required to develop procedures for

states to become authorized to implement that program.67 Most states have chosen to do so.68

Under RCRA Subtitle D, state and local governments were established as the primary planning,

regulating, and implementing entities responsible for managing non-hazardous solid waste,

including waste explicitly exempt from regulation under Subtitle C. EPA’s primary role under

Subtitle D is to provide state and local agencies with information, guidance, and policy.69

The Bentsen Amendment and EPA’s

1988 Regulatory Determination

The Solid Waste Disposal Act Amendments of 1980 (P.L. 96-482) included amendments to

Subtitle C requirements regarding the identification of hazardous waste.70 Provisions commonly

referred to as the “Bentsen” amendment temporarily excluded “drilling fluids, produced waters,

and other wastes associated with the exploration, development, or production of crude oil, natural

gas, or geothermal energy” (E&P wastes) from regulation as hazardous wastes under Subtitle C of

RCRA.71 The exemption was motivated in part by a concern about the economic impact that

comprehensive regulation of E&P wastes under Subtitle C would have on the oil and gas

industry.72 The Bentsen amendment required EPA to conduct a study of E&P waste and submit its

findings to Congress.73 If EPA determined that E&P wastes warranted regulation under Subtitle C,

the agency was required to submit proposed regulations to both houses of Congress. Those

regulations could “take effect only when authorized by Act of Congress.”74

(name redacted), Analyst in Environmental Policy, Resources, Science, and Industry Division, contributed to the

preparation of this section of the report.

The 1976 amendments to the Solid Waste Disposal Act were so comprehensive that the law is more commonly

referred to as RCRA.

42 U.S.C. §§6921-29; H.Rept. 94-1491 (1976), at 5-7.

42 U.S.C. §§6921-25.

42 U.S.C. §§6927-28.

42 U.S.C. §§6926, 6929.

See EPA’s “RCRA State Authorization” web page at http://www.epa.gov/osw/laws-regs/state/index.htm.

42 U.S.C. §§6907 and 6941.

42 U.S.C. §6921.

Solid Waste Disposal Act Amendments of 1980, P.L. 96-482, §7, 42 U.S.C. §6921(b)(2)(A).

S.Rept. 96-172, at 6 (1979).

The study criteria are specified at 42 U.S.C. §6982(m).

42 U.S.C. §6921(b)(2)(C).

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In its 1987 report to Congress,75 EPA found, in part, that existing state and federal regulations

were generally adequate to regulate E&P wastes, although there were regulatory gaps in certain

states. EPA further found that regulating E&P wastes under RCRA Subtitle C would have a

substantial impact on the U.S. economy and would be unnecessary and impracticable. In its 1988

regulatory determination,76 EPA determined that the management of E&P wastes under Subtitle C

was not warranted, but that the agency would pursue the following three-pronged approach to

addressing adverse effects of the waste: improve existing federal regulatory programs under

RCRA Subtitle D and augment the Safe Drinking Water Act and/or Clean Water Act

requirements; work with states to improve their waste management programs; and work with

Congress on any additional legislation that might be needed.77

In the 25 years since EPA made its regulatory determination, the agency has chosen not to

develop regulations under RCRA Subtitle D or pursue additional RCRA legislation. However,

EPA has previously sought to clarify the Subtitle C exemption.78 In 2002, EPA issued guidance

regarding the scope of the exemption, including examples of exempt and non-exempt E&P

wastes.79 EPA listed produced water and drilling fluids as exempt wastes; and unused fracturing

fluids or acids as non-exempt waste.80 That is, unused fracturing fluids may be subject to Subtitle

C requirements if the fluid exhibits characteristics that make a waste “hazardous” (e.g., exceed

regulatory levels for toxicity).81

Depending on the chemicals in the drilling fluid and the geologic formations in which it is

injected, produced hydraulic fracturing fluids may contain hazardous constituents (e.g., heavy

metals).82 Regardless of whether those fluids exhibit the regulatory characteristics of hazardous

waste (e.g., exceed regulatory levels of toxicity), such fluids are exempt from federal Subtitle C

regulation. E&P waste disposal is, however, subject to state waste management requirements, as

well as requirements applicable to the disposal of liquid waste implemented under federal laws

other than RCRA (e.g., UIC Program requirements applicable to the injection of oil and gasrelated wastes into Class II wells).

EPA, Report to Congress: Management of Wastes from the Exploration, Development, and Production of Crude Oil,

Natural Gas, and Geothermal Energy (Dec. 1987), http://www.epa.gov/osw/nonhaz/industrial/special/oil/

530sw88003a.pdf.

Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes, 53

Fed. Reg. 25,446 (July 6, 1988).

Id.

See EPA’s “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) and “Exemption

of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations” (October 2002), both

available at http://www.epa.gov/osw/nonhaz/industrial/special/oil/index.htm.

EPA October 2002 guidance, at pp. 10-11.

Id.

A waste may be deemed hazardous based on reactive, ignitable, corrosive or toxic characteristics specified at 40

C.F.R. §261.20-.24.

Department of Energy, Modern Shale Gas Development in the United States: A Primer 66-71 (2009),

http://energy.gov/sites/prod/files/2013/03/f0/ShaleGasPrimer_Online_4-2009.pdf.

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Natural Resources Defense Council Petition to Regulate

E&P Wastes Under Subtitle C

In September 2010, the Natural Resources Defense Council (NRDC), an environmental advocacy

group, petitioned EPA to initiate a rulemaking under RCRA to regulate E&P wastes as hazardous

wastes under Subtitle C.83 In support of their petition, NRDC identified reports and data prepared

since 1988 that they assert “quantify the waste’s toxicity, threats to human health and the

environment, inadequate state regulatory programs, and readily available solutions.”84 In addition,

NRDC asserted that “both the oil and gas industry and the risks associated with E&P wastes have

expanded dramatically, making EPA’s 1988 Regulatory Determination unjustified.”85 The NRDC

sought to have EPA promulgate regulations that subject E&P wastes to Subtitle C to “ensure safe

management of these wastes throughout their life cycle from cradle to grave, including

generation, transportation, treatment, storage and disposal.”86

EPA has not yet formally responded to the NRDC petition. However, in 2011, EPA indicated that

in response to the petition, the Office of Solid Waste and Emergency Response was reviewing

incidents alleged by the petitioner; regulations in states with natural gas activities; and best

management practices for E&P wastes developed by industry, federal, and state associations.87

Based on its finding, EPA could possibly review and revise its 1988 regulatory determination.

However, as discussed above, the Bentsen amendment specifies that, if EPA determined that

Subtitle C regulation was warranted, proposed regulations could not take effect until authorized

by act of Congress.88 Thus, if EPA were to review its 1988 regulatory determination and find that

regulation under Subtitle C is necessary, the agency could arguably promulgate such regulations,

but could not implement them unless explicitly authorized by Congress to do so.

Comprehensive Environmental Response,

Compensation, and Liability Act89

The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA),90

often referred to as Superfund, provides broad authority for the federal government to respond to

releases or threatened releases of hazardous substances into the environment, in order to protect

Natural Resources Defense Council, Re: 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 1 (September 8, 2010) (hereinafter NRDC Petition),

http://docs.nrdc.org/energy/files/ene_10091301a.pdf. Section 7004(a) of RCRA permits “any person” to petition EPA

for promulgation of a regulation under RCRA. 42 U.S.C. §6974(a).

NRDC Petition at 1.

Id. at 5.

Id. at 4.

See EPA Special Litigation and Projects Division presentation to the American State and Tribal Solid Waste

Management Organization on “EPA’s Energy Extraction Enforcement Initiative,” (October 2011), including

presentation materials for Sandra Connors, Deputy Director, EPA Office of Resource Conservation and Recovery on

“Exploration & Production Waste and RCRA,” p. 31, available at http://www.astswmo.org/Files/Meetings/2011/2011Annual/Presentations/EPA-Hydro-Fracturing.pdf.

42 U.S.C. §6921(b)(2)(C).

(name redacted), Specialist in Environmental Policy, Resources, Sci ence, and Industry Division, contributed to the

preparation of this section of the report.

42 U.S.C. §§9601-9675.

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public health or welfare, or the environment. Federal resources to carry out response actions

under CERCLA are subject to the availability of appropriations. To minimize the burden of the

costs on the taxpayer, CERCLA established a liability scheme to hold persons responsible for a

release or threatened release liable for response costs (i.e., cleanup costs), natural resource

damages, and the costs of federal public health studies that may be carried out at a site to assess

potential hazards.91 The categories of “potentially responsible parties” who may be held liable

under CERCLA include past and current owners and operators of facilities from which there is a

release or threatened release of a hazardous substance, persons who arranged for disposal or

treatment of hazardous substances (often referred to as generators of wastes), and persons who

transported hazardous substances and selected the site for disposal or treatment.92 The President’s

response and enforcement authorities under CERCLA are delegated by Executive Order to the

EPA and certain other federal departments and agencies to fulfill various functions under the

statute.93

Although the sites at which hydraulic fracturing is conducted may not fit the typical mold of

Superfund sites, it is possible that hydraulic fracturing operations94 could result in the release of

hazardous substances into the environment at or under the surface in a manner that may endanger

public health or the environment. If a release were to occur as a result of hydraulic fracturing, the

facility owner and operator and other potentially responsible parties could face liability under

CERCLA. However, certain exclusions or exemptions from the statute potentially could limit

liability in such instances, including the petroleum and natural gas exclusion and the exemption

from liability for federally permitted releases, discussed below.

Petroleum and Natural Gas Exclusion

Although releases of petroleum and natural gas generally are excluded from the authorities of

CERCLA, this exclusion does not constitute a broader facility or industry exclusion, but is a

substance exclusion alone. Therefore, CERCLA may apply to hazardous substances released into

the environment from a petroleum or natural gas facility.95 Similarly, CERCLA also potentially

could apply to releases of hazardous substances resulting from oil or natural gas production, but

not releases of petroleum or natural gas itself.

The petroleum and natural gas exclusion is found in the CERCLA definition of a “hazardous

substance,” where the statute provides that the term “does not include petroleum, including crude

oil or any fraction thereof which is not specifically listed or designated as a hazardous substance

CERCLA also authorizes the federal government to respond to releases, or threatened releases, of pollutants or

contaminants into the environment that may present an imminent and substantial danger to public health or welfare, but

liability under the statute only extends to releases or threatened releases of hazardous substances.

42 U.S.C. §9607(a).

For further discussion of the scope and authorities of CERCLA, see CRS Report R41039, Comprehensive

Environmental Response, Compensation, and Liability Act: A Summary of Superfund Cleanup Authorities and Related

Provisions of the Act, by (name redacted) .

With respect to potential contamination, releases of hazardous substances possibly could occur as a result of many

different aspects of oil and gas production that involve hydraulic fracturing as an extraction technique. Various

stakeholders have used the term hydraulic fracturing in differing ways to reflect a varying scope of activities. In the oil

and gas industry, the term refers to a specific technique to stimulate oil or gas production from a formation, whereas

others may use the term to refer broadly to unconventional oil and gas production and related activities. For more

background on the variety of activities associated with shale gas production in particular, see CRS Report R42333,

Marcellus Shale Gas: Development Potential and Water Management Issues and Laws, by (name redacted) et al.

See EPA, Substances Covered Under Reporting Requirement, Petroleum Exclusion, http://www.epa.gov/osweroe1/

content/reporting/faq_subs.htm.

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... and the term does not include natural gas, natural gas liquids, liquefied natural gas or synthetic

gas usable for fuel.”96 Therefore, while CERCLA would not apply to leaked petroleum products

at a fracking site, contamination of a site by any substance that does satisfy the definition of a

“hazardous substance” could result in liability under the statute. For example, if fracking fluid

contained components (i.e., constituents) that are considered hazardous substances under

CERCLA, and such fluids were released into the environment at a site in a way that could

endanger public health or the environment, the release could warrant cleanup actions, the costs of

which the potentially responsible parties would be liable for under CERCLA. Liability similarly

could arise from releases of hazardous substances that may be present in produced wastewaters

from hydraulic fracturing.

Exemption for Federally Permitted Releases

Whether a release of hazardous substances that may result from hydraulic fracturing operations

would be in compliance with a federal permit (including permits issued by states under delegated

federal authorities) or a state-authorized permit would be a critical factor in determining liability.

CERCLA exempts persons from liability for response costs or damages under the statute resulting

from a “federally permitted release.”97 This exemption provides relief from liability under

CERCLA, but does not preclude liability under other federal or state law, including common law.

CERCLA defines a federally permitted release to include any underground injection of fluids

authorized under the Safe Drinking Water Act, any discharges of wastewater authorized under the

Clean Water Act, and other discharges or emissions authorized under certain other federal

statutes.98 This definition also includes any underground injection of fluids or other materials

authorized under applicable state law for the production or enhanced recovery of crude oil or

natural gas, or the reinjection of produced waters.99 The exemption from liability under CERCLA

for a federally permitted release therefore may include a state permitted release in such instances.

Examples of Application of CERCLA Response Authority

EPA has used the response authorities of CERCLA to investigate potential contamination in

groundwater in at least two instances that have received prominent attention at locations where

natural gas extraction using hydraulic fracturing has been conducted. One such instance occurred

in Dimock, PA, and another has occurred in Pavillion, WY. EPA initiated the Pavillion

groundwater investigation in response to a public petition submitted under CERCLA100 in 2008

that cited concerns of residents about groundwater quality.101 EPA issued a draft investigation

report for the Pavillion site on December 8, 2011.102 On June 20, 2013, EPA announced that it

42 U.S.C. §9601(14).

42 U.S.C. §9607(j).

42 U.S.C. §9601(10).

42 U.S.C. §9601(10)(I).

100

42 U.S.C. §9605(d). CERCLA authorizes any person who is or may be affected by a release or threatened release of

a hazardous substance, pollutant, or contaminant to petition the President (as delegated to EPA and other federal

departments and agencies) to assess potential hazards to public health and the environment. Id.

101

EPA, Region 8 and Office of Research and Development, National Risk Management Research Laboratory, (Draft)

Investigation of Ground Water Contamination near Pavillion, Wyoming, at 1 (December 2011), http://www.epa.gov/

region8/superfund/wy/pavillion/EPA_ReportOnPavillion_Dec-8-2011.pdf.

102

For information on the status of the Pavillion groundwater investigation, see EPA’s Region 8 website:

http://www2.epa.gov/region8/pavillion. For additional background information, see CRS Report R42327, The EPA

Draft Report of Groundwater Contamination Near Pavillion, Wyoming: Main Findings and Stakeholder Responses, by

(continued...)

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does not plan to finalize its groundwater investigation report for the Pavillion site.103 EPA

indicated that it would defer to the state of Wyoming to assume the lead in investigating drinking

water quality in the area, and that its continuing role would focus on providing technical support

to the state.104 The state intended to conclude its investigation and release a final report by

September 30, 2014.105 However, the EPA’s website states that, as of March 2016, the agency

continues to provide technical assistance to the State of Wyoming during the state’s ongoing

investigation of Pavillion groundwater issues.106 The EPA has submitted comments on the state’s

draft final report examining these issues.107

On January 19, 2012, EPA issued an Action Memorandum for the Dimock site to “request and

document approval of an emergency removal action to prevent, limit, or mitigate the threats

posed by the presence of hazardous substances at the Dimock Residential Groundwater Site ...

pursuant to Section 104(a) of the Comprehensive Environmental Response, Compensation and

Liability Act.”108 The Action Memorandum noted that “[h]istoric drilling activities in the Dimock

area have used materials containing hazardous substances” and that there was “reason to believe

that a release of hazardous substances has occurred” that may have contaminated groundwater

used by residents in the area.109 EPA announced on July 25, 2012, that it had completed its

groundwater investigation at the Dimock site and determined that contaminant levels did not

warrant further action by the agency.110

Although the Dimock and Pavillion sites differ in terms of their geophysical characteristics and

other site-specific conditions, they offer examples of the use of the authorities of CERCLA to

investigate potential contamination at locations where hydraulic fracturing has been conducted. In

both cases, EPA has not confirmed a definitive link between a release of hazardous substances

and hydraulic fracturing, and no potentially responsible parties have been identified at either site

who would be liable under CERCLA.

National Environmental Policy Act111

The National Environmental Policy Act (NEPA) requires federal agencies to consider the

potential environmental consequences of proposed federal actions and to involve the public in the

federal decisionmaking process, but does not compel agencies to choose a particular course of

(...continued)

(name redacted), (name redacted), and (name redacted)

103

Press Release, Wyoming to Lead Further Investigation of Water Quality Concerns Outside of Pavillion with Support

of EPA (June 20, 2013), http://yosemite.epa.gov/opa/admpress.nsf/20ed1dfa1751192c8525735900400c30/

dc7dcdb471dcfe1785257b90007377bf!OpenDocument.

104

Id.

105

Id.

106

See https://www.epa.gov/region8/pavillion.

107

Id.

108

Action Memorandum-Request for Funding for a Removal Action at the Dimock Residential Groundwater Site,

Intersection of PA Routes 29 and 2024 Dimock Township, Susquehanna County, Pennsylvania (Jan 19, 2012),

available at http://www.epaosc.org/sites/7555/files/Dimock%20Action%20Memo%2001-19-12.PDF.

109

Id.

110

Press release: “EPA Completes Drinking Water Sampling in Dimock, PA,” available at http://yosemite.epa.gov/opa/

admpress.nsf/d0cf6618525a9efb85257359003fb69d/1a6e49d193e1007585257a46005b61ad.

111

(name redacted), Analyst in Environmental Policy, Resources, Science, and Industry Division, contributed to the

preparation of this section of the report.

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action.112 If the action is anticipated to affect significantly the quality of the human environment,

the agency must document its consideration of those effects in an environmental impact statement

(EIS). If the degree of impacts is uncertain, an agency may prepare an environmental assessment

(EA) to determine whether a finding of no significant impact (FONSI) could be made or whether

an EIS is necessary. There are certain categories of action that do not individually or cumulatively

have a significant effect on the human environment and, thus, do not require the preparation of an

EIS or EA.113

In contrast to the other environmental statutes discussed in this report, NEPA is a procedural

statute. It requires that agencies assess the environmental consequences of an action. If the

adverse environmental effects of the proposed action are adequately identified and evaluated, an

agency is not constrained by NEPA from deciding that other benefits outweigh the environmental

costs and moving forward with the action. Because the requirements of NEPA apply only to

federal actions,114 NEPA applies to hydraulic fracturing activities only when such activities take

place on federal lands or when there is otherwise a sufficient federal nexus to hydraulic

fracturing. The following sections discuss two case studies involving a potential federal role in

the production of oil or natural gas resources that may potentially require the preparation of a

NEPA document.

Drilling in the Monterey Shale: Federal Oil and Gas Leases

Oil and gas companies have shown interest in drilling in the Monterey Shale in Central

California.115 The shale formation was at one time estimated to contain billions of barrels of oil,

most of which may be economically recovered only through the use of hydraulic fracturing and

horizontal drilling.116 In 2011, the Bureau of Land Management (BLM) sold leases in four

parcels, which accounted for about 2,700 acres of public land, to private parties.117 Environmental

groups sued BLM, claiming that the agency had violated the Administrative Procedure Act (APA)

and NEPA when it prepared an EA, resulting in a FONSI, instead of an EIS for the proposed lease

sale.118

During the public comment period for the EA, several parties expressed concerns about the

potential environmental effects of hydraulic fracturing.119 However, BLM declined to analyze

these impacts because, in its view, they were “not under the authority or within the jurisdiction of

the BLM.”120 After issuing a FONSI, BLM proceeded with the auction.121

112

See 42 U.S.C. §4332. For further discussion of NEPA, see CRS Report RL33152, The National Environmental

Policy Act (NEPA): Background and Implementation, by (name redacted)

113

40 C.F.R. §1508.4. By statute, there is a rebuttable presumption that the use of a categorical exclusion under NEPA

applies if certain actions related to oil and gas exploration or development on federal lands are conducted pursuant to

the Mineral Leasing Act. 42 U.S.C. §15942.

114

42 U.S.C. §4332.

115

Order Re: Cross Motions for Summary Judgment at 1-2, Ctr. for Biological Diversity v. Bureau of Land Mgmt., No.

11-06174 (N.D. Cal. Mar. 31, 2013).

116

Id. at 2-3.

117

Id. at 12.

118

Id. at 1.

119

Id. at 6-7.

120

Id.

121

Id. at 10. The FONSI discussed potential impacts on protected wildlife and plant species but did not discuss

hydraulic fracturing. Id. at 27.

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The Council on Environmental Quality (CEQ) promulgated regulations implementing NEPA that

are broadly applicable to all federal agencies.122 Those regulations specify what agencies must do

to determine whether a proposed action will significantly affect the environment and, therefore,

require preparation of an EIS.123 To determine what constitutes “significant” effects, CEQ

regulations require agencies to consider the context of the action and intensity or severity of its

impacts.124 Environmental impacts that must be considered include those identified by CEQ as

direct, indirect (reasonably foreseeable future impacts), or cumulative.125

The district court examined the 10 factors CEQ regulations identify as requiring consideration

when determining the severity of an action’s impacts.126 Consistent with those factors, the court

identified three factors that it believed required BLM to prepare an EIS. According to the court,

these were: (1) hydraulic fracturing is highly controversial because of its potential effects on

health and the environment; (2) the proposed lease sale would affect public health and safety

because of the risk of water pollution; and (3) the environmental impacts of hydraulic fracturing

are uncertain.127 The court also found that BLM did not properly investigate possible direct or

indirect impacts of its decision.128

In March 2013, the district court held that the BLM NEPA review was “erroneous as a matter of

law.”129 The court held that BLM unreasonably relied on an environmental analysis that (1)

assumed only one exploratory well would be drilled on the leased acres when it was reasonably

foreseeable that more wells would be drilled; and (2) did not contain a detailed assessment of the

environmental impacts of hydraulic fracturing and horizontal drilling.130

Delaware River Basin Commission: Proposed Regulations

on Natural Gas Development

The Delaware River Basin Compact is an agreement among the federal government, Delaware,

New Jersey, New York, and Pennsylvania.131 The compact creates the Delaware River Basin

Commission (DRBC) and grants it certain powers to manage the water resources of the basin.132

In December 2010, the commission published draft regulations “to protect the water resources of

the Delaware River Basin during the construction and operation of natural gas development

122

40 C.F.R. §§1500-1508. CEQ directed all federal agencies to adopt procedures to supplement the CEQ regulations

to include detail specific to the classes of action implemented by that agency (40 C.F.R. §1507.3).

123

40 C.F.R. §1501.3-.4.

124

40 C.F.R. §1508.27.

125

40 C.F.R. §1508.8.

126

Order Re: Cross Motions for Summary Judgment at 20.

127

Id. at 24-27.

128

Id. at 26-28.

129

Id. at 2. The court also held that BLM had an obligation to prepare a NEPA document prior to the sale of leases that

did not contain No Surface Occupancy (NSO) provisions rather than during the Application for Permit to Drill (APD)

process. Id. at 15-18. This was because once non-NSO leases had been issued, BLM retained limited authority to deny

a lessee drilling rights during the APD process, and thus an “irretrievable commitment of resources” under NEPA had

occurred. Id.; see also 42 U.S.C. §4332(C)(v); 40 C.F.R. §§1501.2, 1502.5.

130

Order Re: Cross Motions for Summary Judgment at 1-2.

131

Delaware River Basin Compact, 75 Stat. at 689. The text of the compact is contained in the federal law approving

the compact.

132

Delaware River Basin Compact §§1.3(c), (e); 2.1; 3.1.

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projects.”133 In May 2011, the New York Attorney General brought a federal lawsuit on behalf of

the State of New York alleging that five federal agencies and their officers were in violation of

NEPA.134 In November 2011, the complaint was amended to add the DRBC and its executive

director as defendants.135 The plaintiffs asked the court to compel the defendants to prepare an

EIS “before proceeding to adopt federal regulations to be administered by DRBC that would

authorize natural gas development within the Delaware River Basin.”136 New York alleged that

the approval of the DRBC regulations was a major federal action requiring at least one of the

defendants to prepare an EIS.137 New York alleged that the refusal of the five federal agencies that

are represented by the DRBC’s federal member138 to prepare an EIS was not in accordance with

law and was arbitrary, capricious, and an abuse of discretion under the APA.139 Because it appears

that the Delaware River Basin Compact exempts the DRBC from compliance with the APA,140

New York argued that the DRBC’s refusal to prepare an EIS was subject to judicial review under

the compact itself.141

The federal defendants moved to dismiss the lawsuit on the grounds that the court lacked subject

matter jurisdiction over the plaintiff’s claims.142 In addition to procedural arguments, the federal

defendants maintained that NEPA did not apply because the DRBC’s development of proposed

regulations was not a “major federal action.”143 The federal defendants argued that no federal

action existed because, in their view, the DRBC was not a federal agency.144 In addition, the

federal defendants argued that they did not exercise enough decisionmaking power, authority, or

control over the DRBC’s development of the proposed regulations to render it a federal action.145

133

Delaware River Basin Commission, Draft Natural Gas Development Regulations, http://www.nj.gov/drbc/programs/

natural/draft-regulations.html.

134

Initial Complaint at ¶¶ 1, 95, New York v. U.S. Army Corps of Eng’rs, No. 11-2599 (E.D.N.Y. May 31, 2011).

135

Amended Complaint at ¶ 1, New York v. U.S. Army Corps of Eng’rs, No. 11-2599 (E.D.N.Y. Nov. 22, 2011).

136

Amended Complaint at ¶ 1 (abbreviations omitted). According to the complaint, if the DRBC approved the

regulations, “between 15,000 and 18,000 natural gas wells” would be developed within the Delaware River Basin using

high-volume hydraulic fracturing. Id. at ¶ 4. High-volume hydraulic fracturing has raised concerns among some groups

because of its potential effects on water resources and the environment. For more information on this issue, see CRS

Report R41760, Hydraulic Fracturing and Safe Drinking Water Act Regulatory Issues, by (name redacted) and (name

redacted)

137

Id. at ¶¶ 37, 95, 99-100, 109-11.

138

These agencies are the Army Corps of Engineers, Fish and Wildlife Service, National Park Service, Department of

the Interior, and Environmental Protection Agency.

139

Id. at ¶ 106; see also 5 U.S.C. §706(2)(A). NEPA does not contain a private right of action.

140

See Delaware River Basin Compact, P.L. 87-328, §15.1(m), 75 Stat. 688, 715 (1961) (“For purposes of ... the Act of

June 11, 1946, 60 Stat. 237, as amended ... the Commission shall not be considered a Federal agency.”).

141

Amended Complaint at ¶¶ 11, 115; see also Delaware River Basin Compact, §3.3(c), 75 Stat. 688, 693 (1961) (“Any

other action of the commission pursuant to this section shall be subject to judicial review in any court of competent

jurisdiction.”).

142

Memorandum of Law in Support of Motion to Dismiss at 1, New York v. U.S. Army Corps of Eng’rs, No. 11-2599

(E.D.N.Y. June 4, 2012). The DRBC and its executive director also filed a motion to dismiss the complaint. See

Delaware River Basin Commission and Carol R. Collier’s Memorandum of Law in Support of Their Motion To

Dismiss the Amended Complaint of New York State, New York v. U.S. Army Corps of Eng’rs, No. 11-2599 (E.D.N.Y.

Jan. 12, 2011).

143

Id. at 33.

144

Id. at 33-34.

145

Id. at 34-39.

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In September 2012, the U.S. District Court for the Eastern District of New York granted the

defendants’ motions to dismiss New York’s complaint for lack of subject matter jurisdiction.146

The court held that it lacked subject matter jurisdiction for two reasons. First, the court held that

New York lacked standing because it could not show an immediate threat of injury to its interests

from the proposed regulations.147 Alternatively, the court held that it lacked subject matter

jurisdiction because New York’s complaint was not ripe for review.148 Because the court

dismissed the plaintiffs’ complaint on procedural grounds, it did not reach the merits of the

plaintiffs’ claims. However, because the court dismissed the suit without prejudice, the plaintiffs

may file it again in the future if final regulations are adopted.149

The Debate over Public Disclosure of the Chemical

Composition of Hydraulic Fracturing Fluids

The composition of the fluid used in hydraulic fracturing varies with the nature of the formation

but typically contains mostly water; a proppant to keep the fractures open, such as sand; and a

small percentage of chemicals.150 A primary function of these chemicals is to assist the movement

of the proppant into the fractures made in the formation.151 Although some of these chemicals

may be harmless, others may be hazardous to health and the environment.152 A report by the

minority staff of the House Committee on Energy and Commerce found that between 2005 and

2009, the 14 leading oil and gas service companies used 780 million gallons of chemical products

in fracturing fluids.153

Calls for public disclosure of information about chemicals used in hydraulic fracturing have

increased as homeowners and others express concerns about the potential presence of unknown

chemicals in tainted well water near oil and gas operations.154 Proponents of chemical disclosure

laws maintain that public disclosure of the chemicals used in each well would allow for health

professionals to better respond to medical emergencies involving human exposure to the

chemicals; assist researchers in conducting health studies on shale gas production; and permit

regulators and others to perform baseline testing of water sources to track potential groundwater

contamination if it occurs.155 However, some manufacturers of the additives, as well as others in

the industry, remain reluctant to disclose information about the chemicals they use. These parties

146

Memorandum and Order at 4, New York v. U.S. Army Corps of Eng’rs, No. 11-2599 (E.D.N.Y. Sept. 24, 2012).

Id. at 22.

148

Id. at 28.

149

Id. at 23.

150

Department of Energy, Modern Shale Gas Development in the United States: A Primer, 56, 61-64 (2009)

(hereinafter Department of Energy Primer), http://energy.gov/sites/prod/files/2013/03/f0/ShaleGasPrimer_Online_42009.pdf.

151

Id.; Reservoir Stimulation §§7-6.2, 7-6.4 (Michael J. Economides et al., eds) (3d ed. 2000).

152

Department of Energy Primer at 62. See also Minority Staff of House Committee on Energy and Commerce, 112th

Congress, Chemicals Used in Hydraulic Fracturing 5, 9 (2011) (hereinafter Minority Report on Fracturing Chemicals),

http://democrats.energycommerce.house.gov/sites/default/files/documents/

Hydraulic%20Fracturing%20Report%204.18.11.pdf.

153

Minority Report on Fracturing Chemicals at 5.

154

For more information on this issue, see CRS Report R41760, Hydraulic Fracturing and Safe Drinking Water Act

Regulatory Issues, by (name redacted) and (nameredacted)

155

See Lisa Song, Secrecy Loophole Could Still Weaken BLM’s Tougher Fracturing Regs, InsideClimate News, Feb.

15, 2012.

147

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have expressed concerns that disclosure would reveal proprietary chemical formulas to their

competitors, destroying the parties’ valuable trade secrets.156

In 2011, President Barack Obama directed Secretary of Energy Steven Chu to convene a panel to

study the effects of shale gas production on health and the environment.157 The Shale Gas

Production Subcommittee of the Secretary of Energy Advisory Board made several

recommendations intended to address these effects.158 One recommendation calls for the public

disclosure, on a “well-by-well basis,” of all of the chemicals added to fracturing fluids, with some

protection for trade secrets.159 No federal law currently requires parties to submit detailed

information about the chemical composition of a hydraulic fracturing fluid. Under the Emergency

Planning and Community Right-to-Know Act (EPCRA), owners or operators of facilities where

certain hazardous hydraulic fracturing chemicals are present above certain thresholds may have to

comply with emergency planning requirements; emergency release notification obligations; and

hazardous chemical storage reporting requirements.160 In addition, environmental advocacy

groups have petitioned EPA to collect and share health and environmental effect information for

hydraulic fracturing chemicals under the Toxic Substances Control Act and to require the oil and

gas extraction industry to report the toxic chemicals it releases under EPCRA Section 313, which

established EPA’s Toxics Release Inventory.161

Several states have adopted chemical disclosure requirements in the form of laws, regulations, or

administrative interpretations.162 The Interstate Oil and Gas Compact Commission (IOGCC), an

organization with members that include state regulators and industry representatives, has argued

that current regulation of hydraulic fracturing by the states is sufficient.163

Toxic Substances Control Act

A main goal of the Toxic Substances Control Act (TSCA) is to protect human health and the

environment from unreasonable risks associated with toxic chemicals in U.S. commerce.164 Under

156

See Minority Report on Fracturing Chemicals at 11-12. Some manufacturers of fracturing fluid additives have

claimed that developing the additives costs millions of dollars and takes several years. See Mike Soraghan, Two-thirds

of Frack Disclosures Omit ‘Secrets,’ http://www.eenews.net/public/energywire/2012/09/26/1.

157

For more on the subcommittee’s work, see Improving the Safety & Environmental Performance of Hydraulic

Fracturing, http://www.shalegas.energy.gov/.

158

Department of Energy, Shale Gas Production Subcommittee Second Ninety Day Report 1 (2011),

http://www.shalegas.energy.gov/resources/111811_final_report.pdf.

159

Id. at 5-6, 17.

160

42 U.S.C. §§11002, 11004, 11021, 11022.

161

Earthjustice, Citizen Petition Under Toxic Substances Control Act Regarding the Chemical Substances and

Mixtures Used in Oil and Gas Exploration or Production 1, 22, http://earthjustice.org/sites/default/files/

fracking_petition.pdf; Earthworks, Petition to Add the Oil and Gas Extraction Industry, Standard Industrial

Classification Code 13, to the List of Facilities Required to Report under the Toxics Release Inventory 1,

http://www.earthworksaction.org/library/detail/petition_to_add_oil_gas_extraction_to_TRI.

162

For an overview of state requirements of this type and other federal proposals, see CRS Report R42461, Hydraulic

Fracturing: Chemical Disclosure Requirements, by (name redacted) and (name redacted)

163

Interstate Oil and Gas Compact Commission, Hydraulic Fracturing, http://www.iogcc.state.ok.us/hydraulicfracturing.

164

15 U.S.C. §2601; S. Rept. 94-1302, at 56 (1976) (Conf. Rep.). On June 22, 2016, the President signed into law

amendments to TSCA (P.L. 114-182). For more information on TSCA as amended, see CRS Report R44434, Proposed

Amendments to the Toxic Substances Control Act (TSCA) in the 114th Congress: H.R. 2576 Compared with the Senate

Substitute Amendment, by (name redacted) and (name redacted) .

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the act, EPA may require manufacturers and processors of chemicals to develop, maintain, and

report data on the chemicals’ effects on health and the environment.165 EPA may also place certain

restrictions on chemicals when the agency has determined that they warrant regulation based on

unreasonable risk of injury to health or the environment or other criteria delineated in the

statute.166,167

On August 4, 2011, Earthjustice and more than 100 other environmental advocacy organizations

petitioned EPA to promulgate rules under Section 4 and Section 8 of TSCA for chemical

substances and mixtures used in oil and gas exploration or production (E&P Chemicals).168

Section 4 of TSCA authorizes EPA to issue rules requiring manufacturers or processors of

chemicals to test the chemicals in order to obtain data on their health and environmental

effects.169 Section 8 of TSCA generally authorizes EPA to require manufacturers, processors, and

distributors of chemicals in U.S. commerce to maintain and report certain data on the health and

environmental effects of the chemicals.170 The petition stated that EPA and the public “lack

adequate information about the health and environmental effects of E&P Chemicals, which are

used in increasing amounts to facilitate the rapid expansion of oil and gas development

throughout the United States.”171

Earthjustice and the other petitioners further argued that E&P Chemicals may present an

unreasonable risk of injury to health and the environment for several reasons. Petitioners

maintained that, for example, leaks and spills of the chemicals may cause harm to people and

animals, as well as the quality of air, water, and soil.172 The petitioners also argued that the large

volume of chemicals used in hydraulic fracturing of wells in the United States could result in

substantial human exposure to the chemicals, as well as a substantial release of the chemicals into

the environment.173 In the petitioners’ view, testing was needed to obtain sufficient data on the

chemicals’ effects because existing federal and state disclosure requirements were inadequate.174

EPA’s response to the petitioners was mixed. In a November 2, 2011, letter, EPA denied the

petitioners’ request for promulgation of a TSCA Section 4 test rule.175 In a short paragraph, the

agency wrote that the petitioners had failed to present sufficient facts for EPA to find that such a

165

E.g., 15 U.S.C. §§2603, 2607.

15 U.S.C. §2605(a). EPA must consider the benefits of the chemical product or process when considering how, if at

all, to regulate it. Not all of the chemicals used in hydraulic fracturing are necessarily subject to regulation under

TSCA. For example, biocides, which are often used in a fracturing fluid to kill bacteria, may be subject to regulation as

pesticides under the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA). See id. §2602. See also Gayathri

Vaidyanathan, Official Urges EPA Review, Labeling of Fracking Substances, E&E News (Oct. 24, 2012). CRS Report

RL31921, Pesticide Law: A Summary of the Statutes, by (name redacted) and (name redacted)

167

168

Earthjustice, Citizen Petition Under Toxic Substances Control Act Regarding the Chemical Substances and

Mixtures Used in Oil and Gas Exploration or Production 1, 22, (hereinafter Earthjustice Petition),

http://earthjustice.org/sites/default/files/fracking_petition.pdf. Section 21 of TSCA allows any person to petition EPA

to adopt a new rule under certain sections of the act. 15 U.S.C. §2620.

169

15 U.S.C. §2603; see also 40 C.F.R. §790.1. The petitioners also asked EPA to require manufacturers and

processors to disclose the identities of the chemicals they were required to test. Earthjustice Petition at 18.

170

15 U.S.C. §2607.

171

Earthjustice Petition at 1.

172

Earthjustice Petition at 13-19.

173

Id. at 19.

174

Id. at 5-10.

175

Letter from Assistant Administrator Stephen A. Owens to Deborah Goldberg (November 2, 2011),

http://www.epa.gov/oppt/chemtest/pubs/SO.Earthjustice.Response.11.2.pdf.

166

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rule was necessary.176 However, in a November 23, 2011, letter, EPA partially granted petitioners’

Section 8(a) and Section 8(d) requests.177 The agency wrote that it would initiate a rulemaking to

gather available data on the chemicals used in hydraulic fracturing.178 However, the agency

declined to issue rules for other chemicals in the oil and gas exploration and production sector.179

EPA intends to discuss potential Section 8 reporting requirements with the states, industry, and

public interest groups to “minimize reporting burdens and costs, take advantage of existing

information, and avoid duplication of efforts.”180 On July 11, 2013, EPA published an explanation

of the reasons for the agency’s response to the petition.181

In May 2014, EPA issued an advance notice of proposed rulemaking “to develop an approach to

obtain information on chemical substances and mixtures used in hydraulic fracturing.”182 EPA

indicated that it had not yet determined whether to mandate disclosure of the chemical

information under TSCA, provide incentives for voluntary reporting, or use an approach

combining aspects of both mandatory and voluntary disclosure.183

Occupational Safety and Health Act

The Occupational Safety and Health Administration has promulgated a set of regulations under

the Occupational Safety and Health Act (OSHAct) referred to as the Hazard Communication

Standard (HCS).184 A primary purpose of the HCS is to ensure that employees who may be

exposed to hazardous chemicals in the workplace are aware of the chemicals’ potential dangers.185

Manufacturers and importers must obtain or develop Material Safety Data Sheets (MSDS) for

hydraulic fracturing chemicals that are hazardous according to OSHA standards.186 MSDS must

list basic information about the identity of the chemicals; the chemicals’ potential hazards; and

safety precautions for their handling and use, among other things.187 The HCS requires operators

to maintain MSDS for hazardous chemicals at the job site.188

176

Id.

Letter from Assistant Administrator Stephen A. Owens to Deborah Goldberg (November 23, 2011),

http://www.epa.gov/oppt/chemtest/pubs/EPA_Letter_to_Earthjustice_on_TSCA_Petition.pdf.

178

Id.

179

Id.

180

Id.

181

U.S. Environmental Protection Agency, “Chemical Substances and Mixtures Used in Oil and Gas Exploration or

Production; TSCA Section 21 Petition; Reasons for Agency Response,” 78 Fed. Reg. 41,768 (July 11, 2013).

182

EPA, Advance Notice of Proposed Rulemaking, Hydraulic Fracturing Chemicals and Mixtures, 79 Fed. Reg. 28664

(May 19, 2014).

183

Id. For the current status of the rulemaking, see http://yosemite.epa.gov/opei/RuleGate.nsf/byRIN/2070-AJ93.

184

29 C.F.R. §1910.1200. See also 29 U.S.C. §655. OSHA recently modified its Hazard Communication Standard,

effective May 25, 2012. The regulation now requires that by June 1, 2015, employers communicate workplace hazards

to employees by using Safety Data Sheets that are consistent with the United Nations Globally Harmonized System of

Classification and Labeling of Chemicals. 29 C.F.R. §1910.1200(a), (j). In addition to other information, the data sheets

will be required to contain a more specific description of certain chemical substances and mixtures, provided that this

information does not qualify for trade secret protection under the regulations. Id. §1910.1200(g), (i), app. D. During the

transition period, parties may comply with the new regulations, the previous version of the regulations, or both. Id.

§1910.1200(j)(3).

185

Id. §1910.1200(a)-(b) (2011).

186

Id.at §1910.1200(d), (g).

187

Id.at §1910.1200(g).

188

177

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MSDS may provide limited information about hydraulic fracturing chemicals. Currently, the most

specific details about chemical identities that must be listed on the data sheets are the common or

chemical names of substances that are considered to be hazardous under OSHA regulations.189

Chemical Abstract Service Registry Numbers (CASRNs) for substances or mixtures do not have

to be listed. In addition, parties that prepare MSDS may withhold chemical identity information

from the data sheets at their discretion in some circumstances.190 However, the regulations do not

prevent parties from voluntarily submitting data sheets with more detailed information.

Emergency Planning and Community

Right-to-Know Act

The Emergency Planning and Community Right-to-Know Act (EPCRA) establishes programs to

provide members of the public with information about hazardous chemicals located in their

communities.191 It also requires that representatives from different levels of government

coordinate their efforts with communities and industry to prepare response plans for emergencies

involving the accidental release of hazardous chemicals.192

The act seeks to induce each state to establish a State Emergency Response Commission

(SERC).193 Each SERC appoints and coordinates the activities of a Local Emergency Planning

Committee (LEPC) for each emergency planning district created within a state or across multiple

states.194 A LEPC is responsible for developing an emergency response plan for an accidental

chemical release with input from stakeholders and submitting it to the SERC.195 Generally, a

facility is subject to EPCRA’s emergency planning requirements if there is a substance on EPA’s

list of extremely hazardous substances (EHS) present at the facility in excess of its EPAdetermined threshold planning quantity.196 Whether a well site where hydraulic fracturing occurs

would be subject to EPCRA’s planning requirements would depend on the identities and

quantities of the chemicals present, among other things.

Emergency Release Notification and Hazardous Chemical Storage

Reporting Requirements

Under Section 304 of EPCRA, an owner or operator of a facility must immediately notify the

SERC and the community emergency coordinator for the LEPC in the affected area if an

189

Id. §1910.1200(g)(2). For more information on the limitations of MSDS, see Clifford S. Mitchell & Brian S.

Schwartz, Limitations of Information About Health Effects of Chemicals, Journal of General Internal Medicine,

http://www.ncbi.nlm.nih.gov/pmc/articles/PMC1495173/pdf/jgi_01217.pdf.

190

Id. §1910.1200(i)(1) (2011). See also Mike Soraghan, In Fracking Debate, ‘Disclosure’ Is in the Eye of the

Beholder, New York Times (June 21, 2010).

191

H. Rept. 99-962, at 281 (1986) (Conf. Rep.). For more on EPCRA, seeCRS Report RL32683, The Emergency

Planning and Community Right-to-Know Act (EPCRA): A Summary, by (name redacted) .

192

42 U.S.C. §11001; H. Rept. 99-962, at 281 (1986) (Conf. Rep.).

193

42 U.S.C. §11001(a).

194

Id. §11001(a)-(c).

195

Id. §§11001(c), 11003.

196

Id. §11002. EPA’s list of EHS and their threshold planning quantities is located at 40 C.F.R. Part 355 appendixes A

and B. A state governor or SERC may designate additional facilities as subject to EPCRA, provided that the

designation is made after public notice and opportunity for comment. 42 U.S.C. §11002(b)(2).

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accidental release of a chemical that is an EHS occurs in an amount in excess of its reportable

quantity from a facility where an EHS is produced, used, or stored.197 This information must be

made available to the public.198

Section 311 of EPCRA generally requires that facility owners or operators submit an MSDS for

each hazardous chemical199 present that exceeds an EPA-determined threshold level, or a list of

such chemicals, to the LEPC, SERC, and the local fire department.200 For non-proprietary

information, the act generally requires a LEPC to provide an MSDS to a member of the public on

request.201 Again, whether a well site where hydraulic fracturing occurs would be subject to

EPCRA’s requirements would depend on the identities and quantities of the chemicals present,

among other things.

Under Section 312 of EPCRA, facility owners or operators must submit annual chemical

inventory information for hazardous chemicals present at the facility in excess of an EPAdetermined threshold level to the LEPC, SERC, and the local fire department.202 There are two

types of information that may have to be submitted. If the facility owner or operator is required to

report “Tier I information,” then the inventory form must contain information about the

maximum and average daily aggregate amounts of chemicals in each hazard category present at

the facility during the prior year, as well as the general location of chemicals in each category.203

However, most states require the submission of “Tier II information.”204 This information

includes “Tier I information,” as well as the chemical or common name of each hazardous

chemical as listed on its MSDS and the location and manner of storage of the chemical at the

facility.205 Tier II information for the prior calendar year for a particular facility must be made

available to members of the public upon written request.206 A SERC or LEPC must disclose to the

requester any non-proprietary information it possesses.207 If the SERC or LEPC lacks the

197

Id. §11004. If the release of an EHS is not required to be reported to the National Response Center under Section

103(a) of CERCLA, then the notification must be made only if (1) the release is not a federally permitted release under

CERCLA; (2) it exceeds the relevant minimal reportable quantity established by EPA regulation, or if none has been

established, one pound; and (3) it “occurs in a manner which would require notification under section 103(a) of

CERCLA.” Id. If the release is required to be reported to the National Response Center, but it is not a release of an

EHS, then notice must be given if the release is of a substance with a reportable quantity established under CERCLA,

or, if no reportable quantity has been established, if the release exceeds one pound. Id. A list of designated CERCLA

hazardous substances and their reportable quantities is located at 40 C.F.R. §302.4.

In addition, the notification provision “does not apply to any release which results in exposure to persons solely within

the site or sites on which a facility is located.” 42 U.S.C. §11004. The release notification requirements are in addition

to those under CERCLA. 40 C.F.R. §355.60. Different notification requirements apply when a release involves

transportation of a substance or storage of a substance incident to its transportation. 42 U.S.C. §11004(b).

198

Id. §11044.

199

“Hazardous chemical” in this section of EPCRA refers to chemicals that require an MSDS under OSHAct. It is a

more inclusive term than EHS.

200

Id. §11021.

201

Id. §11021(c). Regulations promulgated under EPCRA set forth procedures for EPA to follow when reviewing a

claim that information submitted to EPA is a trade secret. 40 C.F.R. Part 350.

202

Id. §11022.

203

Id. §11022(d).

204

Environmental Protection Agency, Tier II Chemical Inventory Reports, http://www.epa.gov/osweroe1/content/

epcra/tier2.htm.

205

42 U.S.C. §11022(d). The owner may withhold proprietary information from disclosure in some circumstances. Id.

§11042.

206

42 U.S.C. §11022(e).

207

Id.

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information for a hazardous chemical, then it must request the information from the facility

owner or operator and disclose the non-proprietary portions of it to the requester.208

Earthworks Petitioners’ Request for the Oil and Gas Extraction

Industry to Report Under the Toxics Release Inventory

Section 313 of EPCRA requires owners or operators of certain facilities to report information

about the release into the environment of certain “toxic” chemicals from the facilities.209 This

information must be disclosed to federal and state officials, who in turn disclose the nonproprietary details to the public via the Toxics Release Inventory (TRI) website.210 Generally, the

reporting requirements apply to owners or operators of facilities with 10 or more full-time

employees when the facilities fall under certain Standard Industrial Classification or North

American Industry Classification System codes and manufactured, processed, or otherwise used a

listed toxic chemical in excess of its threshold reporting amount during the applicable calendar

year.211 Facilities used by the oil and gas extraction industry are generally not included in the

industry codes required to report under the TRI.212

Section 313(b) allows EPA to add or delete industry codes as needed.213 In October 2012,

Earthworks and several other environmental advocacy organizations asked EPA to require the oil

and gas extraction industry to report the toxic chemicals it releases under the TRI program.214

When determining whether to add new industry groups, EPA has previously considered three

factors:

(1) Whether one or more listed toxic chemicals are reasonably anticipated to be present at

facilities in that industry (chemical factor); (2) whether facilities within the candidate

industry group ‘manufacture,’ ‘process,’ or ‘otherwise use’ EPCRA section 313 listed

toxic chemicals (activity factor); and (3) whether addition of facilities within the

candidate industry group reasonably can be anticipated to increase the information made

available pursuant to EPCRA section 313 or to otherwise further the purposes of EPCRA

section 313 (information factor).215

The Earthworks petitioners argued that the oil and gas extraction industry met the chemical factor

because drilling, well development, and hydraulic fracturing at well sites use many chemicals

208

Id. If the SERC or LEPC lacks the information for a hazardous chemical stored in an amount of less than 10,000

pounds during the prior year, the requester must state the general need for the information. Id.

209

Id. §11023(a), (b). The list of applicable toxic chemicals and chemical categories is located at 40 C.F.R. §372.65.

Under the Pollution Prevention Act, facility owners or operators covered by EPCRA requirements must also report

information about toxic chemical source reduction and recycling. 42 U.S.C. §13106.

210

Id. §11023(h), (j). For more information on this website, see http://www.epa.gov/tri/.

211

42 U.S.C. §11023(b). “Manufacture” means “to produce, prepare, import, or compound a toxic chemical.” Id.

“Process” means “the preparation of a toxic chemical, after its manufacture, for distribution in commerce.” Id. EPA

may also subject owners or operators of facilities with fewer than 10 employees and/or in other industry codes to the

requirements in certain circumstances if those facilities manufacture, process, or use any of certain “toxic” chemicals.

Id.

212

42 U.S.C. §11023(c).

213

42 U.S.C. §11023(b).

214

Earthworks, Petition to Add the Oil and Gas Extraction Industry, Standard Industrial Classification Code 13, to the

List of Facilities Required to Report under the Toxics Release Inventory 1 (hereinafter Earthworks Petition),

http://www.earthworksaction.org/library/detail/petition_to_add_oil_gas_extraction_to_TRI.

215

Final Rule, 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, 23,842 (May 1, 1997).

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listed on the TRI.216 With respect to the activity factor, the petitioners maintained that the industry

manufactured, processed, and otherwise used TRI chemicals via well completions, well

development, and hydraulic fracturing, among other processes.217 Finally, petitioners argued that

the information factor was satisfied because existing federal and state disclosure laws were

“inadequate.”218 The petition is still under review.

State Preemption of Municipal Land Use and

Zoning Powers

As the use of hydraulic fracturing and horizontal drilling to initiate production from oil and gas

wells has increased, owners of property located near oil and gas operations have expressed

concerns about the potential effects of these activities on the environment.219 Additionally, some

worry that the proximity of oil and gas operations to their homes will cause a decline in the values

of their properties.220 In response to these concerns, many local governments have increased their

regulation of hydraulic fracturing and related oil and gas production activities.221 Some

requirements imposed by local governments appear to be intended to regulate the land use aspects

of oil and gas operations.222 However, other requirements have tended toward regulation of the

technical aspects of oil and gas operations.223

In addition to raising questions about the relationship between federal and state authority, the

increase in local regulation of hydraulic fracturing has led to questions about the relationship

between state and local authority. Regulation of oil and gas operations is an area of mixed state

and local concern.224 It implicates the state’s interest in the safe and efficient development of its

natural resources and the local government’s interest in regulating land uses to protect the public

from harm to property values, health, and the environment.225 In matters of mixed state and local

concern, states retain authority over local governments, even when municipalities enjoy some

degree of independence from the state as a result of “home rule” provisions.226 However, the

216

Earthworks Petition at 7.

Id.

218

Id. at 7-8.

219

See, e.g., Water Pollution from Shale Wells Is Major Concern for Pennsylvania Homeowners – Study, E&E News

(November 8, 2012), http://www.eenews.net/energywire/2012/11/08/8.

220

Id.

221

E.g., City of Longmont, Colorado, Ordinance O-2012-25, Amending Chapters 15.04, 15.05, 15.07, 15.10 and

Appendix B of Title 15 of the Longmont Municipal Code Regarding Oil and Gas Well Operations and Facilities (July

24, 2012), http://www.ci.longmont.co.us/pwwu/oil_gas/documents/CA_20120724_125237.pdf.

222

Id. at 3 (stating, with some exceptions, that “City oil and gas well permits may be issued for sites within the City

excluding oil and gas well surface operations and facilities in residential zoning districts.”).

223

Id. at 26 (“The operator shall make reasonable efforts to minimize methane emissions by using all feasible ‘green

completion’ techniques ... and the installation of ‘low-bleed’ pneumatic instrumentation and closed loop systems.”).

224

See, e.g., Robinson Twp. v. Commonwealth, 52 A.3d 463, 483 (Pa. Commw. Ct. 2012).

225

Id.

226

See, e.g., Webb v. City of Black Hawk, 295 P.3d 480, 486 (Colo. 2013) (“For matters that involve mixed state and

local concerns, a home-rule regulation may coexist with a state regulation only as long as there is no conflict. However,

in the event of a conflict, the state statute supersedes the conflicting local regulation to the extent of the conflict.”)

(citations omitted).

217

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Pennsylvania Supreme Court held that the state could not preempt municipal zoning restrictions

when it would violate guarantees contained in the state’s constitution.227

The question of state preemption of municipal land use and zoning powers arises when both state

and local governments seek to regulate oil and gas production. Although the doctrine of

preemption may differ among the states, most jurisdictions recognize three types of preemption:

(1) express preemption, in which the express language of the state statute or regulation shows that

the state intended to preempt all local control over regulation of a particular subject matter; (2)

occupation of the field, in which the state’s regulatory scheme is so comprehensive that it leaves

the locality no room in which to regulate; and (3) conflict preemption, in which a local law is

preempted to the extent that it conflicts with the application of the state law.228

State Court Cases

When a state law expressly preempts requirements imposed on oil and gas operations by

localities, state courts have engaged in statutory interpretation to determine the scope of the

preemption.229 For example, in 2014 the New York Court of Appeals issued a decision finding

that zoning restrictions enacted by two municipalities did not conflict with the state’s mineral

resource laws.230 The municipalities claimed that the zoning restrictions were valid exercises of

the state’s Home Rule law, which empowers local governments to pass laws for the “protection

and enhancement of [their] physical and visual environment” and for the “government,

protection, order, conduct, safety, health and well-being of persons or property therein,”231 and

that their exercise of this authority to restrict certain drilling practices was not preempted by the

state’s oil and gas law.232 The court agreed, finding that the preemption language in the state oil

and gas law limited “only local laws that purport to regulate the actual operations of oil and gas

activities, not zoning ordinances that restrict or prohibit certain land uses within town

boundaries.”233 In the court’s opinion, the new zoning restrictions “are directed at regulating land

use generally and do not attempt to govern the details, procedures or operations of the oil and gas

industries.” As a result the court found that the local zoning restriction did not preempt the state’s

oil and gas laws.234

In the case of Robinson Township v. Commonwealth, a Pennsylvania appeals court considered a

state law (Act 13) that expressly preempted local zoning laws. The court held that towns’

substantive due process rights were violated by the state when Pennsylvania passed a law that

required local governments to allow certain oil and gas facilities in all of their zoning districts,

subject only to minor limitations such as setback requirements.235 Pennsylvania had argued that

the law would advance the commonwealth’s legitimate interest in the safe and efficient

228

E.g., Bd. of County Comm’rs of La Plata County v. Bowen/Edwards Assocs., Inc., 830 P.2d 1045, 1056-57 (Colo.

1992).

229

Cooperstown Holstein Corp. v. Town of Middlefield, 943 N.Y.S.2d 722, 724 (N.Y. Sup. Ct. 2012); Anschutz

Exploration Corp. v. Town of Dryden, 940 N.Y.S.2d 458, 466 (N.Y. Sup. Ct. 2012).

230

Wallach v. Town of Dryden, 23 N.Y.3d 728, 739 (June 30, 2014).

231

N.Y. CLS Mun. Home Rule §10.

Wallach, 2014 NY LEXIS at *5, *7.

233

Id. at *17.

234

Id. at *35.

235

Robinson Twp. v. Commonwealth, 52 A.3d 463, 485 (Pa. Commw. Ct. 2012).

232

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development of its oil and gas resources by eliminating differences in local zoning ordinances

that had burdened the industry and its investors with expense and uncertainty.236 However, the

court held that this mandate was irrational and an improper exercise of the state’s police power

because it allowed incompatible uses in zoning districts, and thus denied the town’s substantive

due process under the state constitution.237 The Pennsylvania Supreme Court subsequently

affirmed the appeals court’s holding that provisions of Act 13 preempting certain municipal

zoning restrictions on oil and gas facilities were invalid under the Pennsylvania constitution.238

A West Virginia case illustrates the doctrine of field preemption in the oil and gas context.239 In

Northeast Natural Energy, LLC v. City of Morgantown, a state court held that state law left no

room for local regulation of oil and gas development and production.240

With regard to conflict preemption, state courts have considered whether the local requirement

interferes with the state’s regulatory scheme governing oil and gas development so as to result in

an “operational conflict” with the state’s objectives.241 Courts considering whether a particular

local regulation is preempted under this test generally evaluate each requirement imposed by the

regulation on a case-by-case basis to determine whether there is a conflict.242 In some instances,

courts must examine not only what the local regulation requires on its face but also how the

regulation is applied in practice by the local government.243 Under the operational conflicts test,

the Colorado Supreme Court held that state law preempted a home rule city’s total ban on oil and

gas drilling.244 In July 2014, a Colorado district court held that state law preempted the city of

Longmont’s ban on hydraulic fracturing, stating that, “The operational conflict in this case is

obvious. The [Colorado Oil and Gas Conservation] Commission permits hydraulic fracturing and

Longmont prohibits it.”245

236

Id. at 483.

Id. at 485.

238

Robinson Township v. Commonwealth, 83 A.3d 901, 985 (Pa. 2013). Three of the justices in the majority held that

the provision violated the state constitution’s Environmental Rights Amendment because it was “incompatible with the

Commonwealth’s duty as trustee of Pennsylvania’s public natural resources.” Id. The other justice in the majority

concurred but would have grounded the decision in the Act 13 provision’s violation of substantive due process

guarantees. Id. at 1001.

239

Order at 6, Ne. Natural Energy, LLC, v. City of Morgantown, No.11-C-411 (W. Va. Cir. Ct. Monongalia County,

2011).

240

Id. at 9; Order Granting Plaintiff’s Motion for Summary Judgment on First Claim for Relief at 7, No. 13CV31385,

Colorado Oil and Gas Association v. City of Fort Collins (Colo. Dist. Ct. Larimer County, Aug. 7, 2014) (“The Court

finds that the City’s Ordinance banning all hydraulic fracturing for five years is impliedly preempted by the [Colorado

Oil and Gas Conservation Act].”).

241

Bd. of County Comm’rs of La Plata County v. Bowen/Edwards Assocs., Inc., 830 P.2d 1045, 1059 (Colo. 1992).

The Colorado cases outlining the operational conflict test were decided before the widespread use of hydraulic

fracturing in combination with horizontal drilling, and thus it is unclear whether the Colorado Supreme Court would

issue similar decisions today. See Jeff Overley, Oil And Gas Group Sues Colorado Town To Kill Fracking Ban,

Law360 (December 18, 2012).

242

Bowen/Edwards at 1060.

243

Id.

244

Voss v. Lundvall Bros., Inc., 830 P.2d 1061, 1062 (Colo. 1992).

245

Order Granting Motions for Summary Judgment at 14, No. 13CV63, Colorado Oil and Gas Association v. City of

Longmont (Colo. Dist. Ct. Boulder County, July 24, 2014).

237

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Alternatives to Preemption

Some states have tried to use alternative methods of accommodating joint state and local

regulatory authority over oil and gas operations. Colorado offers one example. In a February 2012

executive order, Colorado Governor John Hickenlooper wrote that “proving operational conflict

is an adversarial, cumbersome, time consuming, and expensive process.”246 The governor created

a task force to consider how local governments could coordinate their regulatory efforts with the

state to avoid litigation.247 In April 2012, the task force issued a letter in which it wrote that its

members had “determined that drawing bright lines between state and local jurisdictional

authority was neither realistic nor productive.”248 Members of the task force recommended that

local governments enter into memoranda of understanding with operators and intergovernmental

agreements with the Colorado Oil and Gas Conservation Commission (COGCC) to address local

concerns.249 The task force also suggested that the local governments designate a representative to

provide input to operators and the COGCC during the permitting process.250

State Tort Law

Owners of property located near oil and gas operations have brought common law tort claims

against companies that operate oil and gas wells and related infrastructure.251 Plaintiffs have

claimed that damages have occurred as a result of hydraulic fracturing and related oil and gas

operations, including contamination of land from drilling waste placed into pits on the plaintiffs’

properties;252 noise and air pollution from natural gas compressor stations;253 contamination of

water supplies;254 damage to a house allegedly caused by vibrations from nearby drilling

activity;255 and personal injury.256 Common law causes of action brought under state tort law have

included claims for nuisance, trespass, negligence, and strict liability, among others.257 Plaintiffs

have sought monetary and, in some cases, injunctive relief, including remediation of

contaminated property and medical monitoring.258

Often in these cases, some of the damages are alleged to have occurred underground or in the air

above a plaintiff’s property. As a result, plaintiffs may have difficulty demonstrating that the

246

John W. Hickenlooper, Executive Order 2012-002, Creating the Task Force on Cooperative Strategies Regarding

State and Local Regulation of Oil and Gas Development (February 29, 2012).

247

Id.

248

Recommendations from the Task Force Established by Executive Order 2012-002 Regarding Mechanisms to Work

Collaboratively and Coordinate State and Local Oil and Gas Regulatory Structures (April 18, 2012).

249

Task Force on Cooperative Strategies Regarding State and Local Regulation of Oil and Gas Development: Protocols

Recommendations 1-2.

250

Id.

251

Tucker v. Sw. Energy Co., 2012 U.S. Dist. LEXIS 20697, at *4 (E.D. Ark. Feb. 17, 2012); Ginardi v. Frontier Gas

Servs. LLC, 2011 U.S. Dist. LEXIS 89054, at *2 (E.D. Ark. Aug. 10, 2011).

252

Teel v. Chesapeake Appalachia, LLC, 906 F. Supp.2d 519,520 (N.D. W.Va. 2012).(N.D. W. Va. October 25, 2012).

253

Ginardi, 2011 U.S. Dist. LEXIS 89054, at *2.

254

Tucker, 2012 U.S. Dist. LEXIS 20697, at *4; Berish v. Sw. Energy Prod. Co., 763 F. Supp. 2d 702, 704 (M.D. Pa.

2011).

255

Hiser v. XTO Energy Inc., 2012 U.S. Dist. LEXIS 114084, at *1 (E.D. Ark. Aug. 14, 2012).

256

Kamuck v. Shell Energy Holdings GP, LLC, 2012 U.S. Dist. LEXIS 125566, at *5 (M.D. Pa. Sept.r 5, 2012).

257

E.g., Teel, 906 F.Supp.2d at 520.

258

E.g., id.; Fiorentino v. Cabot Oil & Gas Corp., 750 F. Supp. 2d 506, 510 (M.D. Pa. 2010).

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activities of the defendants caused them harm.259 In some cases, defendants have requested that

courts enter modified case management orders (MCMOs) requiring plaintiffs to specifically make

a prima facie showing of exposure, injury, and causation prior to the full discovery process by

submitting expert opinions regarding the nature of the substances to which the plaintiffs were

allegedly exposed; allowing access to the plaintiffs’ medical records; and providing other

supporting data.260 In Colorado, defendants initially succeeded in having one case dismissed after

entry of such an order because the plaintiffs failed to “produce sufficient information and expert

opinions upon which to establish the prima facie elements of their claims.”261 However, a

Colorado appeals court later reversed the trial court’s entry of the order.262 In some cases courts

have declined to enter MCMOs when there are a limited number of parties to the litigation and

the claims are relatively simple.263

One question that arises when a court considers whether defendants are subject to strict liability

for their operations is whether hydraulic fracturing and related oil and gas production activities

are abnormally dangerous as a matter of law. Section 519 of the Restatement (Second) of Torts

states that “[o]ne who carries on an abnormally dangerous activity is subject to liability for harm

... of another resulting from the activity, although he has exercised the utmost care to prevent the

harm.”264 In determining whether an activity is abnormally dangerous, courts generally consider

six factors:

(a) existence of a high degree of risk of some harm to the person, land or chattels of

others;

(b) likelihood that the harm that results from it will be great;

(d) extent to which the activity is not a matter of common usage;

(e) inappropriateness of the activity to the place where it is carried on; and

(f) extent to which its value to the community is outweighed by its dangerous

attributes.265

It appears that few courts have considered the issue. In an April 2014 summary judgment order, a

federal district court judge wrote that “based on an analysis of the six factors set forth in the

Restatement (Second) of Torts ... hydraulic fracturing does not legally qualify as an ultra-

259

E.g., Tucker, 2012 U.S. Dist. LEXIS 20697, at *6-7 (“Missing are particular facts about particular fracking

operations by particular fracking companies using particular substances that allegedly caused the Berrys’ air problems

and the Tuckers’ water problems. General statements about the many dangerous substances used in fracking, and

conclusory statements about the migration of those substances will not suffice.”).

260

Roth v. Cabot Oil & Gas Corp., 287 F.R.D. 293, 295 (M.D. Pa. 2012); Kamuck, 2012 U.S. Dist. LEXIS 125566, at

*1-2; Order Re: Defendants’ Motion to Dismiss or, in the Alternative, for Summary Judgment at 2-3, Strudley v.

Antero Resources Corp., No. 2011CV2218 (May 9, 2012). These orders are commonly referred to as “Lone Pine”

orders. See Lore v. Lone Pine Corp., 1986 N.J. Super. LEXIS 1626 (N.J. Super. Ct. Law Div. November 18, 1986).

261

Order Re: Defendants’ Motion to Dismiss or, in the Alternative, for Summary Judgment at 3, Strudley v. Antero

Resources Corp., No. 2011CV2218 (May 9, 2012).

262

Strudley v. Antero Res. Corp., 2013 Colo. App. LEXIS 1090, *30 (Colo. App. 2013). In April 2014, the Colorado

Supreme Court agreed to hear the defendants’ appeal of the intermediate court’s decision regarding the MCMO. Antero

Res. Corp. v. Strudley, 2014 Colo. LEXIS 239, *1 (Colo. April 7, 2014).

263

See, e.g., Roth, 287 F.R.D. at 295.

264

Restatement (Second) of Torts §519 (1977).

265

Id. §§519-20.

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hazardous activity giving rise to strict tort liability.”266 In another case, a court speculated that it

may be difficult for plaintiffs to meet factors (d), (e), and (f) in the Restatement definition at the

summary judgment stage.267

With respect to trespass claims, the Texas Supreme Court considered whether the subsurface

hydraulic fracturing of a natural gas well that extended into an adjacent property was a trespass

“for which the value of gas drained as a result may be recovered as damages.”268 The court held

that such damages could not be recovered because of the rule of capture, which “gives a mineral

rights owner title to the oil and gas produced from a lawful well bottomed on the property, even if

the oil and gas flowed to the well from beneath another owner’s tract.”269 In another case,

plaintiffs argued that the defendant committed a trespass when it engaged in acts that were not

necessary to the extraction of minerals on the plaintiff’s surface property.270 Plaintiffs have also

argued that emissions of air pollution over their land constitute a trespass.271

Hydraulic Fracturing on Federal Lands

As discussed previously, regulation of practices associated with oil and gas exploration and

production is primarily left to the states and municipalities that have overseen the practice for

decades. Federal regulation of these practices is usually limited to the realm of environmental

impacts. This, however, is not the case when it comes to oil and gas exploration and production

on federal lands. The Bureau of Land Management (BLM), an agency within the Department of

the Interior, oversees leasing and permitting for oil and gas on federal lands.

BLM Final Rule

On March 26, 2015, BLM promulgated a hydraulic fracturing rule applicable to oil and gas

operations on federal and Indian lands.272 However, the final rule was set aside by the U.S.

District Court for the District of Wyoming, and this decision is currently under appeal (see

below). The rule revised BLM’s oil and gas rules related to hydraulic fracturing, which were

promulgated in 1982 and last revised in 1988, before the widespread use of hydraulic fracturing

and horizontal drilling. BLM estimated that the rule would affect roughly 2,800 hydraulic

fracturing operations each year; however, based on previous levels of activity on federal lands,

the rule could affect as many as 3,800 operations annually, and total compliance costs could reach

$45 million annually.273

266

Order at 1-2 & n.2, No. 3:09-cv-2284, Ely v. Cabot Oil & Gas Corp. (M.D. Pa. April 23, 2014). The district court

judge adopted the report and recommendation of the magistrate judge and granted summary judgment to the defendants

on plaintiffs’ Pennsylvania law strict liability claim. Id.

267

Berish v. Sw. Energy Prod. Co., 763 F. Supp. 2d 702, 706 (M.D. Pa. 2011).

268

Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1, 4 (Tex. 2008).

269

Id. at 12-13.

270

Teel v. Chesapeake Appalachia, LLC, 906 F. Supp.2d 519, 520-21 (N.D. W.Va. 2012).(N.D. W. Va. October 25,

2012); see also Whiteman v. Chesapeake Appalachia, LLC, 729 F.3d 381, 394 (4th Cir. 2013) (rejecting a similar

trespass claim).

271

Tucker v. Sw. Energy Co., 2012 U.S. Dist. LEXIS 20697, at *10-11 (E.D. Ark. Feb. 17, 2012); see also Restatement

(Second) of Torts §158 cmt. i (1977).

272

Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands: Final Rule, 80 Fed Reg. 16,128 (Mar. 26, 2015).

273

Id. at 16195. BLM estimates that compliance could cost $11,400 per hydraulic fracturing operation (roughly 0.13 to

0.21% of the cost of drilling a well).

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The rule would require operators that plan to employ fracking as part of an oil or natural gas

drilling operation on federal or Indian land to document to BLM compliance with the following

requirements:



Submit a plan with detailed information about the proposed operation, including

wellbore geology, the location of faults and fractures, the depths of all usable

water, estimated volume of fluid to be used, and estimated direction and length of

fractures;

Design and implement a casing and cementing program that follows best

practices and meets performance standards to protect and isolate usable water,

monitor the cementing operations during well construction, and take remedial

action if there are indications that the cementing is inadequate;

Perform a successful Mechanical Integrity Test prior to the fracking operation;

Monitor well pressure during the fracking operation and cease operations if it

exceeds 500 pounds per square inch;

Manage the recovered “flowback” fluids in above-ground storage tanks that meet

certain specifications; and

Disclose the chemicals used in the fracking operation to the BLM and to the

public (with limited exceptions for trade secrets as demonstrated through an

affidavit).274

The Final Rule also would authorize states and tribes to work with BLM to craft variances from

specific regulatory provisions that would allow compliance with state or tribal requirements to be

accepted as compliance with the BLM rule if the state or tribal provision is at least as protective

as the pertinent BLM provision.275

Final Rule Set Aside in Wyoming v U.S. Dep’t of the Interior

After publication of the Final Rule, a number of states and organizations brought an action in the

U.S. District Court for the District of Wyoming seeking to enjoin its enforcement. These

petitioners argued that BLM lacked statutory authority to regulate hydraulic fracturing, citing the

2005 amendments to the SDWA discussed above as evidence of congressional intent to exclude

hydraulic fracturing from federal oversight unless diesel fuels are involved.276 The court found

that the petitioners had demonstrated the likelihood of success on the merits, and thus enjoined

enforcement of the BLM Final Rule.277 Nine months later the court ruled on the merits and set

aside the BLM Final Rule.278

The federal government appealed the decision to the U.S. Court of Appeals for the Tenth

Circuit.279 The government will likely argue that its broad authority to regulate activities on

274

Id. at 16,130-31.

Id. at 16,130.

276

Wyoming v U.S. Dept. of the Interior, 136 F.Supp. 1317 (D. Wyo. 2015).

277

Id.

278

Wyoming v U.S. Dept. of the Interior, Nos. 2:15-CV-043-SWS and 2:15-CV-041-SWS, 2016 WL 3509415 (D.

Wyo. June 21, 2016).

279

Notice of Appeal, Wyoming v U.S. Dep’t of the Interior, (D. Wyo. 2016) (No. 15-Cv-43-SWS).

275

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federal lands under the Federal Land Policy and Management Act,280 including the power to “take

any action necessary to prevent unnecessary or undue degradation of the lands,”281 provides

sufficient basis for the promulgation of the BLM Final Rule. The government also will likely cite

its authority under Section 226(g) of the Mineral Leasing Act to “regulate all surface-disturbing

activities conducted pursuant to any lease issued under this chapter.”282 The Tenth Circuit’s

decision on this matter will set an important precedent with respect to the federal government’s

ability to regulate hydraulic fracturing and potentially other environmental concerns related to oil

and natural gas exploration and production on federal lands.

BLM Venting and Flaring Rule

On February 8, 2016, the BLM proposed a rule to update standards to reduce venting and flaring

from oil and gas production activities on onshore federal and Indian leases.283 The proposal would

clarify when produced gas lost through venting, flaring, or leaks is subject to royalties and would

replace provisions governing venting, flaring, and royalty-free use of gas issued in 1980. The

proposed rule would limit natural gas venting to specified circumstances and also limit the rate of

routine flaring of natural gas associated with oil well development. BLM expects to issue a final

venting and flaring rule in late 2016.284

Legislation in the 114th Congress

In the 114th Congress, several bills propose to expand federal regulation of hydraulic fracturing

activities, while others would limit federal involvement. This section discusses some of this

legislation.

The Fracturing Responsibility and Awareness of Chemicals Act of 2015 (FRAC Act) has been

introduced in the House (H.R. 1482) and the Senate (S. 785). The bills would amend the SDWA

to (1) require disclosure of the chemicals used in the fracturing process, and (2) repeal the

hydraulic fracturing exemption established in EPAct 2005, and amend the term “underground

injection” to include the injection of fluids used in hydraulic fracturing operations, thus

authorizing EPA to regulate this process under the SDWA. Additionally, S. 785 would authorize

states to seek primary enforcement authority for hydraulic fracturing operations, regardless of

whether the state had obtained primacy for other types of UIC wells, including Class II wells.

The Safe Hydration is An American Right in Energy Development Act of 2015 (H.R. 1515) also

would amend the SDWA to create a new prohibition on fracking unless the party conducting the

fracking operations agrees to comply with new testing and data reporting requirements.

280

43 U.S.C, §§1701 et seq.

43 U.S.C, §1732.

282

30 U.S.C, §226(g).

283

BLM, “Waste Prevention, Production Subject to Royalties, and Resource Conservation: Proposed Rule,” 81 Fed.

Reg. 6616, Feb. 8, 2016. Venting is the release of natural gas (largely methane) into the air without being burned.

Flaring is the burning of natural gas, with the main byproduct being carbon dioxide. Flaring is preferred to venting for

safety reasons but also because methane is several times more potent than carbon dioxide as a greenhouse gas (although

more short-lived in the atmosphere). Flaring also reduces emissions of ozone-forming pollutants compared to venting.

284

Office of Management and Budget, Unified Regulatory Agenda, BLM, "Waste Prevention, Production Subject to

Royalties, and Resource Conservation,” 1004-AE14,

http://www.reginfo.gov/public/do/eAgendaViewRule?pubId=201604&RIN=1004-AE14.

281

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Legislation also has been introduced to require baseline and follow-up testing of potable

groundwater in the vicinity of hydraulic fracturing operations. H.R. 1515, the Safe Hydration is

an American Right in Energy Development Act of 2015, would amend the SDWA to prohibit

hydraulic fracturing unless the person proposing to conduct the fracturing operations agreed to

testing and reporting requirements regarding underground sources of drinking water. H.R. 1515

would require testing prior to, during, and after hydraulic fracturing operations. Testing would be

required for any substance EPA determines would indicate damage associated with hydraulic

fracturing operations. The bill also would require EPA to post on its website all test results,

searchable by zip code.

H.R. 1647 and S. 15, the Protecting States’ Rights to Promote American Energy Security Act,

would amend the Mineral Leasing Act285 to prohibit the Department of the Interior from

enforcing any federal regulation, guidance, or permit requirement regarding hydraulic fracturing

relating to oil, gas, or geothermal production activities on or under any land in any state that has

regulations, guidance, or permit requirements for hydraulic fracturing. Although this language is

broadly applicable to any federal regulation, guidance, and permit requirements “regarding

hydraulic fracturing,” the prohibition on enforcement applies only to the Department of the

Interior, and therefore would presumably impact only hydraulic fracturing operations on lands

managed by the department. The bill also would require the Department of the Interior to defer to

state regulations, permitting, and guidance for all activities related to hydraulic fracturing relating

to oil, gas, or geothermal production activities on federal land regardless of whether those rules

were duplicative, more or less restrictive, or did not meet federal guidelines. The House version

of the bill also would direct the Comptroller General to conduct a study “examining the economic

benefits of domestic shale oil and gas production resulting from the process of hydraulic

fracturing.”286 Other legislation has also been introduced in the 114th Congress to limit the

authority of the Department of the Interior to regulate hydraulic fracturing on federal and Indian

lands.287

Conclusion

Environmental statutes enforced by EPA contain several key exemptions for hydraulic fracturing

and related oil and gas production activities. For example, an amendment to the SDWA passed as

a part of the Energy Policy Act of 2005 clarified that the underground injection control

requirements found in the SDWA do not apply to hydraulic fracturing, although the exclusion

does not extend to the use of diesel fuel in hydraulic fracturing operations.288 In addition, drilling

fluids, produced waters, and other wastes associated with the exploration, development, or

production of crude oil, natural gas, or geothermal energy are exempt from regulation as

hazardous wastes under Subtitle C of RCRA.289 Under EPCRA, facilities used by the oil and gas

extraction industry are generally not included in the industry codes required to report under the

Toxics Release Inventory (TRI).

285

30 U.S.C. §§181 et seq.

H.R. 1647 §3.

287

See. e.g., H.R. 538 at §9 (providing that any Interior rules related to hydraulic fracturing do not apply on “land held

in trust for Indians or on restricted Indian land”), H.R. 2822 at §439 (appropriations legislation barring use of funds to

administer the BLM Final Rule on hydraulic fracturing on federal lands discussed above).

288

P.L. 109-58 at §322.

289

Solid Waste Disposal Act Amendments of 1980, P.L. 96-482, §7, 42 U.S.C. §6921(b)(2)(A).

286

Congressional Research Service

Hydraulic Fracturing: Selected Legal Issues

Environmental groups have filed petitions seeking regulation of hydraulic fracturing and related

activities under various environmental laws enforced by EPA. In September 2010, an

environmental advocacy group filed a petition seeking to have EPA regulate drilling fluids,

produced waters, and other wastes associated with the exploration, development, or production of

crude oil, natural gas, or geothermal energy as hazardous waste under Subtitle C of RCRA.290 In

August 2011, environmental advocacy organizations petitioned EPA to promulgate rules under

Section 4 and Section 8 of TSCA for chemical substances and mixtures used in oil and gas

exploration or production.291 In October 2012, several environmental advocacy organizations

asked EPA to require the oil and gas extraction industry to report the toxic chemicals it releases

under the TRI program.292

Regulation of hydraulic fracturing by local governments has raised questions about state

preemption of municipal land use and zoning powers. Courts in a few states have ruled that local

governments may regulate where drilling occurs but not how it occurs.293 In addition, owners of

property located near oil and gas operations have brought common law state tort claims against

operators, including claims for negligence, strict liability, nuisance, and trespass to land.294

Although this litigation is still in its early stages, it appears that courts have already faced

questions about causation; whether hydraulic fracturing is an abnormally dangerous activity; and

whether hydraulic fracturing may constitute a subsurface trespass to land. A recent federal district

court decision invalidated BLM’s adoption of safety and disclosure requirements for hydraulic

fracturing on federal lands, although an appeal of that decision is pending.

Author Contact Information

(name redacted)

Legislative Attorney

[redacted]@crs.loc.gov

, 7-....

(name redacted)

Specialist in Environmental Policy

[redacted]@crs.loc.gov , 7-....

(name redacted)

Legislative Attorney

[redacted]@crs.loc.gov, 7-....

290

Natural Resources Defense Council, Re: 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 1 (September 8, 2010), http://docs.nrdc.org/energy/

files/ene_10091301a.pdf.

291

Earthjustice, Citizen Petition Under Toxic Substances Control Act Regarding the Chemical Substances and

Mixtures Used in Oil and Gas Exploration or Production 1, 22, http://earthjustice.org/sites/default/files/

fracking_petition.pdf.

292

Earthworks, Petition to Add the Oil and Gas Extraction Industry, Standard Industrial Classification Code 13, to the

List of Facilities Required to Report under the Toxics Release Inventory 1, http://www.earthworksaction.org/library/

detail/petition_to_add_oil_gas_extraction_to_TRI.

293

See the discussion above under “State Preemption of Municipal Land Use and Zoning Powers.”

294

See the discussion above under “State Tort Law.”

Congressional Research Service

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