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STRATA WORKING PAPER
Groundwater Regulations and Hydraulic Fracturing: Reporting Water Use in the Permian
JesseBackstrom1
PhDCandidate,Dept.ofAgriculturalEconomicsTexasA&MUniversity600JohnKimbroughBlvdCollegeStation,TX77843,USA.
Released:February2018
LastMajorRevisions:January2018
Copyright2018byJesseBackstrom.Allrightsreserved.Readersmaymakeverbatimcopiesofthisdocumentfornon-commercialpurposesbyanymeans,providedthatthiscopyrightnoticeappearsonallsuchcopies.
1 I would also like to thank Jake Cottle, a master’s student in economics at Utah State University, for his help compiling and writing an excellent outline of regulations, jurisdictions, and other legal information pertaining to groundwater law in Texas.
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Abstract
The Permian Basin in west Texas is located in a primarily semi-arid to arid environment. In 2011, it was
estimated that the hydraulic fracturing occurring in this region relied solely on groundwater with between
0-2% of the water volume for fractures coming from recycled hydraulic fracturing wastewater (Nicot et al.
2012). Using a unique data set, our analysis over the time period after that (2012-2016) indicated similar
trends for water types used in 26,914 hydraulically fractured wells in 46 counties in the Permian region.
Over this period of time the vertical depths and lateral lengths of new hydraulically fractured wells also
increased, meaning that groundwater demands (which can be any combination of fresh, brackish, and or
produced water) per completed well have become significantly greater in a relatively scarce water region
(Peters 2017). With these trends projected to continue, it is important to understand the localized effects
of potentially greater freshwater withdrawals in the region and therefore examine the transparency of
water use reporting in the industry. In this paper we outline existing groundwater management and
regulation strategies for the state of Texas, which delegates management to local entities such as
groundwater conservation districts, and analyze spillovers of these localized groundwater regulations on
hydraulic fracturing activities. Our preliminary analysis provides some descriptive evidence that in areas
where a localized groundwater management plan exists, hydraulic fracturing operators are more likely to
report less detailed information on water use per stimulated well. A similar relationship was found as less
detailed information on water use was reported for a marginal increase in total water volumes used in
hydraulic fracturing stimulations. These findings are important for groundwater management as they
provide some information on the reporting tendencies of hydraulic fracturing operators of wells located in
groundwater conservations districts in Texas, and allude to several policy options aimed to help make
water use reporting more transparent.
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Introduction Hydraulic fracturing activity has increased rapidly in the U.S. over the last decade, where the Permian
Basin in west Texas has seen some of the largest growth. A growing literature in economics has studied
many of the impacts of the “shale boom,” which have included effects on: the housing market (e.g.
Muehlenbachs et al. 2015; He et al.2017); employment, wage, and tax and royalty revenues (e.g. Feyrer et
al. 2017); crime rates (e.g. James and Smith 2017); health (e.g. Currie et al. 2017); increased truck traffic
and accidents (e.g. Muehlenbachs and Krupnick 2013; Rahm et al. 2015; and Muehlenbachs et al. 2017);
and others such as attitudes and risk perceptions toward hydraulic fracturing (e.g. Schafft et al. 2013;
Boudet et al. 2014; and Boudet et al. 2016) and cost-benefit studies (e.g. Fitzgerald 2013; Jackson et al.
2014; and Mason et al. 2015). Aside from these more ‘general’ economic studies, there is also an
increasingly expansive literature on the localized environmental effects of hydraulic fracturing. These
include many qualitative review papers on environmental risks associated with shale development (e.g.
Krupnick and Gordon 2015), as well as studies that are more specific to effects on: air quality and
greenhouse gas emissions (e.g. Howarth et al. 2011; Knittel et al. 2015; and Holladay and LaRiviere
2017); induced seismic activity associated with wastewater disposal (Ellsworth 2013); and agricultural
production (e.g. Hitaj et al. 2014; Farah 2017).
A large volume of water in a short period of time is needed to hydraulically fracture (or stimulate) a well
drilled for hydrocarbon production from shale. In our sample, a median of 11,779,194 gallons of water
was used per well stimulation in 2016, which is the equivalent of supplying ~73,000 average 2-person
U.S. households with water for a day (USGS 2016). Although informative to understanding general
trends in water use by the hydraulic fracturing industry and identifying potential externalities, previous
economic studies of the effects of hydraulic fracturing on local water quality and availability have generally
come from a qualitative narrative (e.g. Burnett 2013; Muehlenbachs and Olmstead 2014; Olmstead and
Richardson 2014; and Kuwayama et al. 2015). Outside of a study on the effects of hydraulic fracturing
activity on surface water quality by Olmstead et al. (2013), the only quantitative studies on these issues
(that we are aware of) have come from a purely scientific perspective (e.g. Nicot 2012; Nicot and Scanlon
2012; Mitchell et al. 2013; Scanlon et al. 2013; Nicot et al. 2014; Scanlon et al. 2014a; Scanlon et al.
2014b; Small et al. 2015; Vengosh et al. 2014; Barth-Naftilan et al. 2015; Kondash and Vengosh 2015;
Horner et al. 2016; and Scanlon et al. 2016). Quantitate studies on water quality and availability issues
have largely escaped the economics literature, which we believe is primarily due to data limitations,
among other barriers,
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Another issue in the oil and gas industry that has led to an inability of economists to study water quantity
and availability issues is the relatively poor transparency of water use reported. In Texas for example, it
was not until 2012 hydraulic fracturing operators were mandated by House Bill 33282 to report water and
chemical ingredients in hydraulic fracturing fluids to the FracFocus national chemical registry. Even then,
operators were still not required to report detailed information on the type of water used in well
stimulations, nor the source of that water, which has led to a nontrivial amount of variability in the detail
of reporting by operators. Without clear knowledge on water use, the impacts of withdrawals for
hydraulic fracturing on water resources cannot be studied credibly, which limits the ability to create new
policies aimed at incentivizing alternatives to freshwater. The only studies we are aware of that investigate
how different regulations impact withdrawals took place in the Susquehanna (SRBC 2015) and Ohio
(Braun 2015) River Basins, where surface water is the primary water source for the industry. Although, on
average, these areas might be more water rich, transparency of water use is still important because if many
new wells in a particular area are due to be stimulated and their operators obtain water from the same or a
connected source, there is potential for drawdown. This potential becomes even more pronounced during
drought, the summer months, or if the source is a groundwater aquifer with little or no natural recharge.
In this paper we investigate an issue that, to our knowledge, has yet to be studied in the economics and
natural science literatures. Using a unique data set3 of hydraulically fractured wells, we examine trends in
the volume of water used in well stimulations in the Permian Basin in west Texas from 2012-2016 and
analyze spillovers of localized groundwater management regimes on hydraulic fracturing activities.
Specifically, we investigate how water use reporting by operators of wells located within the jurisdiction of
a groundwater conservation district (GCD) varied relative to water use reporting for wells not located
within a GCD. The impacts of groundwater management on hydraulic fracturing activities are
particularly challenging to tease out because management tends to be local (compared to river basins) and
can vary greatly between management areas (within the Permian Basin there are 29 different management
regimes). We hypothesize that operators of hydraulically fractured wells located in a GCD area might be
more likely to be less detailed in their reporting of water use in order to limit the potential for interaction
with local regulatory authorities and, since freshwater is the cheapest source of water, possibly to prevent
future legislation of water use by leaving less of a paper trail.
2 House Bill 3328, Texas Legislature. September 1, 2011. 3 Data set provided by Primary Vision in Houston, Texas (http://www.pvmic.com/).
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We start by outlining how groundwater is managed in Texas, how it has evolved, and how hydraulic
fracturing has introduced new challenges to a region tasked with the management of scarce groundwater
resources. Next, we explore water use reporting by operators of hydraulically fractured oil and gas wells
within the Permian Basin due to their location in a water scarce region and reliance on groundwater. Our
preliminary analysis provides descriptive evidence that in areas where a localized groundwater
management plan exists, hydraulic fracturing operators are more likely (by about 1.5 percentage points) to
report less detailed information on water use per stimulated well. A similar relationship was found as less
detailed information on water use was more likely to be reported for a marginal increase in total water
volumes used in hydraulic fracturing stimulations, and for horizontally-drilled wells versus vertically-
drilled wells, as the former require more water to stimulate a well. These findings are important for
groundwater management as they provide some information on the reporting tendencies of hydraulic
fracturing operators of wells located in GCDs in Texas, and allude to several policy options aimed to help
make water use reporting more transparent. We believe that relevant policy questions might center on
creating GCDs where none currently exist, and possibly expanding the water use reporting requirements
of House Bill 3328 in order to better understand water sources and types used in hydraulic fracturing
stimulations and incentivize the use of alternatives to freshwater.
Texas Groundwater Institutions Over the past century, Texas groundwater management has evolved and been shaped by court cases aimed
at protecting private property and legislative efforts to conserve and protect Texas's natural resources.
Common Law: Rule of Capture Texas's foundational principle, the rule of capture, traces its origins back to the landmark English case,
Acton v. Blundell (1843). The plaintiff in the case, Acton, argued the water he used for his business was
intercepted and diverted by the defendant. Blundell argued he was within his right to utilize the water he
pumped on his property as he saw fit; regardless of the impact it had on the plaintiff. The Court of
Exchequer Chamber agreed and ruled against the plaintiff. One reason the Court gave for its ruling was
the location and movement of water underground could not be known and therefore, cannot be liable for
something that could not be predicted (Grover and Mann 1991).
In its own landmark decision, Texas adopted the rule of capture (derived from the rule of absolute
ownership) in the case of Houston & Texas Central Railroad Co. v. W.A. East (1904). The railroad
company dug a well on its property to support its operations, which dried up its neighbor's domestic well.
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The neighboring landowner sued the railroad company for damages and the case made its way to the
Texas Supreme Court in 1904. The court had to choose between the rule of capture, which grants
landowners the right to pump and capture whatever water is available beneath their property regardless of
the effects of that pumping on neighboring wells, and the American Rule, also known as the rule of
reasonable use.
The Texas Supreme Court ultimately chose the rule of capture based on two public policy considerations.
First: “Because the existence, origin, movement and course of such waters, and the causes which govern
and direct their movements, are so secret, occult and concealed that an attempt to administer any set of
legal rules in respect to them would be involved in hopeless uncertainty, and would therefore be
practically impossible.” Second: “Because any such recognition of correlative rights would interfere, to the
material detriment of the commonwealth, with drainage of agriculture, mining, the construction of
highways and railroads, with sanitary regulations, building, and the general progress of improvement in
works of embellishment and utility” (Potter 2004). However, for more than a century the Texas Supreme
Court had not made an official decision on whether a landowner owns not only the water that emerges
from the ground, but the water in place underground as well (i.e. ownership before the water is
produced). Finally, on February 24, 2012 in Edwards Aquifer Authority v. Day, the Supreme Court
announced for the first time that under Texas law the ownership of the groundwater in place also belongs
to the owner of the property and is subject to takings (when property owners require compensation for
having their withdrawals capped or reduced), similar to oil and gas, yet it is still unclear what is
considered effective groundwater management and regulatory takings (McCarthy, E.R., and Jackson,
Sjoberg, McCarthy & Townsend LLP 2012 and Texas Water Code Section 36.002).
Groundwater Conservation Districts Many of the Texas Legislature's efforts to conserve its water resources have been on the heels of drought.
The Conservation Amendment to the Texas constitution was no exception as it followed the droughts of
1910 and 1917 (Potter 2004). The amendment declared the natural resources of the State to be public
rights and duties: “The conservation and development of all of the natural resources of this State … and
the preservation and conservation of all such natural resources of the State are each and all hereby
declared public rights and duties; and the Legislature shall pass all such laws as may be appropriate
thereto” (Texas Constitution. Article XVI, § 59). The amendment also authorized the creation of
conservation and reclamation districts: “There may be created within the State of Texas ... conservation
and reclamation districts ... with the authority to exercise such rights, privileges and functions concerning
7
the subject matter of this amendment as may be conferred by law” (Texas Constitution. Article, XVI, §
59).
Groundwater Conservation Districts (GCD) were first created in Texas in 1949 (Texas Water Undated),
and are "charged to manage groundwater by providing for the conservation, protection, recharging, and
prevention of waste of groundwater resources within their jurisdiction" (TCEQ Undated-1). GCDs can
be created by one of four ways: (1) action of the legislature, (2) landowner petition, (3) Texas
Commission on Environmental Quality (TCEQ) on its own motion in a designated Priority
Groundwater Management Area (PGMA), and (4) an alternative to creating a new GCD is to add
territory to an existing district (TCEQ Undated-1). GCDs are legal entities empowered with three
primary legislatively-mandated duties to include: "permitting water wells, developing a comprehensive
management plan, and adopting the necessary rules to implement the management plan" (TCEQ
Undated-1).
In 1985, 1997 and 2001, the Texas Legislature passed new laws aimed at encouraging the development
and establishment of more GCDs (Texas Water Undated). As of January 2018, there are a total of 100
confirmed GCDs and two unconfirmed GCDs (pending election) in the state of Texas (Figure 1). These
conformed GCDs cover 180 of the 254 counties in the state (TCEQ Undated-1).
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Figure 1. Map of Groundwater Conservation Districts in Texas (Source4).
Following a three-year drought, the state created its first historic omnibus water bill, Senate Bill 1 (SB1)
(1997), which consolidated all of the laws governing GCDs into Chapter 36 of the Texas Water Code.
The legislature affirmed the state’s preferred method for groundwater management to be GCDs and
stated they "embody a central premise of this legislation - local control - and represent the idea that those
closest to the resource are those most capable of managing it" (Hubert and Bullock 1999). SB1 increased
GCDs’ statutory authority to manage withdrawals by requiring permits for any new drilled water well,
requiring users to report use and submit statement of purpose when applying for permits, authorized
GCDs to deny out of basin transfers, and exempted certain types of wells from obtaining a permit (e.g.
use for domestic, livestock, and hydrocarbon production). The exemption of water supply wells for oil and
gas production is still largely debated, but has become increasingly important as hydraulic fracturing has
increased in the state and also may not require regulation by a GCD (Hardberger 2016).
4 Texas Commission on Environmental Quality. https://www.tceq.texas.gov/assets/public/permitting/watersupply/groundwater/maps/gcdmap.pdf
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Priority Groundwater Management Areas SB1 moved to treat the state as a whole by setting up regional planning groups and providing data
collection to close data gaps.
Figure 2. Priority Groundwater Management Areas in Texas (Source5)
Priority Groundwater Management Areas (PGMAs) are identified by the TCEQ with assistance from
the Texas Water Development Board (TWDB) as areas that currently have no GCD and will potentially
have "critical problems" within the next fifty years (TCEQ Undated-2). PGMAs were created to "enable
effective management of the state's groundwater resources in areas where critical groundwater problems
exist or may exist in the future" (TCEQ Undated-2). As of January 2017, seven PGMAs have been
designated in Texas and cover all or part of 35 counties (TCEQ and TWDB 2017). Local, legislative, or
TCEQ administrative actions to establish GCDs are still required in four PGMAs. A map of the
PGMAs is provided in Figure 2, above. As outlined in Chapter 35 of the Texas Water Code, the TCEQ
shall call an evidentiary hearing where it will hear testimony from affected persons in the region under
consideration. Once a decision to designate an area to be a PGMA is made, the affected counties must
take one of several actions within two years: (1) join an existing GCD, (2) create one or more GCDs, (3)
or a combination of (1) and (2) depending on the hydrogeology. If affected counties do not take steps in 5 The Hays County RoundUp. http://hayscountyroundup.blogspot.com/2009/11/tceq-report-looks-at-options-to-plug.html
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creating a GCD then the TCEQ will step in and create one or more districts under Chapter 36 of the
Texas Water Code.
In 2001, the legislature passed Senate Bill 2 (SB2) to update and strengthen the initiatives in SB1
(Hardberger 2016). SB2 expanded districts permitting and enforcement powers by authorizing them to
regulate well spacing to minimize interference between wells and set production limits based on tract size
or production capacity by dictating acre-feet per acre or gallons per minute (Hardberger 2016). However,
data issues still remain if oil and gas water supply wells are not subject to frequent reporting (most are
only required to report once each year with an annual volume, according to conversations with Jim
Bradbury), or if oil and gas operators are not subject to more detailed water use reporting (FracFocus
requires operators to report total water volume, but does not require specifying the water source(s) or
type(s) used in each fracture). SB2 also reduced some permitting powers by prohibiting districts from
denying a permit solely on the basis the user planned to export groundwater out of the district; instead, it
authorized them to place an export fee.
Groundwater Management Areas The legislature foresaw issues that may arise due to GCDs potentially sharing the same water source.
This scenario could cause problems if multiple GCDs had different or conflicting management plans.
Therefore, SB2 required TWDB to create Groundwater Management Areas (GMA) that would cover
water boundaries, and cross political borders to establish procedures for joint management across GCDs.
In December of 2002, the TWDB created 16 GMAs that covered the entire state with only the area
encompassing GMA 5 in Western Texas having no GCDs (Figure 3). While originally GMAs were a
good method for getting GCDs to communicate, the legislature in 2005 required GCDs and GMAs to
coordinate and develop desired future conditions (DFC) that would then be converted into modeled
available groundwater (MAG) by the TWDB. DFCs are determined based on what the GMA wants the
resource to look like in the future. The MAG would translate the DFC into an annual amount of water
that could be extracted and over a fifty-year period and still meet the DFC (Hardberger 2016).
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Figure 3. Groundwater Management Areas in Texas. (Source6)
The DFCs and MAGs generated by the GMAs are consolidated at the state level to produce a larger
State Water Plan that would be completed every five years and project over the next fifty years
(Hardberger 2016).
Special Case: Edwards Aquifer Authority The Edwards Aquifer Authority is a direct result of Sierra Club v. Lujan (1991) in which the Sierra Club
filed suit against the U.S. Department of the Interior (DOI) alleging violation of the 1973 Endangered
Species Act (ESA). The Sierra Club cited the DOI was not adequately protecting endangered species in
the Comal and San Marcos Springs and that if unrestricted pumping continued it would constitute a
"taking" as defined by ESA.7 They requested that DOI be required to ensure minimal spring flows to
protect the endangered species. In 1993, the judged ruled in-favor of the Sierra Club and directed the
Texas Water Commission to prepare and submit a plan to ensure spring flow levels. Furthermore, the
judge announced the Texas legislature had to enact a regulatory plan to limit withdrawals from the aquifer
or he would put the aquifer under the federal government's control and create his own plan (Eckhardt
Undated).
6 Panhandle Regional Planning Commission. http://www.theprpc.org/Programs/RegionalH2OPlanning/gma1.html. 7 The term “take” means to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or to attempt to engage in any such conduct (ESA Section 3).
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As ordered, the Texas legislature passed Senate Bill 1477 (Edwards Aquifer Authority Act) four months
after the verdict was rendered (Hardberger 2016). The Edwards Aquifer Authority is authorized under
the same constitutional amendment as others GCDs, but has additional regulatory power and authority
that gives them more control of the water management in the region (Hardberger 2016). The biggest
differences are the firm total pumping cap on the Edwards Aquifer and how permits are allocated.
The legislature created a rubric for permitting based on historic use and gave preference to those who
could show beneficial use from June 1, 1972, through May 31, 1993 (Hardberger 2016). After all historic
use permits were issued, the Edwards Aquifer Authority would then review new applicants, not to exceed
the cap amount. Additional limits could be enforced during times of low water levels and no water was to
be used outside of the district (Hardberger 2016).
Water Use and Management in the Oil and Gas Industry The oil and gas industry has a long history of water use, yet the advent of hydraulic fracturing has made
the amount of water used in the process a new focus due to concerns over both water availability and
quality. While the volume of water used in oil and gas production is relatively small compared to total
water use, Kondash and Vengosh (2015) estimate hydraulic fracturing accounts for 0.04% of total fresh
water use per year, the water use issue is magnified at the local level, where large quantities of water are
needed over short periods of time (days to weeks) to hydraulically fracture a well, as opposed to a constant
withdrawal over time (Nicot and Scanlon 2012). The impacts of large withdrawals over a short period of
time can exacerbate water scarcity, especially in times of drought such as the one in Texas in 2011.
There are many factors affecting the volume of water needed to fracture a well, such as the lateral (or
horizontal) length of wells, geology, and the composition of the hydraulic fracturing fluid. The lateral
length is directly correlated to the amount of water used per well with longer horizontal lengths requiring
greater water volumes. As lateral lengths increase, fracture (water required entering the fractures),
wellbore (space in the wellbore), and total volumes (fracture volume plus wellbore volume plus leakage or
other unintended losses) all increase (U.S. EPA 2015). Geologic characteristics, such as shales, tight
sands, and coalbeds, also influence the amount of water used per well (U.S. EPA 2015). Lastly, hydraulic
fracturing fluid type is another important determinant as some fractures contain higher proportions of
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recycled wastewater8 and others contain non-aqueous substances such as liquid-gas mixtures of nitrogen
or carbon dioxide, both of which reduce the amount of water needed to fracture a well (U.S. EPA 2015).
In a county-level analysis of the intersection between water use (or consumption) and availability by U.S.
EPA (2016c), it was found that large volumes of water used in hydraulic fracturing alone do not
necessarily result in impacts to drinking water resources. Rather, they found that the potential for impacts
depends on both water use and water availability at a given withdrawal point. Where water availability is
low compared to use, hydraulic fracturing withdrawals are more likely to impact drinking water resources
or require curtailments. For example, in Pennsylvania, a water rich state, water withdrawals have been
restricted during summer and drought conditions in the Susquehanna River Basin (SRBC 2015).
Furthermore, groundwater withdrawals exceeding natural recharge rates may lower the water level in
aquifers (particularly for unconfined aquifers, i.e. those aquifers with no connection to surface recharge),
potentially mobilizing contaminants or increasing their concentration. These results suggest that the
potential for impacts exists, and that more local-scale case studies will help to provide details on where
impacts will occur at the local scale.
Water Life Cycle in Hydraulic Fracturing Water consumption is water that, following its use, is removed from the local hydrologic cycle and is
therefore unavailable to other potential users (U.S. EPA 2016c). Hydraulic fracturing water consumption
can occur in a variety of ways such as through evaporation from storage ponds, retention of water in the
geologic formation, or disposal in Underground Injection Control (UIC) Class II injection wells (U.S.
EPA 2016c). Although the stimulation of wells has become more robust to the use of various water types
(e.g. saline water)9, the majority of hydraulic fractures use fresh water because it requires minimal testing
and treatment (U.S. EPA 2016c), and therefore is usually the least cost option. The U.S. EPA (2016c)
outlines five stages in the hydraulic fracturing water cycle. Each stage is defined by an activity involving
water that supports hydraulic fracturing. The stages and activities are explained in Table 1, below.
8 We use “wastewater” as a general term to include both flowback and produced water that may be reused in hydraulic fracturing; we do not distinguish between flowback and produced water except when specifically reported in the literature. 9 Mentioned in a phone conversation with Gabriel Collins, an attorney in Houston, Texas. https://www.bakerinstitute.org/experts/gabe-collins/
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Table 1. The stages and activities in the hydraulic fracturing water cycle (U.S. EPA 2016c). Stage Activity
Water Acquisition The withdrawal of groundwater or surface water to make hydraulic fracturing fluids.
Chemical Mixing The mixing of a base fluid, proppant, and additives at the well site to create hydraulic fracturing fluids.
Well Injection The injection and movement of hydraulic fracturing fluids through the oil and gas production well and
in the targeted rock formation.
Produced Water Handling
The on-site collection and handling of water that returns to the surface after hydraulic fracturing and the transportation of that water for disposal or reuse.
Wastewater Disposal and Reuse
The disposal and reuse of hydraulic fracturing wastewater.
Water Sourcing and Disposal Hydraulic fracturing operators have two primary water problems. The first is locating (or sourcing) water
to hydraulically fracture a well (Carr 2017). To adequately fracture a well, up to 9.7 million gallons of
water can be needed according to a study of U.S. wells over 2000 to 2014 (USGS 2015), depending on
the factors previously mentioned, and the water is needed within a short period of time to ensure
sufficient pressure to fracture and complete the well. Since water is over allocated in Texas, one way that
oil and gas operators obtain water is through water markets, whereby lucrative markets for the sale of
water have been created in regions with hydraulic fracturing, which have not come without effects of their
own. In regions with relatively low water availability, the impacts of multiple wells requiring water
withdrawal in a short time period can lead to rapidly declining groundwater levels, especially during
drought or seasonal times of low water availability. The result can be the drying of domestic wells, such as
cattle wells running dry on the Fasken Oil and Ranch, located in Midland (Dallas News 2014). Stream
capture decline (which can also occur as groundwater levels lower), is another effect that has occurred
when private stock dams ran dry in western North Dakota (Kusnetz 2012). Aside from the direct impacts
on groundwater levels, there is a fear of displacement of local homeowners as water availability decreases,
where other neighbors in the area have fruitlessly drilled water wells and others reported having to haul
water from out of town (Kusnetz 2012). Careful management of water is therefore needed at the local
level, as it is local water availability that is the most sensitive in terms of social welfare.
15
The second problem is arguably the largest, which is the wastewater – both the initial flowback and
produced water – that is pumped from the well with oil and gas and contains many of the salts, minerals,
and other petroleum residues naturally existing in the formation. This water is produced throughout the
life of a well where initially, in the Permian Basin, 252 to 336 gallons (6 to 8 barrels) of water are
produced per gallon of oil (Carr 2017), and the volumes of both produced water and oil decline at
relatively the same rate as the well ages (Kondash and Vengosh 2015). Operators must dispose, treat, or
reuse this wastewater in a safe and responsible manner. In all of Texas, this is usually done via injection
into UIC Class II injection wells (Texas Railroad Commission Undated and Collins 2017). Disposal of
produced water in injection wells however, has been connected to seismic activity in Oklahoma (Walsh
and Zoback 2015). If Permian Basin produced water volumes continue to increase, as is projected to
happen due to increasing hydraulic fracturing activity, the produced water problem will become even
more pronounced.
Water Sales – Informal Markets During peak production in the Bakken region in North Dakota, many landowners invested roughly
$150,000 to build a water depot, from which they pumped and sold water to hydraulic fracturing
operators (Kusnetz 2012). Some landowners earned profits in excess of $25-30 million in a year supplying
water, with several local towns of only few a thousand people following suit and earning $10 million in a
year according to that same article. Although no literature was found on water trading in the Permian
Basin, two attorneys10 mentioned that informal water sales are taking place.
Freshwater is in higher demand due to it being less expensive than recycled wastewater, and the rents
available to landowners for their provision of water have led to a ‘race to pump’ for profit. With more
freshwater provision, a more rapid depletion of an already scarce groundwater source can occur and pose
external costs on other water users in the area due to a need to drill new and deeper water wells. This
common pool resource dilemma appears to be more pronounced in Texas due to its rule of capture law,
especially in areas without GCDs, and making it clear that the price of water is a primary tool that can be
used to manage the types and sources of water being used in well stimulations as increasing the price of
water will reduce amount of water that is used.
10 It was mentioned to us in phone conversations that by taking a drive through the Permian basin, many road signs are visible that advertise water for sale for oil and gas operations.
16
Water Permitting Exemption Although the rule of capture allows landowners to pump as much water as they choose, landowners
located within the reaches of a GCD can be required by that GCD to obtain a drilling permit and report
metering and withdrawal water subject to limits set forth by the GCD (Dowell 2013). Well size is a
primary determinant of the need for a permit, where large well owners can also be subject to user and
export fees by GCDs (Lesikar et al. 2002). Landowners located in an area outside of a GCD (also known
as ‘white areas’) do not face these regulations or restrictions.
A key ruling with respect to the permitting of water wells comes from an exemption in Chapter 36
Section 117(b)(2) of the Texas Water Code: “A district shall provide an exemption from the district
requirement to obtain a permit for drilling a water well used solely to supply water for a rig that is actively
engaged in drilling or exploration operations for an oil or gas well permitted by the Railroad Commission
of Texas provided that the person holding the permit is responsible for drilling and operating the water
well and the water well is located on the same lease or field associated with the drilling rig.” The exemption has
brought questions over how far it reaches, and whether water used for hydraulic fracturing is included in
the statute. In the phone conversation with one of the attorneys, he mentioned that the interpretation of
this exemption is different across GCDs, where its lack of clarity allows opposing views to maneuver
around it. Likewise, he mentioned that no GCD has wanted to be the test case of this exemption, so in
instances of dispute, settlements have typically been made and no cases ever reach the courtroom.
FracFocus After the enactment of House Bill 3328 by the Texas Legislature, the future of hydraulic fracturing in the
state was changed when subchapter S was added to Chapter 91 of the Texas Natural Resources Code.
The new law directed the Texas Railroad Commission (TRC) to adopt new rules requiring the disclosure
of the hydraulic fracturing fluids used in wells for which drilling permits are issued by the TRC on or
after February 1, 2012 (Cavender 2011).
17
Table 2. FracFocus Disclosure Requirements for Texas (Source: House Bill 3328, Texas Legislature)
(1) Operator name (2) Date of completion and hydraulic fracturing treatment(s) (3) County of well (4) API number (5) Well name and number (6) Latitude and longitude of wellhead
(10) Each chemical ingredient used in the hydraulic fracturing treatment(s) of the well that is subject to the requirements of 29 Code of Federal Regulations §1910.1200(g)(2), as provided by the chemical supplier or service company or by the operator, if the operator provides its own chemical ingredients
(7) Total vertical depth of well (8) Total volume of water used in the hydraulic fracturing treatment(s) of the well or the type and total volume of the base fluid used in the treatment (if something other than water) (9) Each additive used in the hydraulic fracturing treatments and the trade name, supplier, and a brief description of the intended use or function of each additive in the hydraulic fracturing treatment(s)
(11) The actual or maximum concentration of each chemical ingredient in percent by mass (12) The CAS number for each chemical ingredient listed, if applicable (13) A supplemental list of all chemicals and their respective CAS numbers, not subject to the requirements of 29 Code of Federal Regulations §1910.1200(g)(2), that were intentionally included in and used for the purpose of creating the hydraulic fracturing treatments for the well
The law required operators to disclose the information in Table 2 to FracFocus.org, which is a national
registry developed by the Groundwater Protection Council and the Interstate Oil and Gas Compact
Commission. Of particular interest to this study are requirements (8), (9), and (11), which detail the
minimum information needed that pertains to water and chemical ingredients in hydraulic fracturing
fluids.
The Permian Basin The Permian Basin in west Texas is located in a primarily semi-arid to arid environment. When a region
with significant water use associated with hydraulic fracturing is combined with low water availability,
drought, and reliance on groundwater sources, there exists a potential to affect the quantity of drinking
water resources (U.S. EPA 2016c). Impacts are likely to be initially realized locally dependent on
hydraulic fracturing activity, aquifer conditions, and other factors such as drought. In a detailed case study
of southern Texas, Scanlon et al. (2014b) observed generally adequate water supplies for hydraulic
fracturing, except in specific locations. Excessive drawdown of local groundwater was found in a small
proportion (~6% of the area) of the Eagle Ford shale play in Texas, another groundwater-stressed region.
They suggested water management, particularly a shift towards brackish water use, could minimize
potential future impacts to freshwater resources, especially since the high brackish water availability in
18
Texas may help offset hydraulic fracturing water demand. Similar or more extreme effects might be
anticipated in the Permian Basin due to its status as the most active for shale oil production.
Figure 4. The Permian Basin (Source11); Groundwater Recharge in Texas (Source12)
Figure 4, above, provides visuals for the Permian Basin and the low groundwater recharge rates in the
area. Of the 46 counties in the Permian Basin with a well completion record in our data set, 29 contain
hydraulically fractured wells that are within a GCD. In Figure 5, below a map of Texas Counties, GCD
areas, and well locations are also shown. The red boundary indicates the wells that are included in this
study. Three of the counties with high intensities of hydraulic fracturing (Midland, Reagan, and Upton)
are not currently managed by a GCD, but a PGMA instead, and are in the early stages of the
development of GCD. The final report for the area was submitted in January. Our focus was to
distinguish the water use reporting of completed wells located in the Permian Basin in areas with a GCD
compared to those without, and assess the effectiveness of existing GCDs.
11 DrillingInfo. https://info.drillinginfo.com/inside-driliinginfos-map-drawers-1-permian-basin/ 12 Texas Aquatic Science. http://texasaquaticscience.org/aquifers-springs-aquatic-science-texas/
19
Figure 5. Texas Counties, GCD areas, and Well Locations (Permian Basin roughly outlined in red)
These findings could have implications with regards to establishing relevant reporting requirements (such
as the water source and type) and jurisdictional authority for new GCDs currently under development.
The next section describes the data set used, followed by the methodologies used and the results.
Data - Primary Vision Proprietary data was provided by Primary Vision (PV), a company based in Houston, Texas, that provides
unique analytical tools and access to data on the use of water, proppant, and chemicals in hydraulic
fracturing. PV constructed this proprietary database by downloading the FracFocus database and
combining it with data from other public sources such as the TRC. The initial data set that was provided
included information on nearly 124,000 hydraulically fractured wells in several states over 2011-2017.
With respect to House Bill 3328, operators are required to report information on the total water volume
and chemical compositions used in well completions as of February, 2012, so we drop well observations
from before that, but include records for January, 2012 (391 observations) only because we believe it to be
reasonable that operators anticipated the reporting required as it was announced in fall, 2011 and may
have reported anyway. We also drop well records from 2017 since the full list of well records is likely
incomplete.
Important variables for our analysis included the location of a well within a GCD or non-GCD area, the
total volume of water used in well stimulation, hydraulic fracturing fluid mass, well orientation
20
(horizontal, directional, or vertical drill), and fixed effects for month of sample. Although few operators
report to FracFocus the proportions of freshwater, recycled wastewater, saltwater, slickwater, and
produced water used to stimulate each well, hydraulic fracture fluid mass was calculated proprietarily by
PV using some of this information from FracFocus but also from other sources that we were not named.
Where sufficient information was unavailable to calculate hydraulic fracturing fluid mass for wells in the
database, PV coded their hydraulic fracturing fluid mass as unknown. PV verified that this in fact meant
that it was not reported by the operator or was unable to be obtained, which is important to our analysis
since it contributes to what we refer to as reporting less water use information relative to more
information.
The arcGIS data on counties13 and GCDs14 in Texas come from the Texas Department of
Transportation and TWDB, and we found that two of the GCDs located in the reaches of the Permian
Basin (Terrell County and Reeves County GCDs), were not confirmed until November, 2012 and
November, 2015, respectively. Since these areas contain well records prior to the establishment of a
GCD, we classify the pre-GCD well records located in these areas as located within a white area instead
of within the jurisdiction of a GCD, which gives us a little bit of variation in the data. Additionally, we
would like to obtain data on lateral lengths the number of stimulations per well, which is available
through DrillingInfo.
Figures 6 and 7, below, illustrate two trends seen in the Permian Basin with respect to the intensity of
hydraulic fracturing and average water use per well over 2012-2016. The orange line in the first chart
shows an increasing number of horizontal and directionally-drilled wells until roughly October of 2014,
and a declining number thereafter. The blue line in this chart shows that the number of vertically-drilled
wells was declining over time. Figure 7 shows that the median reported volume of water used in well
stimulations has increased over the whole time horizon for horizontal and directionally-drilled wells. The
reason for these trends is that when oil prices fell steeply in late 2014 and early 2015, operators began
completing fewer wells and searching for ways to make the drilling and stimulation process more
profitable for the fewer wells they completed. This was accomplished by increasing productivity via longer
lateral lengths, the use of more proppant, and re-fractures of the well (Abramov 2016 and Bush 2017).
13 Source: http://gis-txdot.opendata.arcgis.com/datasets/8b902883539a416780440ef009b3f80f_0 14 Source: http://www.twdb.texas.gov/mapping/gisdata.asp
21
Figure 6. Hydraulically Fractured Wells in the Permian Basin (2012-2016).
Figure 7. Median Reported Water Use of Hydraulically Fractured Wells in the Permian Basin (2012-2016).
Descriptive statistics in Table 3, below, provide more information on the median reported volume of water
used in well stimulations across for horizontal and directionally drilled wells and also vertically drilled
wells during our period of study.
0
100
200
300
400
500
600
2012
.01
2012
.03
2012
.05
2012
.07
2012
.09
2012
.11
2013
.01
2013
.03
2013
.05
2013
.07
2013
.09
2013
.11
2014
.01
2014
.03
2014
.05
2014
.07
2014
.09
2014
.11
2015
.01
2015
.03
2015
.05
2015
.07
2015
.09
2015
.11
2016
.01
2016
.03
2016
.05
2016
.07
2016
.09
2016
.11
Num
ber o
f Wel
ls
Horizontal and Directional Vertical
0
2000000
4000000
6000000
8000000
10000000
12000000
14000000
16000000
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
201…
Wat
er V
olum
e (G
allo
ns)
Horizontal and Directional Vertical
22
Table 3. Descriptive Statistics. Median Reported Water Volume Per Well (Gallons) and Wells Completed.
2012 2013 2014 2015 2016
Horizontal and Directionally Drilled Wells
Median Water Volume 1,527,590 4,552,727 6,859,743 8,129,183 11,779,194
No. Completed Wells 1,008 1,481 2,364 2,336 1,883
Vertically Drilled Wells Median Water Volume 774,677 754,384 556,670.5 235,368 74,256
No. Completed Wells 5,668 5,639 4,630 1,455 576
Note: the number of completions per well was unavailable with these data.
After looking at the trends in water use, we noticed what appeared to be an error in the data as we found
that zero recycled wastewater was used in well stimulations over the period of study. We were not sure if
zero operators actually reported this information to FracFocus (it is not required, but it would appear to
be in the operators’ best interest to report it), or if PV was unable to obtain this information altogether for
the Permian Basin. We interpreted these findings with some skepticism and believe further examination
of water type reporting is needed since Dallas News (2014) reported that although information on
recycled wastewater use is difficult to obtain, a water consultant from Fort Worth estimated it at 20% for
the Permian in 2014. Seeley (2014) reported that Apache Corporation has used a system to stimulate
wells without the use of freshwater. Fasken Oil and Ranch, one of the oldest privately owned oil
companies in the Permian Basin, has also begun using alternatives to freshwater over concern of aquifer
depletion and future generations living on the ranch (Guerin 2014).
Given that only total water volume and chemical ingredients and compositions are required to be reported
to FracFocus in Texas, which is therefore the minimum amount of publicly available information that PV
can obtain, we believe that operators might report water use information with a variable level of useful
detail. We hypothesized that a potential reason for variation in reporting was due to operators completing
wells in counties with a GCD feeling more (or less) inclined to report any “extra” information in order to
make (or possibly hide) a paper trail on water use, even though reporting of this information was not
required. The reporting of additional water use information (e.g. type and source) is important as it can
provide valuable information and transparency about where operators obtain their water from in order to
more appropriately manage water resources in the Permian Basin and elsewhere. Reporting the use of
recycled wastewater can also be viewed as beneficial by operators in order to give them, and hydraulic
fracturing in general, a better image in the eye of the public.
23
Further examination of the data proved our hypothesis to be true. PV provided data (we believe the
majority of it is from FracFocus) on total hydraulic fracturing fluid (by mass), which consisted of
information on the base fluid(s), chemicals, and proppant or sand, used in well stimulations. We found
that, in addition to reporting total water volume, most records (97.85%) reported enough information on
the use of freshwater and other additives in order for PV to interpolate an estimate of hydraulic fracturing
fluid mass. However, a small percentage (2.15%) only reported the total water volume. We also found
that where the total hydraulic fracturing fluid mass was unknown, other information such as the
proportions of freshwater, recycled wastewater, salt water, slickwater, and produced water were not
available, yet a total water volume was always reported. We used this information to create an indicator
variable to classify the reporting tendency of well records providing “extra” information and those that
provided only what was required by Chapter 36.117(B)(2).
Table 4. Descriptive Statistics. Number of Wells Completed in GCD and Non-GCD Areas. 2012 2013 2014 2015 2016
Number of Horizontal and Directionally Drilled Wells GCD Area 376 705 1,125 1,029 887
Non-GCD Area 2,617 2,538 2,033 596 226
Number of Vertically Drilled Wells GCD Area 629 775 1,234 1,306 981
Non-GCD Area 3,004 3,087 2,582 857 327
Another interesting trend can be seen above in Table 4, where the number of wells stimulated in Non-
GCD areas is significantly greater than the number stimulated in GCD areas until 2015. This trend also
holds across both drilling orientations.
Methodology In order to analyze the tendencies of hydraulic fracturing operators to report more water use information
relative to less, we first implement a linear probability model in order to obtain a more easily interpretable
effect. We then use a predictive logistic regression to model as a robustness check because we are making
functional form assumptions with the linear probability model. In both models, we model dichotomous
dependent variable as a function of an indicator variable for the location of wells in a GCD or non-GCD
(or white) areas, the total water volume used in well stimulations, and well orientation. In this case, the
independent variables are useful to analyze how the probability of reporting extra water use information
changes if a well is located in a GCD or non-GCD area, how it changes for a marginal increase in the
24
volume of water used in stimulations, and how this probability changes for a horizontal well relative to a
vertical well. The advantage of a logistic regression is that it allows us to link the actual (binary)
dependent variable 𝑌 to the estimated dependent variable 𝑌′ as a linear function of the independent
variables (i.e. transforming 𝑌 from {0,1} to the real number line), for example:
𝐹(𝑌) = 𝑌′ = 𝑿𝜷 + 𝜖.
We define the binary dependent variable for well record i as follows:
(1) 𝑌, ∈ 1𝑖𝑓𝑚𝑜𝑟𝑒𝑤𝑎𝑡𝑒𝑟𝑢𝑠𝑒𝑖𝑛𝑓𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛 𝑡ℎ𝑎𝑛𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑 𝑤𝑎𝑠𝑟𝑒𝑝𝑜𝑟𝑡𝑒𝑑;0𝑖𝑓𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑𝑎𝑚𝑜𝑢𝑛𝑡𝑜𝑓𝑤𝑎𝑡𝑒𝑟𝑢𝑠𝑒𝑖𝑛𝑓𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛𝑤𝑎𝑠𝑟𝑒𝑝𝑜𝑟𝑡𝑒𝑑 ,
and model it with the logit function:
(2) log DEFD
= 𝑿𝜷.
This equation can be rewritten as:
(3) Y = H𝑿𝜷
EIH𝑿𝜷
where 𝑿 is a vector of our independent variables and 𝜷 is a vector of parameters to be estimated. We
estimate this model via maximum likelihood to obtain the estimated parameters (𝛽′𝑠). Given the
estimated 𝛽′𝑠, we can then calculate the likelihood or probability of observing each 𝑌, by plugging in each
𝑋,𝛽,.
Results In Table 5, below, the output from three linear probability models is shown to analyze whether the
location of a well in a GCD area has an effect on whether an operator reports more than the required
amount of water use information. The dependent variable in each specification is an indicator variable
taking the value of 1 if the operator reported more water use information than the amount required and 0
if the minimum amount of information was reported. In each model, we found that if a well was
stimulated in area within a GCD area there was an associated decline of about 1.5 percentage points in the
likelihood of an operator reporting additional information on water use. These estimates were significant
25
at the 90% level in the first specification, and at 95% and 90% in the other two specifications. Each model
included month of sample fixed effects.
Table 5. Linear Probability Model. Dependent Variable: Report Extra Water Use Information (1 or 0) (mean = 0.975) Model 1 2 3 GCD (1 or 0) -0.01518* -0.01529** -0.0144825* (0.00084814
) (0.0073825) (0.0072251)
Well Orientation -0.02611 *** -0.020165** (=1 if HOR/DIR, 0 if VER)
(0.0094173) (0.0091131)
Total Water Volume -0.00005*** (Unit = 50k Gallons) (0.0000096) Month of Sample FEs Yes Yes Yes Observations 26,914 26,914 26,914
Standard errors in parentheses. Clustered at county level. *** p<0.01, ** p<0.05, * p<0.10
In model 2, an indicator was added to control for well orientation, or whether the well was horizontally or
directionally drilled or vertically drilled. It was shown that if a well is drilled horizontally, there is an
associated 2 percentage point decline in the likelihood of an operator reporting additional information. In
model 3, total water volume was also included as an explanatory variable and show that a marginal
increase (50k gallons) in the total volume of water used in well stimulations is associated with a small, but
statistically significant decline in the likelihood of an operator reporting additional information on water
use beyond what is required.
In Table 6, below, the output from three logit models is shown and acts as a robustness check for the
linear probability model results. Although the interpretation of each coefficient is not intuitive, we still
found that the sign on each did not change from that in Table 5, and additional statistical significance
was gained for each model.
26
Table 6. Logit Regression. Dependent Variable: Report Extra Water Use Information (1 or 0) Model 4 5 6 GCD (1 or 0) -0.7301** -0.79077*** -0.74525*** (0.3360606) (0.2818386) (0.2707454) Well Orientation -1.24192*** -1.07635*** (=1 if HOR/DIR, 0 if VER)
(0.2271151) (0.2328098)
Total Water Volume -0.00187*** (Unit = 50k Gallons) (0.0005344) Month of Sample FEs Yes Yes Yes Observations 21,081 21,081 21,081
Standard errors in parentheses. Clustered at county level. *** p<0.01, ** p<0.05, * p<0.10
If a well was stimulated in within a GCD area there was an associated decrease in the likelihood of an
operator providing additional information on water use. These estimates were significant at the 95% level
in the first specification, and at the 99% level in each of the other two specifications. Similar statistically
significant estimates were found for both well orientation and total water volume in models 4 and 5,
indicating that are model passed one robustness check. Although we cannot yet claim a causal effect of
location within a GCD area, we believe that this is reasonable preliminary evidence of some variation in
reporting tendencies.
Conclusion Water withdrawal impacts from hydraulic fracturing can occur depending on the local balance between
withdrawals, availability, and quality, particularly in drought-prone regions with limited groundwater
recharge (U.S. EPA 2016c). Areas like the Permian Basin, with many wells being stimulated from large
amounts of sustained groundwater pumping, are most likely to experience impacts. Landowners in these
regions who are not pumping water for sale happen to be the ones who are most affected by the changes
to water availability, as they are faced with more expensive water from having to drill new wells and or
pump it from deeper, and also with the relocation possibility if water becomes too scarce. In Texas, most
aquifers are managed by multiple GCDs, however, portions of some aquifers are in areas that are not
managed by a GCD, meaning that even the best run GCD can be undermined by someone pumping
from the same aquifer water in a nearby area that is free from regulation (Hardberger 2016).
27
Data on water sources and types used in hydraulic fracturing are typically difficult to obtain15, which is
partly due to the fact that even within the GCDs or groups of GCDs that are more stringent, most do
not require metering or reporting of water use by water permit holders, which limits their ability to really
manage the aquifer (Hardberger 2016). We must be clear that our results do not indicate that hydraulic
fracturing operators are resistant to water use reporting. However, assuming that our interpretations and
use of the PV data are correct, they do provide evidence that GCDs might be in need of new ways to
induce water use reporting, particularly if more wells will continue to be hydraulically fractured in these
areas. We believe that the goal of these groundwater management regimes with respect to hydraulic
fracturing is to make water use more transparent and provide valuable data to inform better policy
making. One way to accomplish this goal might be to develop GCDs in white areas and expand water use
reporting requirements to FracFocus.
If such policies are infeasible, others that incentivize the reuse of wastewater from previous hydraulic
fracturing operations, or other alternatives to freshwater such as brackish water, can also reduce the need
for fresh surface or groundwater and offset total new water withdrawals for hydraulic fracturing. However,
the reuse of wastewater historically has been limited by its higher associated costs, which are a function of
water quality. To determine the potential for reuse, operators routinely test wastewater for certain quality
parameters such as pH, maximum concentrations of specific cations and anions, total dissolved solids
(which can inhibit the effectiveness of friction reducers), and microbial agents that can interfere with
hydraulic fracturing fluid performance if they multiply in the wellbore or interfere with other chemical
additives in the fluid (U.S. EPA 2016c).
Our conversation with an attorney from Rice University in Houston indicated that, more recently,
hydraulic fracturing fluids have become more robust as better technology has allowed for more efficient
treatment or dilution in order to meet the level of water quality desired in the hydraulic fracturing fluid
formulation. This is a positive sign and led Collins (2016) to argue that produced water is not being
treated as an asset and a market should be developed in order to exploit its potential as a commodity and
reduce freshwater withdrawals. Although adequate piping and storage infrastructure are not yet in place,
Dallas News (2014) mentions that various wastewater treatments plants have been constructed in the
Permian in order to supply water suitable for well stimulations and alleviate water availability issues.
These operations are not widespread yet due to wastewater recycling being more expensive for operators
than purchasing freshwater pumped from local supply sources.
15 Source: email conversation with Bridget Scanlon. https://www.jsg.utexas.edu/researcher/bridget_scanlon/
28
Echoing the argument for commoditizing wastewater, it has been found that high lithium concentrations
are found in produced water (Veil 2016; Shih, Swiedler, and Krupnick 2016), which could hypothetically
induce operators to value flowback and produced water more carefully. Additionally, Sourcewater is a
company based out of Houston, Texas, which is attempting to become the world’s first online water
marketplace for the oil and gas industry. Their goal is to lower the water sourcing and disposal or
treatment costs of operators by connecting water suppliers, demanders, and treatment (mobile or
stationary) and disposal locations online, which would be one way to alter the prices of water types and
induce changes in water use if sourcing or treatment costs are lowered.
Our future work on this paper will involve expanding the analysis to the whole state of Texas. We would
also like to find a better indicator for the level of reporting of hydraulic fracturing operators as well as
including several more variables from DrillingInfo including, the number of completions per well, lateral
length, perforation length, and target formation. Additionally, we would like to extend the motivation
behind this paper by obtaining groundwater level data and using it to identify an effect of hydraulic
fracturing on groundwater levels in the Permian Basin and or other regions such as the Eagle Ford or
Bakken formations. We believe that these extensions would be helpful in making better policy
recommendations and in the evaluation of mechanisms to incentivize the use of freshwater alternatives.
29
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