- SHALE GAS AND WATER IMPACTS

[Senate Hearing 112-247]
[From the U.S. Government Publishing Office]

S. Hrg. 112-247

SHALE GAS AND WATER IMPACTS

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HEARING

before the

SUBCOMMITTEE ON WATER AND POWER

of the

COMMITTEE ON
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE

ONE HUNDRED TWELFTH CONGRESS

FIRST SESSION

EXAMINE SHALE GAS PRODUCTION AND WATER RESOURCES IN THE EASTERN UNITED
STATES

__________

OCTOBER 20, 2011

Printed for the use of the
Committee on Energy and Natural Resources

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COMMITTEE ON ENERGY AND NATURAL RESOURCES

JEFF BINGAMAN, New Mexico, Chairman

RON WYDEN, Oregon LISA MURKOWSKI, Alaska
TIM JOHNSON, South Dakota JOHN BARRASSO, Wyoming
MARY L. LANDRIEU, Louisiana JAMES E. RISCH, Idaho
MARIA CANTWELL, Washington MIKE LEE, Utah
BERNARD SANDERS, Vermont RAND PAUL, Kentucky
DEBBIE STABENOW, Michigan DANIEL COATS, Indiana
MARK UDALL, Colorado ROB PORTMAN, Ohio
JEANNE SHAHEEN, New Hampshire JOHN HOEVEN, North Dakota
AL FRANKEN, Minnesota DEAN HELLER, Nevada
JOE MANCHIN, III, West Virginia BOB CORKER, Tennessee
CHRISTOPHER A. COONS, Delaware

Robert M. Simon, Staff Director
Sam E. Fowler, Chief Counsel
McKie Campbell, Republican Staff Director
Karen K. Billups, Republican Chief Counsel
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Subcommittee on Water and Power

JEANNE SHAHEEN, New Hampshire, Chairman

RON WYDEN, Oregon MIKE LEE, Utah, Ranking
TIM JOHNSON, South Dakota JAMES E. RISCH, Idaho
MARIA CANTWELL, Washington DANIEL COATS, Indiana
BERNARD SANDERS, Vermont JOHN HOEVEN, North Dakota
DEBBIE STABENOW, Michigan DEAN HELLER, Nevada
JOE MANCHIN, III, West Virginia BOB CORKER, Tennessee

Jeff Bingaman and Lisa Murkowski are Ex Officio Members of the
Subcommittee

C O N T E N T S

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STATEMENTS

Page

Beauduy, Thomas, W., Deputy Executive Director Counsel,
Susquehanna River Basin Commission............................. 29
Cooper, Cal, Worldwide Manager, Environmental Technologies,
Greenhouse Gas, and Hydraulic Fracturing Apache Corporation.... 38
Dougherty, Cynthia C., Director, Office of Ground Water and
Drinking Water, Office of Water, Environmental Protection
Agency......................................................... 5
Dunlap, Katy, Eastern Water Project Director, Trout Unlimited.... 42
Lee, Hon. Mike, U.S. Senator From Utah........................... 3
Russ, David P., Regional Executive for the Northeast, U.S.
Geological Survey, Department of the Interior.................. 9
Shaheen, Hon. Jeanne, U.S. Senator From New Hampshire............ 1
Wrotenbery, Lori, Director, Oil and Gas Conservation Division,
Oklahoma Corporation Commission................................ 22

APPENDIX

Additional material submitted for the record..................... 59

SHALE GAS AND WATER IMPACTS

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THURSDAY, OCTOBER 20, 2011

U.S. Senate,
Subcommittee on Water and Power
Committee on Energy and Natural Resources,
Washington, DC.
The subcommittee met, pursuant to notice, at 2:59 p.m. in
room SD-366, Dirksen Senate Office Building, Hon. Jeanne
Shaheen presiding.

OPENING STATEMENT OF HON. JEANNE SHAHEEN, U.S. SENATOR FROM NEW
HAMPSHIRE

Senator Shaheen. Good afternoon, everyone.
I apologize for the delay in starting this afternoon. As
you know, we had some votes on the Senate floor. So hopefully
we haven't delayed our panelists, and all of you who are here,
too much.
We are here today at this water and power subcommittee to
examine the effects of shale gas development on the water
resources of the eastern United States.
As we all know, the last decade has seen a real dramatic
change in the energy industry as technological advances have
opened up vast new stores of previously unrecoverable natural
gas.
Like many in Congress, I believe that natural gas has an
important role to play as we move to a clean energy economy.
That the benefits of abundant, domestically produced shale gas
are clear, particularly in States like my home State of New
Hampshire where 45 percent of the electricity is generated from
natural gas.
Shale gas has the potential to provide significant amounts
of affordable, clean electricity to both homeowners and
businesses. However, serious concerns have been raised about
the effects that shale gas production and hydraulic fracturing
have on water resources, particularly here in the eastern
United States.
The process of fracking just a single well requires
millions of gallons of water, which is often sourced from local
streams and rivers. In eastern shale formations, 20 to 40
percent of this water flows back up to the surface. The water
can often contain radioactive elements such as radium or other
materials that could be harmful to human health. Furthermore,
Duke University researchers have suggested that the improper
construction of shale gas wells can lead to methane
contamination of nearby surface waters.
The purpose of today's hearing is not to focus exclusively
on the risks associated with fracking, but rather, to hopefully
take a more holistic view of shale gas production and its
effects on water quality and supply. As our country becomes
more reliant on shale gas, it's critical that we examine the
full range of issues affecting our water resources.
Recently, the full committee heard testimony from the
President's Shale Gas Advisory Board, which stressed the need
to address issues resulting from the acquisition, management
and disposal of the water used in shale gas production. It's
important to note that the board has found that, by and large,
shale gas development is being conducted responsibly and that
the public should not be alarmed about any danger of widespread
contamination. It's the purpose of this hearing to further
explore that analysis, and to examine any outlying issues that
may be areas of concern.
Today we have a diverse panel of experts who will discuss
how water is being handled in eastern shale gas plays, what
steps are being taken to safeguard the public, which efforts
are working and what more work needs to be done.
Our first panel includes Cynthia Dougherty, who is director
of EPA's Office of Ground Water and Drinking Water, and David
Russ who is the Northeast Regional Director at the U.S.
Geological Service.
I'm going to go ahead and introduce our second panel prior
to their coming up. They include Lori Wrotenbery, who is the
director of the Oil and Gas Conservation Division of the
Oklahoma Corporation Commission, as well as a board member of
the State Review of Oil and Natural Gas Environmental
Regulation or STRONGER, as it's known.
Tom Beauduy is the deputy executive director and counsel
for the Susquehanna River Basin Commission.
Cal Cooper is the worldwide manager for Environmental
Technologies, Greenhouse Gas, and Hydraulic Fracturing for the
Apache Corporation.
Finally, Katy Dunlap is Eastern Water Program director at
Trout Unlimited.
I look forward to hearing from each of our witnesses about
their experiences with shale gas development, and the resulting
impacts on water resources.
Before I ask our panel to begin, I will turn it over to
Senator Lee for a statement.
[The prepared statement of Senator Casey follows:]

Prepared Statement of Hon. Robert P. Casey, Jr., U.S.. Senator From
Pennsylvania

Thank you for holding this oversight hearing to examine shale gas
production and water resources in the Eastern United States. We are
incredibly fortunate to have the abundant domestic source of energy and
jobs that shale gas represents. While I support the development of our
natural gas resources, Pennsylvania still bears the scars of mining and
drilling from decades past, which reminds us that we need to extract
our energy resources responsibly. Although Pennsylvania is relatively
gifted in water resources, we must protect and conserve them. In order
to assure that this priceless commodity will be around as clean and
plentifully as we have enjoyed it, we must treat our waters with the
same sense of value that we give all other resources. That is why I
introduced legislation, the Fracturing Responsibility and Awareness of
Chemicals (FRAC) Act, S. 587 to repeal the exemption of hydraulic
fracturing from the Safe Drinking Water Act. No industrial endeavor is
entirely without risk, so we must strive for prudent development and
proper monitoring, especially at the scale of Marcellus Shale.
While there are broader issues involved in shale gas production,
awareness of water resources concerns have been at the forefront.
Completing a typical Marcellus well requires millions of gallons of
water. The increasing number of reports, recommendations and local
efforts relating to shale gas demonstrate public demand for better
oversight of the industry and protection of our vital water resources.
Controls are needed to secure the quality and quantity of all water
resources--underground or surface; sources of drinking water of
fishable creeks. The full scope of potential pbulic health, safety and/
or environmental impacts should be fully assessed to plan for
development that assures an acceptable level of comfort for the general
public. One started, close monitoring of all operational parametes are
needed to allay any possible risks to safety, public health and the
environment.
Advances in technology have enabled us to get shale gas out of the
ground, now we need to prove that technology is as effective as
safeguarding our water, air, and communities. To prevent water quality
and quantity impacts, gas wells should be built to unequivocally
isolate underground acquifers and protect sources of drinking water.
The amount of wastewater created and how it is disposed of needs to be
closely watched. A growing network of pipelines, compressors, and
metering stations are conveying the gas from wells to where it will be
stored or used. To lessen waterway and wetland destruction, strategic
location of pipelines, preferably within the same carefully selected
corridors, should be planned for. Better coordination and communication
among industry planners, federal, state and local oversight agencies,
and the public on all of these aspects is critically needed to reduce
safety, property and environmental impacts while ultimately reducing
costs.
The FRAC Act I proposed also would require disclosure of the
chemicals used in the hydraulic fracturing process. We must have
transparent public disclosure for chemicals used in fracking fluids.
Many companies have been overly cautious in releasing proprietary
information about the ingredients in their fracturing fluids,
contributing to a public perception that the industry is hiding
something. I believe that the public's right to know extends to
disclosure of all additives used in the complete lifecycle of a well
even as drillers' intellectual property is protected. The public has
the right to know about any risks in their community, and what is being
hauled over their roads, or pumped through underground aquifers where
their water wells may be located. Public disclosure of fracturing
chemicals is also an easily achievable way to provide a measure of
comfort to local communities.
While technology is advancing rapidly, there is still more that can
be done. For instance, reduced water consumption and wastewater
generation may be possible using the frac fluids other than water, such
as nitrogen, carbon dioxide, or other foams, but advanced or
alternative techniques that could reduce or substitute water use are
not well understood. Alternative fracturing fluids and other ``green
completion'' methods may pave a path to more efficient production
techniques even while providing less significant environmental impacts.
Marcellus Shale natural gas has turned out to be Pennsylvania gold,
but we must ensure that Pennsylvania and our country benefits from this
newfound wealth of energy rather than being saddled with drinking water
threats and other risks. I am confident that the proper standards to
assure its prudent development will nto hinder its development as a
valuable domestic energy resource. I do not believe that this approach
requires us to choose our economy over our environment. Taking the
steps needed to assure that domestic energy production is done right,
even though they may be labor intensive, will lead to greater national
security and more jobs here at home.

STATEMENT OF HON. MIKE LEE, U.S. SENATOR FROM UTAH

Senator Lee. Thank you, Senator Shaheen.
I'd also like to thank our witnesses for joining us today.
To start, I think it's worth mentioning that today's
hearing follows several similar hearings previously held in
this committee over this month and in the EPW Committee. There
is another field hearing scheduled for next month and we've
looked quite closely at many of these issues.
Just about 2 weeks ago, our full committee held a hearing
on a shale gas report requested by Secretary Chu. He asked a
number of experts to spend 90 days identifying potential
environmental impacts associated with shale gas development, as
well as measures that can be taken to reduce those risks.
The testimony we heard at that hearing was encouraging and
overwhelmingly positive for natural gas drilling. All of the
witnesses testified that the challenges involved in shale gas
development, particularly the water issues, are manageable.
They also determined that the States should continue in their
roles as the primary managers and regulators of shale gas
development.
Today, we're back for another bite at the same apple. We're
here, again, to talk about the environmental implications
associated with shale gas development and who should manage the
risks. So as we hear testimony today, we ought to remember that
the administration's own handpicked panel provided testimony
consistent with the conclusion that the States are the
appropriate body to regulate shale gas development. They've
testified that the States are doing their job and doing it
well. They've unanimously agreed that the environmental risks
associated with shale gas development are being adequately
managed at that level, even as continued improvement is called
for.
I understand the desire to make sure that shale gas is
produced safely, and I'm hopeful that this committee, if we
continue to look at shale gas, will continue to and begin to
broaden its focus. Instead of focusing as heavily and
repeatedly on potential environmental impacts, we should also
look at the significant economic benefits that are now rapidly
apparent in places that are producing shale gas.
The members of our committee know I'm a strong advocate for
the domestic production of natural gas. It's pretty simple.
When we produce natural gas here in the United States when--
then we necessarily create jobs here. We generate revenues
here, and we help keep affordable energy here, and we need that
right now. It helps Americans. It helps our families and our
businesses. It helps attract investment. It helps our local and
rural communities. It helps our Nation stay competitive, and it
helps generate a revenue stream that's necessary to sustain,
among other things, the budget of our Federal Government.
Not too long ago, many people thought that high natural gas
prices were here to stay; a limited, natural gas supply to meet
our growing demand. Most people thought that job-producing
business--industries would suffer as a result of those
escalating gas prices. It was also anticipated by many that the
United States would begin to import large quantities of
liquefied natural gas in order to keep up with the demand.
But instead, what has happened is that the United States
has become mostly self-sufficient with regard to supplies of
natural gas. Our natural gas prices have fallen, hundreds of
thousands of jobs have been created, and industries that rely
on natural gas have invested billions of dollars in the United
States. Much of this is due to the development of shale gas.
So absolutely, we should make sure that natural gas is
being produced safely, and at the same time, let's not forget
that we have a commodity that everyone needs and in great
abundance right here in the United States, and we ought to be
producing all that we can while doing so in an environmentally
responsible manner.
I'm confident the States should continue to regulate shale
gas production and believe that industry should continue to
strive to maximize production and minimize any environmental
impacts.
I look forward to this hearing, but more than that, I look
forward to future, to a future where the money benefits
associated with natural gas production become even more
apparent through our country.
Senator Shaheen. Thank you, Senator Lee.
I will now turn it over to our panel. Ms. Dougherty, would
you like to begin?

STATEMENT OF CYNTHIA P. DOUGHERTY, DIRECTOR, OFFICE OF GROUND
WATER, DRINKING WATER AND OFFICE OF WATER, ENVIRONMENTAL
PROTECTION AGENCY

Ms. Dougherty. Thank you.
Good afternoon Chairman Shaheen, Ranking Member Lee, and
members of the subcommittee.
Thank you for inviting me to discuss natural gas extraction
and production activities, and EPA's role in protecting public
health and water quality.
As you said, I'm Cynthia Dougherty, Director of the Office
of Ground Water and Drinking Water at EPA.
Let me first note that EPA and this administration have
recognized the promise that natural gas holds as an important
energy resource for our country. We believe that this
resources, if accessed in an environmentally responsible
manner, has the potential to improve air quality, stabilize
energy prices, and provide greater certainty about energy
reserves.
In the last year as we've talked to people about hydraulic
fracturing and shale gas extraction, we've heard from many
citizens across the country about their concerns for their
families, their communities, and their water resources
regarding the potential impacts of natural gas production. But
we've also heard from citizens about how much their communities
sorely need the income that would be gained by natural gas
production.
We believe this important resource can be and must be
extracted responsibly in a way that protects drinking water
sources and surface waters. These considerations were laid out
in the president's Blue Print for Secure Energy Future and are
also consistent with the Secretary of Energy's advisory board's
recommendations for the safe development of natural gas
resources.
We also know that if improperly managed, natural gas
extraction, including hydraulic fracturing, can impact our
water resources and potentially endanger public health.
The EPA has an important role to play in protecting water
resources and we remain committed to working with State
officials who are on the front lines of permitting and
regulating natural gas production activities.
I'd like to highlight some of the key research and
programmatic activities our agency is currently undertaking.
At the request of Congress last year, EPA launched a
research study to understand the relationship between hydraulic
fracturing and drinking water resources. The EPA study will
look at 5 stages of water use in the hydraulic fracturing
process. These include: water acquisition, the mixing of
chemicals, injection at the well, flowback and produced water,
and the disposal of wastewater. We will be evaluating
information such as the characteristics of hydraulic fracturing
fluids and their behavior if released into the environment.
For the injection process itself, we will examine if well
construction is effective at containing fluids and gasses, and
will assess the potential for fluids or gasses to migrate to
drinking water resources.
The draft study plan was recently reviewed by EPA science
advisory board, and the final study plan will be released
shortly. The EPA plans to release the results of the study in 2
reports: one in 2012 and one in 2014.
In addition to these research activities, the EPA has
several regulatory authorities that can be used to ensure that
natural gas production is carried out safely and responsibly.
The Safe Drinking Water Act's underground injection control
program and the Clean Water Act's permitting and pretreatment
programs are examples of authorities we use to regulate certain
activities related to oil and gas production to protect public
health and water quality.
The EPA works with States to ensure that gas extraction is
carried out consistent with the Clean Water Ac and Safe
Drinking Water Act requirements to protect surface water,
ground water, and drinking water. This year under the clean
water programs, we produced a ``Frequently Asked Questions''
document to assist State and Federal Clean Water Act permitting
authority within the Marcellus Shale region in addressing
treatment and disposal of wastewater from shale gas extraction.
In addition, the EPA is developing a guidance to help
States address water quality issues related with that, the
wastewater treatment plants that accept that oil and gas
wastewater.
Today, as part of our planning process for technology based
standard on the Clean Water Act, we announced this morning our
decision to develop national pretreatment standards for
wastewater from shale gas extraction operations. The EPA will
develop these standards with the input of stakeholders
including States, industry, and public health groups. We plan
to issue the proposed rule in 2014. These pretreatment
regulations will ensure that shale gas wastewaters receive
proper treatment and can be handled by wastewater treatment
plants before the water is discharged to surface waters.
For the underground injection control program, the Energy
Policy Act of 2005 contains an exclusion from permitting
requirements for hydraulic fracturing for oil and gas. But this
exclusion does not extend to oil and gas hydraulic fracturing
activities when diesel fuels are used in the fracturing fluid.
The EPA is developing guidance for how to write permits for
wells that inject diesel fuel using hydraulic fracturing.
Separate from that, also under the underground injection
control program, we're also coordinating with our State and
tribal co-regulators to make sure that flowback and produced
water, or the wastewaters basically from the extraction
processes, are injected underground in a safe and a responsible
manner when that's the chosen disposal method.
In closing, the EPA is committed to using its authority
consistent with the law, and the best available science, to
protect communities across the Nation from impacts to water
quality and public health associated with natural gas
production activities.
Thank you again for the opportunity to testify.
[The prepared statement of Ms. Dougherty follows:]

Prepared Statement of Cynthia Dougherty, Director, Office of Ground
Water and Drinking Water, Office of Water, Environmental Protection
Agency

Good morning, Madame Chairman, Ranking Member Lee, and Members of
the subcommittee. I am pleased to be here today to discuss the EPA's
role in ensuring that public health and water quality areprotected
during natural gas extraction and production activities.
Natural gas can enhance our domestic energy options, reduce our
dependence on foreign supplies, and serve as a bridge fuel to renewable
energy sources. If produced responsibly, natural gas has the potential
to improve air quality, stabilize energy prices, and provide greater
certainty about future energy reserves.
While natural gas holds promise for an increased role in our energy
future, the EPA believes it is imperative that we access this resource
in a way that protects drinking water sources and surface waters.
As we listened to citizens at public meetings across the country
last year, we heard the concerns many have for their families, their
communities, and their water resources. We also heard from citizens who
expressed how much their communities sorely need the income that could
be gained from natural gas production.
We believe that this important resource can be - and must be -
extracted responsibly, in a way that secures its promise for the
benefit of all. If improperly managed, natural gas extraction and
production, including hydraulic fracturing, may potentially result in
impacts to public health or our water resources. If we look at water
across the entire shale gas extraction process, from water acquisition
to wastewater treatment and disposal, some of the impacts on our water
resources may include:

stress on surface water and its uses and groundwater
supplies from the withdrawal of large volumes of water used in
drilling and hydraulic fracturing;
potential contamination of drinking water aquifers resulting
from faulty well construction and completion;
compromised water quality due to challenges with managing
and disposing of contaminated wastewaters, known as flowback
and produced water, where contaminantscould include organic
chemicals, metals, salts and radionuclides

The EPA has an important role to play in protecting water resources
and in working with federal and state government partners to manage the
benefits and risks of shale gas production. We must effectively address
the potential consequences of shale gas development on water resources
using the best scienceand technology. To this end, we are working in
the following areas and under the following authorities, among others,
with stakeholders, including other federal and state agencies, the oil
and gas industry, and the public health community, to evaluate and
address the potential public health and water quality issuesrelated to
shale gas extraction. These actions are important pieces of the
Administration's broader effort to ensure that natural gas production
occurs in a safe and responsible manner, as laid out in the President's
Blueprint for a Secure Energy Future. They are also consistent with the
Secretary of Energy Advisory Board's recently released recommendations
on steps to support the safe development ofnatural gas resources.
Research
At the direction of Congress, the EPA launched a study last year to
better understand the potential impacts of hydraulic fracturing on
drinking water resources. As part of this study, the EPA has engaged
thousands of Americans across the country who currently live in areas
where hydraulic fracturing is taking place. When complete, this peer-
reviewed research study will help us better understand potential
impacts of hydraulic fracturing on drinking water resources and factors
that may lead to human exposureand risks, while reducing scientific
uncertainties about environmental impacts from those processes.
As part of this effort, the EPA has used information gathered from
oil and gas companies conducting hydraulic fracturing and from the many
stakeholder outreach meetings the EPA held duringdevelopment of the
study plan. The draft study plan was recently reviewed by the EPA's
Science Advisory Board, is in the last stages of being finalized, and
is expected to be released soon. The EPAplans to release two reports,
one in 2012 that will summarize existing data, intermediate progress
regarding retrospective case studies, scenario modeling and laboratory
studies; and one in 2014 that will provide additional scientific
results on these topics and report on prospective case studies and
toxicological analyses.

Examples of Authority to Protect Water Resources
While Congress specifically exempted selected oil and gas
production activities from several environmental laws, a number of
environmental protections continue to apply. The Safe Drinking WaterAct
(SDWA)'s Underground Injection Control (UIC) program and Sections
301(b) and 402(a) of the Clean Water Act (CWA) are two examples of laws
the states and EPA use to regulate certain oil and gas production
activities to protect public health and water quality. For example, the
Energy Policy Act of 2005 contains an exclusion from the SDWA UIC
program's permitting requirements for hydraulic fracturing for oil and
gas, but this exclusion does not extend to oil and gas production
activities when diesel fuels are used in fracturing fluids. The SDWA
also regulates underground injection of flowback and produced water.
The EPA and authorized states have the authority to regulate waste
waters from oiland gas wells under Sections 301(b) and 402(a) of the
CWA when they are discharged into publicly owned treatment works
(POTWs) and surface waters. Under these two examples of authorities,
the EPAhas a number of activities underway, which I would like to
outline for you.

Examples of Activities to Protect Water Resources
Under the CWA and SDWA, the EPA works with states to ensure that
gas extraction is carried out consistent with CWA and SDWA regulations
to protect surface water and drinking water. This year, the EPA
produced a frequently asked questions (FAQ) document to assist state
and federal permitting authorities within the Marcellus Shale region in
addressing treatment and disposal of wastewater fromshale gas
extraction.\1\ The document covers oil and gas extraction, centralized
waste treatment, acceptance and notification requirements for publicly
owned treatment works, pretreatment, and storm water. The FAQs have
assisted the EPA and state personnel as we have worked with the
regulated community to address shale gas extraction wastewater. In
addition, the EPA is developing guidance to help states address water
quality issues related to Centralized Waste Treatment Facilities or
POTWs that accept oil and gas wastewater. As part of its effluent
guidelines planning process under CWA section 304(m), the EPA is
considering whether to initiate a rulemaking to revise these
regulations to address natural gas extraction flowback waters.
---------------------------------------------------------------------------
\1\ This document is available at http://cfpub.epa.gov/npdes/
hydrofracturing.cfm
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Under SDWA's UIC program, the EPA is working expeditiously to
ensure the SDWA programmatic requirements related to hydraulic
fracturing when using diesel fuels are implemented appropriately. The
EPA is developing guidance to provide information to the states and
regulated community on permitting wells that inject diesel fuels during
hydraulic fracturing. With regard to flowback and produced water, we
are coordinating with our state and tribal co-regulators to ensure
proper management of flowback and produced water disposed of via
underground injection.

Conclusion
In conclusion, the EPA is committed to using its authorities,
consistent with the law and best available science, to protect
communities across the nation from impacts to water quality and public
health associated with natural gas production activities. Where we know
problems exist, the EPA will not hesitate to protect Americans whose
health may be at risk.
We remain committed to working with state officials, who are on the
front lines of protecting water resources and regulating natural gas
production activities. By helping manage environmental impactsand
addressing public concerns, natural gas production can proceed in a
responsible manner, which protects public health and enhances our
domestic energy options. We believe that as a Nation, we canprovide for
the safe and responsible development of this significant domestic
energy resource whose use brings a range of other important national
security, environmental and climate benefits.

Senator Shaheen. Thank you very much.
Mr. Russ.

STATEMENT OF DAVID P. RUSS, REGIONAL EXECUTIVE FOR THE
NORTHEAST, U.S. GEOLOGICAL SURVEY, DEPARTMENT OF THE INTERIOR

Mr. Russ. Chairwoman Shaheen, members of the subcommittee
who--Chairwoman Shaheen and members of the subcommittee, thank
you for the opportunity to appear before the subcommittee to
discuss the USGS's role in studying, understanding, and
assessing the potential effects of shale gas production on
water resources.
The Department of the Interior supports responsible
development of natural gas as a clean energy sources. So it is
important to investigate and evaluate potential impacts to the
environment associated with shale gas development.
The Marcellus Shale is a rock formation that occurs across
the Appalachians containing a potentially large economic
resource space. The USGS recently released a new assessment of
the undiscovered, technically recoverable, gas resources of the
Marcellus Shale. Results show that there is a mean value of 84
trillion cubic feet of gas within the Marcellus Shale system.
The USGS is coordinating ongoing and planned Marcellus
Shale gas research and monitoring, a complement other Federal
and State shale gas programs, particularly those of our sister
bureaus within Interior. We are collaborating with the EPO--EPA
on its ongoing national study on hydro fracturing and its
potential impact on drinking water.
For example, we are drilling several observation wells in
the vicinity of an EPA prospective wellsite in western
Pennsylvania to provide a baseline on groundwater quality prior
to the drilling of a nearby gas production well.
The USGS leads an ad hoc Federal Committee that is
preparing a plan to help facilitate a coordinated Federal--
State approach to evaluate the environmental effects of shale
gas production in the Delaware, Susquehanna, and Ohio River
Basins. USGS activities on the potential environmental effects
of shale gas exploration and production include research to
protect water supply and water quality, to measure baseline
water quality conditions, and to conduct research on potential
impacts to land cover and ecosystems. The USGS conducting
studies to assess potential for this contamination.
In one study on water quality, the USGS is analyzing the
composition of produced waters from the Appalachian Basin,
focusing on the radium content in the water.
Another study investigated the occurrence of natural gas in
private water supply wells in northern Pennsylvania using
chemical and isotopic techniques to determine the nature and
the source of the gas. The research showed the gas artificially
injected into the deep storage reservoirs can migrate upward
into shallow water wells, but that detailed studies are
necessary to accurately identify the sources of this gas.
The USGS plans to develop a regional groundwater flow model
for defined areas of the Marcellus Shale gas play to evaluate
the fate of injected hydrofracture waters that are not
recovered. Additional research is needed, however, to fully
understand the potential fate of injected waters, particularly
in areas where hydrofracturing and resource production from
shallow shale beds is permitted.
Because natural gas emanating from subsurface rock and
alluvial formations can be both natural and man-generated,
baseline monitoring before, during and after gas exploration
and production activities is needed to detect the possible
presence of the gas and to distinguish among gas sources. To
meet this need, the USGS is conducting a number of baseline
surface and groundwater studies.
One of the studies is characterizing the existing water
quality of natural park supply wells or public wells serving
these park units in order to provide a baseline of comparison
with future water quality conditions.
To provide a basis for improved regional baseline
monitoring, the USGS has enhanced its existing water quality
monitoring network in Pennsylvania through support from the
Pennsylvania Department of Environmental Protection. These
activities are providing a snapshot of conditions at selected
locations.
A more comprehensive, regional monitoring, assessment, and
research program would provide the data and information to
understand the relations among hydrofracturing, environmental
setting, and management factors on water resources of the area.
USGS resource--research on potential impacts of shale gas
production on biological resources is focused on assessing
changes in land use patterns and possible impacts on forests
and aquatic habitats.
The USGS is using airborne imagery to assess forest
fragmentation caused by shale gas activities and its possible
effects on the abundance of migratory bird populations.
Research also is addressing the effects of habitat change on
key aquatic species in the Marcellus Shale region, including
eastern brook trout and the federally endangered dwarf wedge
mussel.
There are a variety of additional issues related to water
resources and shale gas production that warrant investigation
by the appropriate agency, institution, or industry.
Thank you, Chairwoman Shaheen. I will be happy to answer
any questions you, or the other members, may have.
[The prepared statement of Mr. Russ follows:]

Prepared Statement of David P. Russ, Regional Executive for the
Northeast, U.S. Geological Survey, Department of the Interior

Thank you Chairwoman Shaheen and members of the subcommittee for
the opportunity to appear today to discuss with you the U.S. Geological
Survey (USGS) role in studying, understanding, and assessing the
potential effects of shale gas production on water resources and
related scientific topics. I am David P. Russ, Regional Executive for
the Northeast Area. I manage USGS science centers and activities in the
northeastern U.S. and coordinate USGS shale gas studies in the
Northeast. I represent the USGS in meetings of the Delaware and
Susquehanna River Basin Commissions (DRBC & SRBC).
The USGS serves the Nation by providing reliable scientific
information to describe and understand the Earth; minimize loss of life
and property from natural disasters; study and assess water,
biological, energy, and mineral resources; and enhance and protect our
quality of life. USGS conducts scientific investigations and
assessments of geologically-based energy resources, including
unconventional resources such as shale gas and shale oil. USGS programs
to monitor and investigate the Nation's surface and ground water
resources are fundamental in determining water availability and water
quality, including the potential impacts of energy resource extraction
on drinking water, healthy ecosystems, and the sustainability of living
species. The Department of the Interior (Interior) supports responsible
development of natural gas as a clean energy source, so it is important
to investigate and evaluate potential impacts to the environment
associated with shale gas development.
USGS research related to shale gas development is in important part
of the Administration's actions to ensure the natural gas production
proceeds in a safe and responsible manner. These research activities
are in line with priorities identified in the President's Blueprint for
a Secure Energy Future, and are also consistent with the Secretary of
Energy Advisory Board recommendations on research steps to support the
safe development of natural gas resources.

Role of the USGS in Unconventional Energy Resource Studies in the
Northeast
The USGS conducts research and assessments of the undiscovered,
technically recoverable oil and gas resources of the United States
(exclusive of the Federal outer continental shelf). Advances in
drilling technologies and subsurface geophysical imaging techniques
over the last 20 years have enabled a new class of petroleum systems,
primarily coal, shale and tight sands, to become more easily accessible
and economically viable as petroleum sources. These unconventional
systems lack traditional oil and gas trapping structures, are regional
in extent, occur in rock of extremely low permeability, and, therefore,
require artificial stimulation such as hydrofracturing to produce the
gas or oil (see attached *figure 1).
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* All figures have been retained in subcommittee files.
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The Marcellus Shale is one of a number of shale formations that
occur across a considerable area in the Appalachians. The Marcellus
Shale is sufficiently thick and organically rich to contain a
potentially large economic resource base. In August 2011, the USGS
released a new assessment of undiscovered oil and gas resources of the
Marcellus Shale. Results from the assessment found that there is a mean
value of 84 trillion cubic feet of gas within the Marcellus Shale
system, an amount that is significantly higher than the 2 trillion
cubic feet estimate provided in an USGS assessment conducted in 2002
before the application of modern hydrofracturing and horizontal
drilling technologies. By comparison, according to the Department of
Energy's (DOE) Energy Information Administration, the total natural gas
consumption for the United States in 2010 was about 24.1 trillion cubic
feet. The USGS recently completed and is preparing for release a new
assessment of the unconventional natural gas and natural gas liquid
resources in the Mesozoic Basins of the Eastern U.S. The geological and
groundwater characteristics of various shale gas formations vary
significantly across the region and can affect production economics and
potential environmental impacts in different ways. USGS is conducting
research that should allow for an improved understanding of the local
and regional variations in gas abundance, composition, and quality. The
results could serve to guide exploration strategies and the resultant
need and locations of water resources to support future gas and oil
development efforts.

Focus of USGS Shale Gas Research in the Northeast
The USGS is coordinating ongoing and planned research activities
that complement other Federal and State shale gas programs, with
particular effort being made to support the decision-making needs of
Interior resource management agencies. For example, the USGS is
coordinating with the Environmental Protection Agency (EPA) in its
ongoing national study on hydrofracturing and its potential impact on
drinking water.
The USGS chairs a Federal committee, that includes representatives
from Interior agencies, EPA and U.S. Army Corps of Engineers, that is
preparing a plan to help facilitate a coordinated Federal-State
approach to evaluate the environmental effects of shale gas production
in the Delaware, Susquehanna, and Ohio River basins.
USGS activities on potential environmental effects of shale gas
exploration and production is focused on three primary topics: 1)
research to protect water supply and water quality, 2) measurement of
baseline water-quality conditions, and 3) research leading to improved
management of short term and cumulative impacts to land quality and
terrestrial and aquatic ecosystems. The USGS currently is focusing
monitoring and research on documenting and understanding the conditions
of water quality and availability and habitat conditions prior to land
disturbance and shale gas development. In the Marcellus Shale gas area,
the USGS is focusing on the potential effects of hydrofracturing and
gas production to water quality and the occurrence of natural gas in
private water wells (so-called ``stray gas''). Concerns about the
possible presence of gas and hydrofracturing chemicals in private
water-supply wells have been raised by citizens living in areas where
shale gas production is underway.

Protecting Water Supply and Water Quality
The possibility of surface and ground water contamination from
drilling practices at the well pad, accidents, groundwater transport,
and the construction of pipelines and support facilities to collect and
convey gas has been a prevailing topic in public discussion. Drilling
regulations and permits issued by federal and state agencies and water
basin commissions, as well as industry best management practices, are
designed to minimize these potential problems. However, whether these
practices and regulation are adequate to protect water supplies and
water quality during drilling and production are still a concern and
the need to review and modernize regulations and best practices was
noted in the Secretary of Energy Advisory Board Shale Gas Production
Subcommittee--90-Day Report. Some of the key water supply and quality
concerns related to Marcellus Shale gas production include:

Effect of water withdrawal for well construc*tion and
hydrofracturing on local water resources,
Effects of land disturbance from road, bridge, and drill pad
development and from heavy equipment travel on stream
sedimentation and small watershed degradation,
Safe storage and disposal of the large quantities of fluids
recovered from the wells, which may contain salt and
radioactive elements,
Composition and fate of chemicals introduced into the well
bore during hydrofracturing and the potential effect of these
chemicals on public drinking water supplies, groundwater,
wetlands, and sensitive habitats.

Examples of ongoing USGS Studies

The USGS is analyzing the composition of produced waters
from the Appalachian Basin (waters that flow into the well
after well completion and during the gas production phase) and
recently released a publication on this topic that focuses on
the radium content in the produced waters.
USGS is studying the occurrence of natural gas in private
water-supply wells in northern Pennsylvania, using chemical and
isotopic techniques to determine the nature and source of the
gas. This ``stray gas'' can emanate from a variety of natural
and human produced sources, which may include abandoned oil and
gas wells, subsurface fluid injection wells and water wells.
Because there are tens of thousands of abandoned wells in
Pennsylvania, the potential occurrence of abandoned well
leakage is a significant issue. Stray gas also can be released
naturally by various organic-rich rock formations, abandoned
coal mines, landfills, and decaying vegetative matter in
alluvial fill (biogenic gas).
The USGS is collecting water resource data from the
Marcellus Shale gas region and is using these data to assess
the potential effects of hydraulic fracturing on water
resources in the Marcellus Shale area.

Planned USGS Research
The USGS plans to use its modeling capabilities to develop a
regional groundwater flow model for specific areas of the
Marcellus Shale gas play to evaluate the fate of injected
hydrofracture waters that do not return up the wellbore to the
surface as ``flowback waters'' (a relatively small proportion
of the water in Marcellus wells currently returns to the
surface). Additional research is needed to fully understand the
potential fate of the injected waters, particularly in areas
where hydrofracturing and resource production from shale beds
as shallow as 2,000 feet from the surface is permitted. For
example, a recently published USGS study shows that
artificially injected deep gas can and does migrate into
shallow water wells in the Marcellus Shale gas area in northern
Pennsylvania.

Baseline Water Quality and Natural Gas Measurements
Because natural gas can and does emanate from a variety of
subsurface rock and alluvial formations (for example, organic shales,
abandoned coal mines, conventional oil-and gas-bearing rocks,
landfills, and river valley alluvial fills), baseline monitoring for
natural gas occurrence is needed for research purposes prior to,
concurrent with, and following gas exploration and production
activities in order to detect and/or distinguish among these gas
sources. Given the challenge of conducting such monitoring that would
cover the entire extent of the Marcellus Shale gas area with sufficient
instrumentation for meaningful analysis, USGS recommends that several
representative pilot areas be instrumented to support the collection of
baseline water quality and gas data. It is important that the
monitoring be maintained for an extended period of time to ensure a
scientifically adequate sample size to detect water quality anomalies
and determine possible trends.
USGS is conducting a number of baseline surface water and
groundwater quality studies, including:

Groundwater quality baseline monitoring and simulation of
groundwater sources to wells is underway at the USGS Northern
Appalachian Research Lab in Wellsboro, PA.
Improvements to the USGS water-quality monitoring network in
Pennsylvania have been made to enhance monitoring in headwater
streams near drilling operations. Through support from the
Pennsylvania Department of Environmental Protection, eleven new
sampling sites were added in small headwater streams during FY
2011, and the frequency of sample collection and analysis was
increased at existing sites. Ten new continuous monitors were
added for temperature, dissolved oxygen, specific conductance,
and pH that will improve the baseline of water quality in the
State.
Baseline water quality in National Park units within the
Marcellus and Utica Shale gas plays is being assessed. This
work is characterizing the existing water quality and
radiochemistry of National Park supply wells or public wells
serving these park units in Pennsylvania, New York and West
Virginia in order to provide a basis of comparison with future
conditions, including identification of the potential effects
of hydrofracturing (see figure 2).
Construction of several observation wells near an EPA
prospective research site in western Pennsylvania is underway
to provide background data on groundwater quality prior to the
drilling of a primary Marcellus Shale gas well nearby. This
project is part of USGS's collaboration with EPA on its
national study regarding the potential impacts of
hydrofracturing operations on drinking water supplies.
USGS is monitoring baseline surface water and groundwater
quality in the Lycoming Creek watershed in northeastern
Pennsylvania and in Blair County in central Pennsylvania.

The activities are providing a snapshot of conditions at selected
locations. A more comprehensive regional monitoring, assessment, and
research program would provide the data and information to understand
the relations among hydrofracturing, environmental setting, and
management factors on water resources of the area.

Managing Short-Term and Cumulative Impacts on Land Use, Wildlife, and
Ecosystems
Potential impacts to biological resources and the water resources
available to sustain them due to activities associated with shale gas
development are also being investigated. The use of large volumes of
freshwater for drilling, completion of shale gas wells, and for
hydrofracturing purposes will result in a net loss of available
freshwater. To reduce freshwater use, most companies recycle fracture
water that has been ``rehabilitated'' after initial use, however,
impacts to freshwater resources may remain. Additionally, fragmentation
of the forest canopy due to Marcellus Shale gas development in the
region could potentially create challenges for plants and wildlife and
open avenues for invasive species.
For biological resources, landscape scale research is important to
quantify responses of key species and ecological communities to the
impacts resulting from development of energy resources within the
Marcellus Shale and to develop best management practices to identify
and mitigate impacts. In addition to traditional biological and
ecological research, new interdisciplinary approaches linking ecology,
economics, and geospatial modeling frameworks can be applied to assess
impacts across the full suite of ecosystem services and provide the
science decision-makers need to prioritize management decisions.
As a first step, USGS research on potential impacts of shale gas
production on biological resources is focused on using remotely sensed
airborne imagery to assess forest fragmentation and effects of shale
gas activities on land use patterns and the abundance of migratory bird
populations in key areas where shale gas production is underway.
Research also is addressing the effects of habitat change on key
aquatic species in the region affected by Marcellus Shale production,
including eastern brook trout and the federally endangered dwarf wedge
mussel.

General Research and Development Needs
There are a variety of important issues related to water resources
and shale gas production that warrant investigation by the appropriate
agency, institution or industry. These include:

Characterization of the physical processes by which rock
fractures are formed and propagate during the hydrofracturing
pressurization process. The USGS previously has conducted
research on hydrofracturing in an effort to characterize the
Earth's natural stress fields as part of its Earthquake Hazards
Reduction Program. Controlling the propagation of induced
fractures is important to limiting water use required in
hydrofracturing, minimizing the potential for the formation of
large contiguous fracture sets that could potentially serve as
conduits to transmit hydrofracturing fluids to or near aquifers
and/or the Earth's surface, and maximizing the yield of gas
from the reservoir.
Assessment of water requirements necessary to re-
hydrofracture gas wells that are declining in gas production.
This research would address the important topic of re-use of
existing wells, thereby reducing the need to drill new wells
and minimizing additional impacts on the environment. Important
components of this research would be the application of
advanced microseismic techniques to better understand how the
original fractures formed during the hydrofracturing process
and whether re-hydrofracturing might simply open up existing
fractures rather than generate new ones, which would
significantly reduce the potential gas yield from the well.
Investigation of the effects of water flowing through
fractures generated by hydrofracturing on gas yield. As gas
production in a well diminishes over time, there is reduced gas
pressure in the fractures, so the water in the fractures could
act as a ``flow retardant.'' Pressure, however, is necessary to
drive water and gas out of the rock and into the well. The
research would address mechanisms to enhance gas flow.
Understanding induced seismicity triggered by the injection
of shale gas waste fluids into the subsurface. The USGS has
conducted research on induced seismicity as part of the
Earthquake Hazards Reduction Program. USGS has partnered with
the Arkansas State Geological Survey to evaluate a series of
earthquakes during the past year and assess whether they may
have been generated by waste water fluid injection in wells in
the Fayetteville Shale gas play area.

Thank you, Chairwoman Shaheen, for the opportunity to share USGS
research activities and plans on the very important topic of the
potential effects of shale gas production in the Northeast on water
resources. I will be happy to answer any questions you or the other
Members may have.

Senator Shaheen. Thank you very much, Dr. Russ.
Since this hearing is supposed to be addressing gas
development and water resources in the eastern United States,
and much of the previous hearing has dealt with gas development
out West, perhaps you could start by talking a little bit about
what's different about shale gas development in the East versus
the West as we look at the geology?
Mr. Russ. Right. The shale gas development in the East
largely relates to the Marcellus Shale gas and the Utica Shale.
Because of the demonstrated existence of high amounts of shale
gas in the Marcellus, this has really taken off in the last few
years as a primary target.
The thickness of the shale potentially accommodates a large
amount of gas. The amount of gas in the enriched organic matter
within that gas makes it a truly attractive target.
There are some differences in the types of gas between the
northern part of the area in New York and Pennsylvania versus
the southern part into West Virginia, but still, it's an
attractive target.
The gases in other parts of the United States, whether it's
the Barnett Shale in Texas or the Fayetteville Shale in
Arkansas, are also very attractive targets. They have been, I
think, under production for a bit longer period of time than
Marcellus. But certainly the recent ability to do
hydrofracturing and horizontal drilling, and the recognition of
the target for opportunity in the Marcellus is making that an
area of significant current play.
Senator Shaheen. Can you talk about whether the geology of
water in the eastern United State is different, and how that
might affect production?
Mr. Russ. One I am--can remark upon, Senator, is the fact
that the Marcellus Shale has higher salinity levels in the
water related to where the gas is than of the other oil and gas
reservoirs that we are familiar with in the United States. So
that high level of salinity must be dealt with, of course, by
industry, but it also is a potential for mobilizing higher
levels of radium than perhaps in some of the other basins and
areas of production. So it's something that we're looking at
and studying at this point in time.
Senator Shaheen. Thank you.
Ms. Dougherty, did you want to add? Is there anything that
you would like to add to, as we look at----
Ms. Dougherty. Yes, I would like to say that the----
Senator Shaheen. The differences?
Ms. Dougherty. The higher levels of salinity may create
issues that need to be dealt with in terms of the produced
water discharges and what's done with the produced water. It is
an issue that's come up in Pennsylvania that Pennsylvania DEP
and EPA are working together to look at.
Senator Shaheen. Does the level at which groundwater can be
accessed have any impact that's different in the East than the
West?
Mr. Russ. I don't know of any difference in the impact.
It's of interest to us to understand where is the groundwater
moving? Is it flowing in some regional fashion? If so, where is
it moving to?
In some areas, you can hydrofrac and develop shale
resources of shale is 2,000 feet. So understanding, given those
relatively shallow depths what the groundwater regime is, we
believe it's important. That's why in my testimony, I mentioned
the development of a regional groundwater flow model.
Senator Shaheen. Thank you.
Ms. Dougherty, you talked or you mentioned that just today,
the EPA is proposing new standards for wastewater disposal for
shale gas. That this process will likely take until 2014?
Ms. Dougherty. To get to the proposal, yes. Yes.
Senator Shaheen. Can you talk a little bit about----
Ms. Dougherty. Sure.
Senator Shaheen. What's going to be involved in that?
Ms. Dougherty. Sure. EPA has under the Clean Water Act
permit--there are permits required for discharge of wastewater
to surface waters in the United States. Those permits are set
up in terms of technology-based standards which apply across
the country, and then water quality-based standards which
States apply based on the standards they've set in their State.
So the technology-based standards are the floor, basically.
There are no such standards for wastewaters from shale gas
extraction. Right now, the standard that applies to them does
not allow direct discharge of those wastewaters. But the
wastewaters are being taken to sewage treatment works or to the
centralized waste treatment works to have treatment before
they're discharged.
There really isn't a good treatment right now available for
some of the things that are in the wastewater, and so we need
to work through what can't--what should be done in terms of
those technology-based standards that everyone can use. This is
an issue we've been working, particularly with Pennsylvania on,
because there were a number of sewage treatment plants that
were being asked to accept the waste and they could create
problems, both for the sewage treatment works working, as well
as for the water quality were they discharged.
Senator Shaheen. Do we know what treatment methods are out
there that can address----
Ms. Dougherty. There's some treatment methods that are out
there, but the purpose of doing the regulatory process is to
find out what treatment exists and what treatment would be
usable to the industry. In some cases--and what they've done
previously is they decided that the best, the most economical
way to dispose of the waste was through injection, which is
covered under the underground injection control program. So,
they've got to sort out whether or not it could be done through
the sewage treatment plant.
Senator Shaheen. Thank you.
Senator Lee.
Senator Lee. Dr. Russ, as I understand it, the U.S.
Geological Survey has been conducting some well water testing
in Van Buren County, Arkansas within the Fayetteville Shale gas
play looking for possible links between concerns over drinking
water and natural gas drilling.
Can you tell us a little bit what--about what you found
after testing in what I understand to be 71 samples? What did
you find there?
Mr. Russ. Yes, in fact, this is quite recent information.
You're quite right, Senator, and what we found is we detected
no evidence of any contamination or materials from the
hydrofracturing process or drilling effort that have gotten
into any of the wells that were sampled. These wells are
peripherally right in the area of where the drilling is
ongoing.
Senator Lee. So do you know what it is you're looking for?
I mean, what is it you're looking for? Are there specific
chemical markers you're trying to identify when you conduct
those samples?
Mr. Russ. Yes. We look, certainly, for evidence of
salinity, which would be an indication potentially of mobilized
salt related to the shale gas and the hydrofracturing process
being able to get into shallow private water wells, for
example. Any anomalous chemicals that otherwise were not
expected to be in the groundwater. I don't know right off the
top just which chemicals are we're looking for.
Senator Lee. So how would you characterize the quality of
the water that you sampled, then?
Mr. Russ. We would say that there's no demonstrable change
whatsoever from the natural, native water that's there before
the drilling.
Senator Lee. OK. Do you plan to conduct additional tests in
the Fayetteville play or in other plays around the country?
Mr. Russ. We have not made those decisions yet, Senator.
Senator Lee. OK. How--and then, do you store that data? I
guess the plan is to store that data and compare it to data you
might collect in the future to see if anything changes?
Mr. Russ. We would store it, but most probably would also
release it in the form of a report, a technical report or a
published--a publication of some sort.
Senator Lee. OK. But you were, I assume, somewhat relieved
by the findings that you did make, by what you discovered, the
lack of contamination that you saw?
Mr. Russ. We--in the USGS, we try to maintain a non-
advocacy neutral position. We report what we find and then let
others make the decisions.
Senator Lee. Free of any positive or negative emotion, in
other words.
Mr. Russ. Yes.
Senator Lee. OK. That's good to know.
Ms. Dougherty, I've got a question for you. So you issued a
press release that says that you're proposing a schedule to
develop new standards for wastewater discharges produced by
shale gas extraction. Is the NPDES program insufficient in some
way in order to cover that kind of concern or is this?
Ms. Dougherty. Right now, under the NPDES program, this
will be covered by the pretreatment part of that program,
because there's no direct discharge allowed.
But under the pretreatment part of the program, there are
no technology-based standards for what someone who would be
bringing that produced water to a sewage treatment plant would
need to do beforehand. Usually, you would have to pretreat
industrial wastewater so that you wouldn't have what we call
interference or pastures.
So interference would be, you don't want to screw up the
sewage treatment plant because then you'd have raw sewage going
into the water. Pasture is you don't want contaminants going
directly into the surface water that don't get treated in some
way if they're going to cause harm to the surface water.
So right now, in order to deal with that, the EPA or the
State, or actually in the case of Pennsylvania, it's EPA and
the State because the State has the permitting program, but EPA
runs the pretreatment program. Would have to have the town or
the sewage treatment plant would have to develop local limits
for what they would do on a plant by plant basis, as opposed to
having the underlying technology standards that could then be
used whenever someone brings that waste to a source stream or
plant. That's the point of doing it.
Senator Lee. Is it your perception that the State
departments of environmental quality are inadequate in this
regard, that they not capable?
Ms. Dougherty. I wouldn't say that they're inadequate, but
they can use the help. In fact, the State of Pennsylvania--the
commissioner from the State of Pennsylvania requested that EPA
do these rules.
Senator Lee. Requested that they do them so it could give
them----
Ms. Dougherty. That EPA do the national pretreatment
standards for shale gas.
Senator Lee. So----
Ms. Dougherty. I believe. I don't have a copy of the letter
with me, but a few months ago or something like that.
Senator Lee. OK. So as to give them some guidance; they
were looking for guidance?
Ms. Dougherty. So, well to give them that technology-based
standard that that would then be used, so that those sewage
treatment plants that would be receiving the wastewater would
know that it had been pretreated or what kind of limits they
need to put on it to make sure they don't do something to the
plant. That they don't end up putting wastewater out of the
treatment plant that will cause problems in the water.
There have been some issues in terms of bromide levels, in
particular, that can create problems for downstream drinking
water plants.
Senator Lee. OK. Thank you. Thank you. Chair.
Senator Shaheen. Thanks. I'm going to try and follow up on
some of those questions because I know, Ms. Dougherty, that in
your opening statement, you referred to some of the Federal
legislation under which the EPA gets involved in the issue of
shale gas production. You talked about the pretreatment
standards this afternoon.
Can you layout very easily the aspects of production that
the Federal Government has jurisdiction over versus those that
the State is involved in? Where they overlap, is that an easy--
--
Ms. Dougherty. Sure. It's not easy.
Senator Shaheen. Description?
Ms. Dougherty. I'll give you--let me just, I'll just talk
about EPA. So I'm not going to talk about the Department of
Interior where BLM has----
Senator Shaheen. Yes, good. That's fine.
Ms. Dougherty. Their own authorities. The States have the
authority to deal with oil and gas production. The EPA doesn't
deal with permitting and doesn't have authority to say, ``Yes,
you can drill here.'' That's the authority----
Senator Shaheen. Right.
Ms. Dougherty. Of the State. So the EPA gets involved and
since you're dealing with water, I'm not going to talk about
the air program either if that's OK, but I can--we can answer
that later. From a water standpoint, as I said when I was
talking about our study, there's water withdrawals. That,
again, is a State function. In some cases, like in
Pennsylvania, the Susquehanna River Basin Commission deals with
water withdrawals or other commissions might do that. So that's
not an EPA function.
There is storage of the water and the fluids that they use
for hydraulic fracturing on the site. If there are spills from
that storage, there may be things that either EPA or the State
might be involved in. There's the actual injection for
hydraulic fracturing to begin the drilling and the production.
In that case, the Safe Drinking Water Act does apply where the
driller is using diesel fuel as part of the hydraulic
fracturing fluids. Otherwise, the EPA does not have an
authority over the hydraulic fracturing injection itself.
The Chairwoman. Can you just explain why that's the case,
relative to the diesel fuel?
Ms. Dougherty. Congress in 2005 made the decision to exempt
hydraulic fracturing from the definition of injection under the
Safe Drinking Water Act. So under the Safe Drinking Water Act,
any injection of basically anything is covered by the
underground injection control program requires a permit for
that injection to take place.
Now I should say when I'm talking about injection, be it
for hydraulic fracturing or for the produced waters that I'll
get to in a minute, in most States that have a lot of oil and
gas production, the State is the permitting authority under the
underground injection control program under the Safe Drinking
Water Act for all the activity.
So even though it's a Federal law, the State has set State
laws which we've approved--which EPA, over the years, actually
decades ago in most cases, has approved as either as stringent
as, or as effect as EPA's rules for them to carry out the
program. So in most States the State is carrying out the
underground injection control permitting program, and EPA
retains an oversight responsibility, but basically, the States
are the people on the ground who are doing the work. It's very
much in a lot of States, it's in concert with the work that
they're doing on the oil and gas production side as well. Is
often, if not usually, in the same part of the State in the
same department. So it may not be in the environmental
department at all; it may be in a different department of a
State.
So then, once the hydraulic fracturing is done, there's
what's called flowback water. You correct me whenever I get
this wrong. That's called--there's flowback water that comes up
right after the hydraulic fracturing is done, which includes a
portion of the hydraulic fracturing fluid and a portion of the
water, as you said in your opening statement, somewhere in the
20 percent range; sometimes more, sometimes less.
What happens with that water probably--is likely covered by
either the Clean Water Act or the Safe Drinking Water Act. If
they reinject it, which is often done and has historically been
what's been done further west, than the UIC program, the
Underground Injection Control program covers. Again, that's the
thing, the program the States are usually carrying out that
we've approved.
If it is taken either trucked or somehow taken to a sewage
treatment plant or a centralized waste treater for discharge to
surface water, we talked about that just a few minutes ago, the
NPDES program and the pretreatment program related to that
would apply, and there are requirements, and in most cases
the--but in not all States. The State is the permitting
authority under NPDES. There are 11 States that have the NPDES
program where EPA is the pretreatment authority. Then there's
still a few States where EPA is the NPDES authority as well.
Then there's produced water, which is as they're producing
the gas, there's more water that comes out. The disposal of
that water is the same--is in the same kind of thing.
Now in both of those cases, there are other choices that
could be made. They could recycle the water. Based on what's
been happening in Pennsylvania, there's been a lot of effort
for the drillers in the Pennsylvania area to look at recycling
as a choice, and I think that's been happening across the
country.
EPA in getting information from the people who have been
sending their produced water to the wastewater treatment plants
in Pennsylvania had been telling them that they planned by this
year to be recycling up to 90 percent of their produced water.
I don't know whether that's actually happened or not, but
there's definitely a movement to do that.
So if they recycle it, then there's not a permit that
applies under either the Clean Water Act or the UIC program.
That water's reused for the next hydraulic fracturing along
with the other water. They need to replenish it since there
won't be as much as they would need. So that, I think, that
covers pretty much everything.
But the States, you know, the States are doing their normal
permitting program in terms of oil and gas, and they have
requirements in terms of--they have requirements not just in
terms of the sighting of the wells, but also the construction
of the gas wells and the operation of those wells. Those vary,
depending on the State.
Where the UIC program comes into play, there are a number--
there are obviously lots of criteria that we have in terms of
what happens. If there are other issues, there are emergency
response authorities that we have. There are other issues that
I didn't mention in terms of air. There are some issues in
terms--there are some authorities in terms of TSCA that might
apply in terms of the kinds of chemicals that might be used.
NEPA will apply if Federal lands are involved, which happens
with BLM.
Senator Shaheen. So not an easy delineation.
Ms. Dougherty. No.
Senator Shaheen. Thank you. That's very helpful. I have,
actually, some follow up questions on that, but my time is
over, so I'm going to turn it over to Senator Lee first.
Senator Lee. How often is diesel fuel used in the injection
fluid?
Ms. Dougherty. I don't actually know. We believed back when
the Energy Policy Act was passed in 2005 that it was not going
to be used a lot, because we had an agreement with 3 major
hydrofracking companies that they wouldn't use diesel fuel any
longer in their coal bed methane hydrofracking. But then as the
world changed in terms of what was happening with shale gas, we
understand from discussions with people and from things that
people have said in meetings and from information that some
Members of Congress have collected that it's being used a lot
more than we thought it was. How much, I'm not----
Senator Lee. Do you----
Ms. Dougherty. It's part of the fracking fluid, which is
not a huge part of the volume, but it is being used.
Senator Lee. Right. Once that's used in the fracking fluid,
then that changes the regulatory framework that you apply.
Ms. Dougherty. That does change the regulatory framework,
yes.
Senator Lee. That's as a result of the language of the
exemption placed in the Energy Policy Act----
Ms. Dougherty. Yes.
Senator Lee. Of 2005.
Ms. Dougherty. Yes.
Senator Lee. Which provided that the exemption would not
apply, but did it specifically mention diesel fuel or was it?
Ms. Dougherty. Diesel fuel
Senator Lee. OK.
Ms. Dougherty. Specifically.
Senator Lee. OK. Thank you.
Senator Shaheen. I want to go back to a couple of things
that--to make sure I understood you correctly. When you were
talking about the water that was being used, you said, ``Now
about 90 percent of it is being recycled,'' or that's at least
what----
Ms. Dougherty. That's what the companies----
Senator Shaheen. That's been suggested.
Ms. Dougherty. That have called our regional office in--
that deals with Pennsylvania. So that's not necessarily the
case elsewhere.
Senator Shaheen. Right, and----
Ms. Dougherty. That may not be the case in Pennsylvania yet
either, but that's what they said they had--they intended to
do.
Senator Shaheen. Is there any jurisdiction over that
recycling of water, or does it matter because it's all being
used for the same process and?
Ms. Dougherty. There would be 2 places where there might be
jurisdiction. One is if it's recycled it in a way that it's
treated before it's reused, then there might be a residual from
the treatment, and then what happens to that residual would be
probably covered by either a State and possibly EPA, but by
some State authority.
If the residual is used or the water is used in another way
to--in some cases there have been brine waters from gas
production that have been used for deicing, there would be
State requirements related to that.
Senator Shaheen. There have been some press reports that
the brine, when it gets reused, actually maybe the States are
not regulating, but there has been some suggestion that it's
being used without a real examination of what the impact might
be. So if it were used on roadways for deicing or if it were
used in other circumstances that there's no real regulation of
what the content of that might be.
Ms. Dougherty. I don't have information for every State,
but I do have some information from Ohio and Pennsylvania both
where they have--where they permit any use of brine for, I
believe, for deicing. They have limits in terms of what the
quality of that, of the brine can be. It's quite likely that
Marcellus Shale brine would not meet the requirements, or at
least in the case of one of the permits. You don't know any? I
don't know any more about that.
Senator Shaheen. Do you want to add to that, Dr. Russ? Do
you have any additional information?
Mr. Russ. I know that in most of the examples I'm familiar
with from visits to the area that most of the flowback water is
secured in tanks, or sometimes through pipeline and sent to
other well sites.
I've been told that on one or so occasions when some
flowback water is received that samples are taken for analysis
to see what might be in it. But before the analysis are made or
at least received back for consideration, that the water is
consigned for other uses, including things like spraying as
dust suppressant on roads in upstate Pennsylvania, for example.
Senator Shaheen. What would be in that brine that might
make it harmful?
Mr. Russ. Things such as radium.
Senator Shaheen. That would come up as the result of
drawing the water out of the ground. So it would be existent in
the water as it was in the ground?
Mr. Russ. Possibly. Each flowback water situation is
different, as Ms. Dougherty said. The amount of flowback varies
well to well, and therefore the composition of what might be in
the water varies as well.
Senator Shaheen. OK. Casing and cementing are obviously key
as we look at the potential for seepage into the water table.
Can you, either of you, speak to whether well design including
the casing and the cementing is being adequately regulated at
the State level?
Ms. Dougherty. Actually, Lori might be able to help you
better more on----
Senator Shaheen. OK. I will----
Ms. Dougherty. That one, when you talk to her.
Senator Shaheen. Reserve that for the next panel then.
Ms. Dougherty. Where there's a UIC permit involved, we have
specific requirements related to well casing and cementing, but
that's where a permit's required.
Senator Shaheen. OK. Thank you. I don't have any further
questions for either of you. Senator Lee?
Thank you both very much.
Ms. Dougherty. Thank you.
Mr. Russ. Thank you.
Senator Shaheen. I appreciate it.
Mr. Russ. Thank you.
Senator Shaheen. If we could ask the next panel to come up.
Good afternoon, everyone. Thank you all for joining us, and
hopefully we won't be too much later than you were anticipating
for this panel.
I am going to start with you, Ms. Wrotenbery, for your
testimony. So if you would like to begin.

STATEMENT OF LORI WROTENBERY, DIRECTOR, OIL AND GAS
CONSERVATION DIVISION, OKLAHOMA CORPORATION COMMISSION

Ms. Wrotenbery. Thank you, Chairman Shaheen and Ranking
Member Lee.
Appreciate the opportunity to come talk to you today about
what the States are doing to review and update their
regulations to make sure that shale gas development is being
conducted safely. There is a lot of work going on at the State
level across the country.
In my written testimony, I went into some detail about some
things going on in Oklahoma, but I understand the focus today
is on the eastern United States, so I'll just say that I
provided that information as just an example of the kind of
work that's going on. I do know the same kind of effort is
underway in the Marcellus Shale States. I have heard reports,
actually earlier this week from a number of my counterparts in
States, in Marcellus Shale States about what they have going on
and what the status of their efforts are.
We had a meeting of the Interstate Oil and Gas Compact
Commission in Buffalo earlier this week, and my counterparts
from New York, and Pennsylvania, and Ohio, and other States
were there and gave reports on the status of their regulatory
development work.
They also talked about the challenges they're facing, and
we are all addressing challenges that are associated with shale
gas development. The challenges vary from State to State, and
region to region. So the particular character of the
challenges, you have to look at the individual State and see
what's underway there to really understand them. But there are
some things in common with horizontal drilling and the
multistage hydraulic fracturing operations that are being used
to free up the gas from the shale reservoirs.
You've got a lot of water involved. You've got a lot of
freshwater that's required to make up the hydraulic fracturing
fluid. Then when you flowback the water, in order to begin
producing the well, you have a large volume of wastewater to
manage. That scenario is being addressed by a number of States.
I will say the States are all acting to address those
challenges, and I would refer you to some of the reports that
STRONGER has issued over the last year.
STRONGER is a stakeholder organization. It was originally
set up by the Interstate Oil and Gas Compact Commission and the
U.S. Environmental Protection Agency to help benchmark State
regulations for oil and gas waste management. To develop
guidelines for effective State regulatory programs and to
review State programs against those guidelines. Over the years
this process, this stakeholder process has been used to
evaluate State programs. In fact, 21 States over the years have
been reviewed under the STRONGER process.
Most recently, STRONGER convened a workgroup to develop
some guidelines specifically addressing hydraulic fracturing
and some of the issues that have arisen concerning hydraulic
fracturing, and the safety of hydraulic fracturing operations,
and the effectiveness of the State regulations.
The guidelines were developed by a stakeholder workgroup.
Everything STRONGER does is done by stakeholder teams and
stakeholder workgroups with equal numbers of representatives
from the State regulatory community, the industry, and the
environmental community.
So it was a stakeholder process. Guidelines were developed
and then since then, STRONGER has done reviews of already 5
States using the hydraulic fracturing guidelines. Pennsylvania
and Ohio were first and they were shortly followed by Oklahoma,
Louisiana, and Colorado. The Colorado report just came out
earlier this week. A STRONGER team is going to Arkansas in
November to review the hydraulic fracturing regulations there.
But if you look at the State reports, I think you'll see
documented there what kinds of challenges the States are facing
in regulating shale gas development, and how the States are
addressing those challenges.
I also wanted to just mention briefly FracFocus. This is
another State effort that's underway to try to address the
public's desire for information about hydraulic fracturing and
what kind of chemicals are used in hydraulic fracturing fluids.
This is a Website that was set up by the Ground Water
Protection Council and the Interstate Oil and Gas Compact
Commission to provide information about hydraulic fracturing
and also to set up a chemical registry where companies can
report the chemical constituents of their hydraulic fracturing
fluids.
I've given you the latest statistics on that site, but
we've got over 5,000 wells now that have been reported on the
FracFocus wellsite--Website.
Also I should say, right now the system is a voluntary
system. It was set up that way, but a number of the States are
adopting requirements that operators use that system to report
on the chemical constituents of their frac fluids. So we are
seeing more and more of the companies reporting their wells
through that FracFocus Website.
That's a very quick summary of my written testimony, but
I'll end there and be happy to address any questions.
[The prepared statement of Ms. Wrotenbery follows:]

Prepared Statement of Lori Wrotenbery, Director, Oil and Gas
Conservation Division, Oklahoma Corporation Commission

Thank you for the opportunity to testify today about the actions
being taken by states to address the potential impacts on their water
resources from the development of their shale gas resources. I very
much appreciate your interest in hearing the perspective of a state
regulator on how states are working with oil and gas operators, local
communities, environmental organizations, and other stakeholders to
realize the economic potential of our natural gas resources while
ensuring public safety and protecting the environment.
Recent technological developments have given us access to natural
gas resources held tightly in shale formations. We welcome this new
opportunity. We also recognize the challenges it presents, particularly
to those of us who work on a daily basis to manage and protect our
precious water resources. To address these challenges, states across
the nation are actively reviewing and updating their regulatory
standards and procedures to ensure that shale gas drilling and
production operations are conducted safely. States are also continually
testing, evaluating, and strengthening the mechanisms they have in
place to develop, implement, and enforce sound regulations.
To give you a sense of the breadth and vitality of these state
efforts, I would like to briefly summarize activities in three areas:
(1) recent regulatory developments in the State of Oklahoma, which are
in many ways specific to the particular circumstances there, but also
have much in common with efforts underway in other shale gas states,
including those in the eastern United States; (2) the work being done
through the stakeholder process called ``STRONGER'' to assist the
states in benchmarking and improving their environmental regulations
for oil and gas drilling and production operations; and (3) the
development by the Ground Water Protection Council (GWPC) and the
Interstate Oil and Gas Compact Commission (IOGCC) of the website called
FracFocus and the chemical registry and other information available to
the public on that website.
Regulatory responses to development of the Woodford Shale in Oklahoma
Oklahoma has a long history of oil and gas exploration and
production. The first commercial oil well was completed in 1897.
Subsequently over half of a million oil and gas wells are estimated to
have been drilled in the state.
I've attached a *fact sheet to this testimony to give you an idea
of the nature and extent of oil and gas operations in the State of
Oklahoma. We presently have about 190,500 active wells in Oklahoma-
roughly 115,000 oil wells, 65,000 gas wells, and 10,500 injection
wells. They are widely distributed throughout most of the 77 counties
in the state.
---------------------------------------------------------------------------
* Fact sheet has been retained in subcommittee files.
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In the early days most of the wells were drilled for oil. In recent
decades, however, natural gas has dominated the exploration and
production activity in Oklahoma. While crude oil is still a vital and
highly valued component of the state's economy, Oklahoma today is truly
a natural gas state. Assisted by advances in horizontal drilling and
hydraulic fracturing technology, oil and gas operators in Oklahoma are
actively developing the Woodford Shale.
The Oklahoma Corporation Commission (OCC) was established at
statehood in 1907 and was first given responsibility for regulating oil
and gas production in Oklahoma in 1914. OCC regulates public utilities,
trucking, pipelines, petroleum storage tanks, and various other
activities as well as oil and gas drilling and production.
The OCC is headed by three statewide-elected officials who serve
staggered six-year terms. The Commission sets policy by adopting rules.
The Commission also meets in public on a daily basis to issue orders
based on the record created through formal, evidentiary hearings in
various permitting, ratemaking, and enforcement proceedings.
My division, the Oil and Gas Conservation Division, is responsible
for implementing and enforcing the rules and orders of the Commission
for oil and gas exploration and production operations. Regulating the
drilling, completion, and production of the multitude of oil and gas
wells in the state requires a full complement of specialists:
engineers, geologists, hydrologists, attorneys, technicians, and
inspectors. These are the professionals I work with every day to ensure
oil and gas operations in Oklahoma are conducted in compliance with the
Commission's rules and orders.
All of these individuals, from the Commissioners on down, play key
roles in our organization, and I don't wish to slight any of them, but
I wish to emphasize the importance of our field staff. Our most
fundamental regulatory operations occur in the field, not in an office.
I believe our field inspectors are the single greatest strength of our
regulatory program.
Our 58 field inspector positions cover the state. Field inspectors
are required by statute to live within 37.5 miles of their territories.
They work out of trucks that are fully equipped as mobile offices with
computers, GPS units, field sampling kits and other equipment they
require on a daily basis. They are the first point of contact for most
of the people we serve-oil and gas operators, landowners, local
government officials, and others. Our field inspectors are truly
members of the communities they serve-indeed many of them grew up in
the same or nearby communities. They are required to have prior
experience working in the oil and gas field, so they understand the
operations they are inspecting. And they spend most of their working
hours traveling the area lease roads, so they know their territories
like few others. In case of an emergency, they can be on location
within an hour in all but the most remote parts of the state.
Our field inspectors must meet high standards of conduct and
performance-they are expected to inspect the operations and enforce the
rules fairly, consistently, and appropriately. And they strive to meet
these standards. They have earned our trust and respect, and the trust
and respect of their communities, time and again. They don't always get
the recognition and respect they deserve, so I'm pleased to have the
opportunity to highlight their contribution here today.
Our field inspectors are our greatest strength, but they are not
our only strength. Other strengths I would like to emphasize today
relate to: (1) the complementary nature of our regulatory functions;
(2) the way we have adjusted rapidly to new technologies and other
emerging issues; and (3) our ability to tailor our rules to address
unique areas and special circumstances.
Complementary regulatory functions
OCC regulates oil and gas exploration and production to
conserve oil and gas resources, protect the rights of mineral
interest owners, and protect public health and the environment.
In the early days, our regulations no doubt focused on
protecting the oil and gas resources. In fact, some of the
earliest requirements to case wells with steel pipe were
designed to keep water from damaging the oil and gas zones
rather than to protect the water zones. Regardless, the
requirement to separate the water zones from the oil and gas
zones served to protect both.
The complementary nature of these requirements has become
increasingly apparent over the decades as we have worked to
ensure that our precious water resources are protected from oil
and gas and associated saline waters. The same casing and
cementing requirements that isolate the gas in its formation
until it can be produced up through tubing and casing and into
pipelines for transportation to market don't just prevent waste
of oil and gas and protect mineral rights, they also protect
our fresh water resources.
As another example, the spacing requirements that are
designed to ensure the orderly development of our oil and gas
resources play a role in controlling the surface impacts of oil
and gas development. In its 2011 Regular Session, the Oklahoma
Legislature established new mechanisms for the creation of
special units and the drilling of multiunit wells to allow the
drilling of horizontal shale gas wells across section
boundaries. These new mechanisms will facilitate the drilling
of longer laterals, which will also reduce the surface
footprint of shale gas development in the state.
Evolution of regulation
The example of the new legislation for shale gas drilling
illustrates how the State of Oklahoma has rapidly adapted to
new technologies and addressed emerging issues. In recent years
the OCC has engaged in an annual review of its oil and gas
regulations and adopted changes to address new technologies,
emerging issues, and other developments. Through this process
of continuing assessment and adjustment, the OCC ensures that
its rules remain current and effective.
For example, perhaps the biggest environmental issue
associated with development of the Woodford Shale in Oklahoma
has been how to accommodate the recycling of flowback water. We
encourage recycling of flowback water as a way to reduce the
demand on our freshwater resources. Recycling on a large scale,
however, has required the use of pits for temporary storage of
flowback water. Oklahoma rules did not allow for storage of
produced waters in pits. In 2009 the OCC initiated a rulemaking
process to develop standards and procedures for the permitting,
construction, operation, and closure of pits for the recycling
of flowback waters. The new rules went into effect in July
2010. And we continue to evaluate how they are working. Based
on our initial experience with the new rules, the OCC has
already made some amendments that went into effect in July
2011.
Special area rules
Most communities in the State of Oklahoma are well acquainted
with the nature of oil and gas drilling and production
operations. The City of Oklahoma City, where I live, is the
location of one of the state's largest oil fields and dealt
early on with the challenges of drilling and production in an
urban environment. Oklahoma City is also recognized nationally
for the quality of its tap water. Oklahoma City draws its
drinking water from surface water supplies of exceptionally
high quality and works effectively with the OCC and others to
ensure that oil and gas operations do not adversely affect
those supplies.
The OCC has procedures for special area rules to protect
municipal water supplies. Any municipality or other
governmental subdivision may apply for a Commission order
establishing special area rules to protect and preserve fresh
water. The Commission has issued hundreds of these special
orders over the years.
Of particular relevance to our discussion today, the OCC
recently reviewed, updated, and strengthened the special area
rules for oil and gas operations in the watersheds of Lake
Atoka and McGee Creek Reservoirs. These truly pristine lakes in
southeast Oklahoma supply water to Oklahoma City about 100
miles away. Special area rules had been initially adopted in
1985, but the recent upswing in drilling activity in the area
raised issues that need to be studied and addressed.
As is typical of our rulemaking proceedings, a rather large
workgroup of stakeholders, including the City of Oklahoma City,
rural water districts, counties, tribes, oil and gas operators,
and others, assisted OCC staff in identifying the issues,
considering options, and developing recommendations for
consideration by the Commission. On the basis of those
recommendations, the Commission proposed rule amendments that
were ultimately adopted with the support of the stakeholders.
The amended rules, which became effective in July 2009,
established new setback requirements from the shores of the
lakes, required containment structures around drilling
locations, and included other provisions to prevent runoff of
soil, salt, and other pollutants into the lakes. They also gave
oil and gas operators some additional flexibility in meeting
pit liner requirements in those locations far enough from the
lakes that the use of pits is allowed. These special area rules
illustrate the kinds of accommodations that can be reached when
the stakeholders work together to figure out how to develop our
oil and gas resources while protecting our water resources.

I have given you examples of the work we are doing in Oklahoma to
ensure that development of our shale gas resources does not impair our
water resources. Similar efforts are well underway in shale gas states
across the country, including the states within the Marcellus and Utica
Shale Basins. For five states already, including Pennsylvania and Ohio,
these efforts are reflected in reports issued by the STRONGER
stakeholder organization on its review of their hydraulic fracturing
regulations.

STRONGER reviews of state oil and gas regulations
STRONGER has completed hydraulic fracturing reviews in five states
now: Pennsylvania, Ohio, Oklahoma, Louisiana, and Colorado. A STRONGER
team will be meeting in Little Rock early next month to conduct a
review of the Arkansas hydraulic fracturing regulations. I have
participated as a team member in each of the reviews, except of course
in Oklahoma where I sat on the other side of the table. I wish to share
with you what I've learned as a participant in the STRONGER hydraulic
fracturing reviews, but first, please allow me to give you a little
background on STRONGER.
The name, STRONGER, is short for State Review of Oil and Natural
Gas Environmental Regulations, Inc. STRONGER is a multi-stakeholder
collaborative effort to: benchmark state regulatory programs; develop
guidelines for effective state regulatory programs; and conduct reviews
of state regulatory programs against those guidelines.
STRONGER is governed by a board of stakeholders. A copy of the
current board roster is attached to this testimony. The board includes
three representatives from each of three stakeholder groups: state
regulators, environmental organizations, and oil and gas producers.
Likewise, all STRONGER efforts, such as guidelines development
workgroups and state review teams, involve the same balanced
representation of the stakeholder groups.
When STRONGER reviews a state's hydraulic fracturing regulations,
the STRONGER stakeholder review team takes the time to review the
materials provided by the state describing its hydraulic fracturing
regulations, listen to a presentation by the state on its standards and
procedures, and discuss with the state how the state addresses the key
program elements laid out in the STRONGER hydraulic fracturing
guidelines. The review team then prepares a report that discusses the
state program and makes findings and recommendations based on the
STRONGER guidelines. In the report, the review team highlights the
program strengths and accomplishments, as well as identifying areas for
improvement. All of the STRONGER hydraulic fracturing reports are
posted on the STRONGER website (www.strongerinc.org).
The reports prepared by the stakeholder review teams speak for
themselves, and the observations I am about to share with you are my
own, not those of STRONGER or of any particular review team. Having
participated in each of the hydraulic fracturing reviews completed to
date, however, I believe the reports document the fundamental strengths
of the state programs as well as the decisive actions states are taking
to meet the challenges of shale gas development. The findings of the
Oklahoma hydraulic fracturing review and similar stakeholder reviews
conducted in other states show that the states are well equipped to
regulate hydraulic fracturing. These reports also document that each
state has experienced challenges in regulating hydraulic fracturing in
today's environment, that the specific nature of the challenges varies
from state to state, and that each state has taken actions in a manner
appropriate to its particular circumstances to ensure that hydraulic
fracturing operations are conducted safely.
Most importantly, the reports contain specific recommendations for
improvement. The STRONGER stakeholder organization looks forward to
returning to the states to learn how they have responded to the
STRONGER recommendations. At this point, I can tell you that Oklahoma
has already made one rule amendment recommended by the STRONGER review
team and made an additional appropriation for field staff based in part
on another STRONGER recommendation. My division has convened a
workgroup to address our reporting requirements for hydraulic
fracturing operations and will be considering the STRONGER
recommendations on those requirements as well as other developments.
So, I can attest that the process is working to help the states in
their ongoing efforts to maintain strong, effective regulatory
programs.
Please note that the hydraulic fracturing reviews have been the
principal focus of STRONGER's effort for the last couple of years, but
STRONGER has a broader mission. STRONGER's hydraulic fracturing
guidelines are but one chapter in its guidelines for state oil and gas
environmental regulations. The state review process was originally
established by the Interstate Oil and Gas Compact Commission and the
U.S. Environmental Protection Agency to address the management of
wastes associated with the exploration and production of oil and gas.
Over the years the process has addressed other significant issues,
including abandoned sites, naturally occurring radioactive material
(NORM), stormwater management, spill risk management, and program
planning and evaluation. And STRONGER continues to review and update
the guidelines as needed to address emerging issues. In addition to
reviewing the hydraulic fracturing guidelines to make adjustments based
on the experience gained through the hydraulic fracturing reviews,
STRONGER is now convening a workgroup to consider developing guidelines
to address the air issues that have arisen in the shale gas basins.
To date, 21 states have been reviewed under the full set of
guidelines. The attached map of the United States shows the status of
reviews in the various states. The states that have been reviewed
account for over 90% of onshore production in the U.S.
North Carolina has volunteered to be the 22nd state to undergo a
full review. The in-state portion of the North Carolina review will
occur next week. North Carolina's request for a STRONGER review is one
of several steps the state is taking to prepare for the future
development of the Marcellus Shale there.
STRONGER also conducts follow-up reviews to determine how the
states have responded to review team recommendations. Ten of the 21
states that have been reviewed have had at least one follow-up review.
Through the follow-up reviews, the review teams have found that fully
three-quarters of the recommendations from prior reviews have been met.
The review teams also found that work on other recommendations was in
progress though not yet complete. For an entirely voluntary process, I
find that record of accomplishment most impressive.

FracFocus
In addition to working with stakeholders to evaluate and improve
their programs, the states are working collectively to provide
information to the public on hydraulic fracturing operations. Two state
organizations have led this effort: the Ground Water Protection Council
(GWPC), an organization of state ground water protection agencies,
including oil and gas regulatory agencies like mine; and the Interstate
Oil and Gas Compact Commission (IOGCC), a compact of the Governor's of
the oil and gas producing states.
In September 2010, the GWPC Board of Directors passed a resolution
expressing GWPC's intent to develop, in concert with other state
organizations, a web-based system to enhance the public's access to
information concerning chemicals used in hydraulic fracturing. The GWPC
then partnered with IOGCC to develop the chemical registry and website
called FracFocus.
Over the next six months a system was developed that allows oil and
gas companies to upload information about the chemicals used in each
hydraulic fracturing job. This system was augmented by a website that
provides a way for the public to locate and review records of hydraulic
fracturing conducted on wells after January 1, 2011. The website also
contains information about the process of hydraulic fracturing,
groundwater protection, chemical use, state regulations, and relevant
publications. It provides links to federal agencies, technical
resources, and each participating company.
And FracFocus will continue to evolve. A recent enhancement to the
site is a Geographic Information System interface that will aid the
public in locating well records. Future enhancements to the site will
include expanded search capabilities and links to more publications,
state agencies, and other resources.
The FracFocus website, www.fracfocus.org, was launched on April 11,
2011. Within its first six months of operation, 66 companies have
agreed to participate in the effort, more than 5200 wells have been
loaded into the system by 49 of these companies, and the website has
been visited more than 65,000 times by people in 125 countries. To give
you an idea of the kind of information being reported to FracFocus,
attached is an example of a report on the hydraulic fracturing fluid
composition for a well in Pennsylvania.
The states are informing their oil and gas producers about the
FracFocus chemical registry and encouraging them to use it. In
addition, a number of states are now adopting or considering chemical
reporting requirements that incorporate the FracFocus chemical
registry.

Senator Shaheen. Thanks very much.
Mr. Beauduy.

STATEMENT OF THOMAS W. BEAUDUY, DEPUTY EXECUTIVE DIRECTOR &
COUNSEL, SUSQUEHANNA RIVER BASIN COMMISSION

Mr. Beauduy. Thank you. Appreciate it. Thank you. We
appreciate it, Ranking Member Lee as well, and members of the
committee for the opportunity to testify in front of you today.
The Susquehanna River Basin Commission, some may not know,
is a fairly unique animal of government. It is a Federal
interstate compact commission. There are lots of interstate
water commissions across the country. There are only a few of
us that are Federal interstate compact commissions with the
Federal Government as a full voting member along with the
member jurisdictions. We have full water resource management
authority that's been delegated to us, the sovereign authority
of our member States to act and exercise that authority on
behalf of the entire Basin.
The Marcellus Shale play underlies about 72 percent of the
Susquehanna Basin which, by the way, extends from Cooperstown,
New York to the top of the Chesapeake Bay at Havre de Grace,
Maryland, and comprises 27,500 square miles. It's a large area.
It's a fairly rural area. It's a fairly mountainous area.
The Marcellus Shale play underlies 72 percent of that and
we consider ourselves to be sort of in the sweet spot of
Marcellus Shale activity. We've done a lot of it. It came to
town, it came to our Basin in mid 2008. We've got 3 years of
effective operating history with it, and I'd like to share a
little bit of that information with you, because I do think
there are some distinctions between what's happening here in
the eastern part of the play versus other plays across the
country.
First, I'll tell you that when this industry came to town
we, like some of the States, were not that well prepared to
deal with it, and so this has been a very dynamic process. You
just heard about the States streamlining their regulatory
programs to meet these challenges. We have modified our
regulatory package 3 times in the last 3 years trying to make
sure that we have the right set of management controls in place
to allow this activity to occur and at the same time, avoid any
impact.
We developed a special set of rules for Marcellus, not so
much because of the total quantities of water involved, and
I'll speak to that in a second, but because of the timing and
location of the withdrawals. Most of this activity is occurring
in very rural, mountainous areas where there are lots of
headwater streams, a lot of pristine trout streams. So special
safeguards need to be built in because unlike most other
industrial activity, which is down on the valley floor along
the main stem river along main tributaries, this activity is an
industrial activity is occurring up in the hinterland, so to
speak, and so we had to develop some special rules.
The first thing we did was our standard 100,000 gallon a
day threshold for when you have to come in to get an approval.
We set it aside and we said for the natural gas industry, ``We
need to regulate you starting at gallon one,'' and the industry
accepted that and we regulate every single withdrawal that's
occurring throughout the Basin on a gallon one basis.
We did a number of other things given the nature of this
industry as well. We saw the opportunity to incentivize water
sharing amongst the companies because we didn't need 15
companies lining up on the same watershed to get water on 1 or
2 locations that they could share those locations would work.
So we incentivize water sharing.
We incentivize the use of lesser quality water. The
unfortunate reality in the Susquehanna Basin is we have some
legacy to deal with from coal extraction. We've got acid mine
drainage in some of our streams, and to be able to utilize AMD
instead of freshwater seemed to make sense.
The use of effluent, the recycling of flowback and
production fluids, you heard some of that from the last panel.
We provide incentives for that to occur and we are seeing it
occurring in a very significant way in our Basin.
What are we seeing? So far, we have issued 150 water
withdrawal approvals for this industry. We regulate water
withdrawals and consumptive use. The consumptive use of water
occurs at the drilling pad site, and we have issued approvals
for 1,600 drilling pads in this Basin so far.
We also require event-specific, post-hydrofracture
reporting in addition to a quarterly monitoring reporting above
withdrawals and consumptive use. Based on what we're seeing
with the post-hydrofrac data, so far we've got--we've had over
1,000 wells fracked in the Basin. I'm going to share a few
numbers with you that are based on the last 4 quarters because
the 8 preceding quarters, a lot of the frac data was mixed in
with exploratory work and the like. So, the numbers aren't as
reflective as the current pattern, the most mature production
pattern that we've seen over the last 4 months--4 quarters, I'm
sorry.
First of all in terms of quantity of water, this industry
right now is withdrawing approximately 7 million gallons a day
of water. It's consumptively using about 10 million gallons a
day. How does this stack up?
When we looked at the industry, we looked at water use in
the Barnett, in the Hayneville, in the Fayetteville Shales. We
tried to extrapolate that data to our Basin to develop an
estimate because from a cumulative impact standpoint, we wanted
to get a handle on, at least make an estimate of what we
thought the potential was here. That estimate is 30 million
gallons per day. Right now, there are 10 million, but they
haven't gone to full production yet. So whether we modify that
estimate moving forward or not, I can't tell you, but I think
we need to be looking at it dynamically all the time.
Additionally, I will tell you that the amount of water
being utilized on a per-well basis is running about 4.5
million. It's--quite honestly, what we're seeing, the
correlation that we see is for every 1,000 feet of horizontal
lateral, we're seeing 1 million gallons of water use. So we're
seeing wells running anywhere from 4 to 8 million gallons, if
they have extreme horizontal laterals in their design. But the
average over the last 4 quarters has been about 4; a little
less than 4 1/2 million gallons of water.
What's unique to the eastern part of this play is that it's
very dry. It's extremely dry. Unlike other areas of the
country, this gas comes out pipeline ready. It doesn't have to
be treated. It's that clean. But that means those formations
are not only tight, they're dry and they hold back the water.
So when you looking at 4 1/2 million gallon frac job, the
flowback that comes from that, once they release the pressures,
is about 5 percent right now. It's been ranging between 5 and
12 percent, which is unlike most of the other return flows in
the country. But right now, where the activity is in our Basin,
we're down around 5 percent. So there's very little flowback
coming back and virtually all of it is being recycled. I can
tell you that as well.
As a result of the rules that Pennsylvania is working on
and the request that was made by the Governor until his new
rules got into effect, the industry no longer takes any
flowback or production fluid to wastewater treatment plants in
our Basin; publicly owned wastewater treatment plants in our
Basin.
There are treatment plants. We had permitted some. We're
not involved in water quality permitting, but we have permitted
any of those treatment facilities that are adding water as part
of the treatment process. But all the flowback and production
fluid is going from pad to pad, or alternatively, from pad to
treatment facility and then back to pad for down hole purposes
for hydrofracture stimulation on the next well. That's what
we're seeing.
I will also just tell you that we have deployed a remote
water quality monitoring network because--and we provide a
support function to our member jurisdictions who have the lead
on water quality controls for this industry. But we play a
support role and we have deployed a 50 station remote water
quality monitoring network; 50 watersheds throughout the
Marcellus Shale play where we have real time data. We're
analyzing for 6 parameters every 5 minutes, 24 hours a day, 365
days a year. That data is going to a Website. We make that
available to all the water resource agencies, to the industry,
and to the general public in, you know, in an attempt to be as
transparent as possible.
We are monitoring all these locations. We started putting
them in, in January 2010. The last one went in, in August of
this year. We have at least 37 of those stations that have
enough data now that we can begin to do analyses. We should
have our first report published in approximately 4 months.
Sometime in January, we will have the first report out.
I can tell you, based on what the data is showing us, that
water quality is remaining within normal ranges. We also do
grab sampling to look at specific parameters related to this
industry: barium, a whole series of constituents that, as well
as gross alpha and beta, the radionuclides and the like. What
we are seeing is that the water quality is staying within
normal limits. We have seen a few spikes that have resulted in
additional investigations. But by and large, that monitoring
network is there for the public to see, for the resource
agencies to use, and thus far, we're seeing things generally
staying in normal range.
Thank you.
[The prepared statement of Mr. Beauduy follows:]

Prepared Statement of Thomas W. Beauduy, Deputy Executive Director &
Counsel, Susquehanna River Basin Commission

I. Introduction
Let me start off by thanking the Chair, Senator Shaheen, as well as
Ranking Member Lee and all subcommittee members for the opportunity to
appear before you today on behalf of the Susquehanna River Basin
Commission (Commission) to address water resource issues associated
with shale gas development in the eastern United States.
The Susquehanna River basin is in the heart of the Marcellus shale
play, which underlies 72% of the land area of the basin. The basin
itself is 27,512 square miles and extends from Cooperstown, New York,
to the head of the Chesapeake Bay at Havre de Grace, Maryland.
Attachment 1 depicts the basin and the geographic extent of the
Marcellus shale formation.
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* Attachments 1-5 have been retained in subcommittee files.
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Geologically, the basin is home to a number of other tight shale
formations that have, as of yet, an undetermined amount of recoverable
natural gas. The level of recoverable gas beyond what is currently
anticipated from the Marcellus, and the level of development activity
and water use associated with it will become better known as
information becomes available from exploratory work that is currently
underway. These formations, in combination with the Marcellus, underlie
85% of the basin.
My comments today will reflect the management controls we have
developed in response to shale gas development activity generally, and
what we are currently seeing with regard to development of the
Marcellus shale formation specifically.

II. Background--Water Allocation and Consumptive Use Management in the
Basin
The Commission was created in 1971 as a result of the enactment of
the Susquehanna River Basin Compact (Compact) by the states of
Maryland, Pennsylvania and New York, and by the United States.
\1\Formed as a federal-interstate compact commission, the Commission is
vested with broad statutory authority to manage the water resources of
the basin, including the authority to allocate the waters of the
basin.\2\ It serves as a forum for the joint exercise of the sovereign
authorities delegated to it by its member jurisdictions.\3\
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\1\ Susquehanna River basin Compact, P.L. 91-575; 84 Stat. 1509 et
seq. (1970).
\2\ Susquehanna River basin Compact, Article 3, Powers and Duties
of the Commission.
\3\ ``The water resources of the basin are subject to the sovereign
rights and responsibilities of the signatory parties, and it is the
purpose of this compact to provide for a joint exercise of these powers
of sovereignty in the common interest of the people of the region.''
Susquehanna River Basin Compact, Sec. 1.3.2.
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The Commission has utilized its Compact authority\4\ to develop a
regulatory program to manage the resource impacts of projects using the
waters of the basin, to avoid conflicts, and to provide standards to
promote the equal and uniform treatment of all water users without
regard to political boundaries.\5\
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\4\ Susquehanna River Basin Compact, Sec. 1.3.5 and Sec. 3.10.
\5\ 18 CFR Parts 806-808.
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Fundamentally, the regulatory program requires review and approval
of any project proposing to withdraw 100,000 gallons per day (gpd) or
more, based on a 30-day average, from groundwater or surface waters, or
the consumptive use of 20,000 gpd or more, also based on a 30-day
average.\6\ By definition, diversions of water out of the basin are
considered to be a consumptive use and are subject to a similar 20,000
gpd threshold.\7\ Diversions into the basin, regardless of quantity,
are likewise subject to review and approval.\8\ As expressly provided
in the Compact, no allocation made pursuant to the authority of the
Commission constitutes a prior appropriation of the waters of the basin
or confers any superiority of right with respect to the use of those
waters.\9\
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\6\ 18 CFR Sec. 806.4(a)
\7\ Id.
\8\ Id.
\9\ Susquehanna River Basin Compact, Sec. 3.8.
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With regard to groundwater withdrawals, the Commission requires
project sponsors to conduct a 72-hour, constant-rate aquifer test
pursuant to a pre-approved test plan with provisions for a groundwater
availability analysis to determine the availability of water during a
1-in-10 year recurrence interval.\10\
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\10\ 18 CFR Sec. 806.12. See also SRBC, Aquifer Testing Guidance,
Policy No. 2007-01 (December 7, 2007).
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For withdrawals generally, the Commission may limit, condition or
deny a request to avoid significant adverse impacts, including
cumulative adverse impacts, to the water resources of the basin.
Limitations are imposed on approved amounts (both quantity and rate)
needed to meet the reasonably foreseeable needs of the project without
causing such impacts.\11\ Adverse impacts include: excessive lowering
of water levels; rendering competing supplies unreliable; causing
permanent loss of aquifer storage capacity; degradation of water
quality that may be injurious to any existing or potential water use;
adversely affecting fish, wildlife or other living resources or their
habitat; and substantially impacting the low flow of perennial
streams.\12\
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\11\ 18 CFR Sec. 806.23(b)(1).
\12\ 18 CFR Sec. 806.23(b)(2).
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In taking action on requests for withdrawals, both surface and
groundwater, the Commission relies on guidelines it has developed to
make determinations on appropriate passby flow and conservation release
values to include as conditions to approvals.\13\ The guidelines are
used to protect aquatic resources, competing users, instream flow uses
downstream from the point of withdrawal, and prevent water quality
degradation.\14\
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\13\ SRBC, Guidelines for Using and Determining Passby Flows and
Conservation Releases for Surface-Water and Ground-Water Withdrawal
Approvals, Policy No. 2003-001 (November 8, 2002).
\14\ Id.
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Parenthetically, I should note that the Commission is now
undertaking a re-evaluation of its existing guidelines related to flow
protection following the completion of a recent basin study conducted
by The Nature Conservancy that addressed how aquatic systems can be
sustained by preservation of the long-term natural hydrologic
variability of streams through ecosystem-based flow goals.\15\ We
anticipate that the Commission will be releasing an updated policy
within the next 3 to 6 months that reflects this new, contemporary
science.
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\15\ Ecosystem Flow Recommendations for the Susquehanna River Basin
(The Nature Conservancy, 2010).
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For each application seeking surface water withdrawal approval, the
Commission undertakes a site-specific aquatic resource survey to
establish baseline conditions and determine appropriate limitations,
unless a similar study was conducted for the site within the past five
years and can provide useful data. The Commission then utilizes these
data to formulate conditions related to (1) limits on the quantity,
timing or rate of withdrawal; (2) limitations on the level of drawdown
in a stream, well, pond, lake or reservoir; and (3) streamflow
protection measures.
Projects involving the consumptive use of water (i.e., where water
withdrawn from the basin is used in such a manner that it is not
returned to the basin undiminished in quantity) are required to
mitigate the loss of water to the basin, particularly during low flow
conditions.\16\ Essentially, mitigation is required on a 1-to-1 basis
by employing one of several options:
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\16\ 18 CFR Sec. 806.22

Reducing withdrawals during prescribed low flow periods in
an amount equal to the project's total consumptive use, and
withdrawing from other secondary source(s) that have sufficient
capacity to sustain withdrawals without impact to surface water
flows for a period of at least 90 days.
Releasing water during prescribed low flow periods from
secondary source(s) for flow augmentation in an amount equal to
the project's total consumptive use, provided the release can
be sustained for at least 90 days without impact to surface
water flows.
Discontinuing the consumptive use during prescribed low flow
periods.
Using as the primary source for consumptive use water a
storage impoundment that is subject to the maintenance of an
acceptable conservation release requirement.
Providing consumptive use mitigation fee payments to the
Commission, which utilizes such funds for the acquisition and
maintenance of water storage used to provide streamflow
augmentation during low flow periods.\17\
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\17\ Id.

The general regulatory framework noted above is applicable to
natural gas development activity throughout the basin, except as
modified by the regulatory enhancements described below.

III. Special Regulation of Marcellus Shale Development Activity
As exploratory well development of the Marcellus Shale formation
got underway in the second half of 2008, the Commission experienced a
dramatic increase in the number of applications seeking approval for
water withdrawals and consumptive water use. It also saw the potential
for this activity to create adverse, cumulative adverse or interstate
effects to the water resources of the basin, regardless of whether
individual projects met or fell below its regulatory thresholds.
Why the concern? Save for the bottled water industry, which tends
to focus on pristine watersheds for high quality water, the vast
majority of projects regulated by the Commission have historically
located themselves alongside the mainstem river, or major tributaries,
or at least down in the valleys along streams with appreciable flow
characteristics. Furthermore, the typical project could be analyzed for
impact based on withdrawals from specific locations to feed adjacent
operations with attendant calculations of return flow and consumptive
loss.
But the natural gas development industry is different,
fundamentally different. It takes water from multiple de-centralized
locations, on an inconsistent basis, and uses it at any one of dozens
of ever-changing locations, based on its operational needs. Perhaps
most significantly, and what sets it apart, is the fact that it engages
in water-demanding activity in remote, often environmentally sensitive
headwater areas.
Quantities of water that one could otherwise consider
inconsequential on a major tributary can represent an important
component of the flow regime in headwater areas. When you overlay the
extent of headwater streams in our basin with the extent of the
Marcellus shale formation, as depicted graphically in *Attachment 2,
you can see that alignment.
As a result of that alignment, coupled with the operational nature
of the industry, the Commission elected to modify its regulatory
approach for this industry. It took administrative and regulatory
actions in 2008, 2009 and 2010, all of which were intended to implement
and refine a set of management controls it felt were necessary to avoid
adverse impacts to the water resources of the basin, yet allow the
industry to proceed with development activity.\18\ Those modifications
include the following:
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\18\ First, the Commission's Executive Director issued a Notice of
Determination for Natural Gas Well Development Projects, August 14,
2008 (as revised October 8, 2008), pursuant to 18 CFR Sec. 806.5(a),
that all natural gas well development projects in the Susquehanna River
Basin targeting the Marcellus or Utica shale formation, and involving
the withdrawal or consumptive use of water, are subject to review and
approval regardless of whether they otherwise meet existing regulatory
thresholds, effectively establishing a ``gallon one'' regulatory
threshold.

The regulatory threshold for initiating Commission review
and approval authority commences at gallon one, rather than the
traditional regulatory thresholds noted above.\19\
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\19\ 18 CFR Sec. 806.4(a)(8).
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Although the threshold changed from 100,000 gallons to
gallon one for water withdrawals, the Commission did not modify
any of the current standards or requirements associated with
the review and approval of water withdrawals. They continue to
be subject to the same standards noted above that all
withdrawals across the basin are subject to, and we believe are
appropriate, to protect the basin's water resources and
simultaneously allow for their utilization by this new
industry.\20\
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\20\ 18 CFR Sec. 806.4(a)(2).
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Consumptive use approvals to go through a new administrative
Approval by Rule process specifically applicable to the natural
gas development industry.\21\
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\21\ 18 CFR Sec. 806.22(f).
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ABRs are issued on a drilling pad basis, regardless of the
number of wells developed on the pad, and include appropriate
monitoring, reporting and mitigation requirements.\22\
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\22\ Id.
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In addition to water withdrawal approvals, the industry may
obtain source approvals under the ABR process, including
approvals to including public water supplies and wastewater
sources.\23\ It is the policy of the Commission to incentivize
the use of lesser quality waters, including effluent discharge
and acid mine drainage, for hydrofracture stimulation in lieu
of fresh water sources. This incentive also extends to the
reuse or recycling of flowback and production fluids for that
purpose.
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\23\ 18 CFR Sec. 806.22(f)(12)(ii).
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The industry is authorized to utilize any of its approved
water sources at any ABR site so as to provide operational
flexibility.\24\
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\24\ 18 CFR Sec. 806.22(f)(11).
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The industry is incentivized to share source approvals
between companies by providing for a simple registration
process to facilitate that sharing and limit the number of
withdrawal locations in a given watershed or area.\25\
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\25\ 18 CFR Sec. 806.22(f)(12)(i).

As a final point on the scope of its regulatory program, and beyond
the water quality considerations taken into account in issuing
withdrawal approvals, it should be noted that the Commission relies on
its member jurisdictions to generally manage the water quality aspects
of this activity. This is consistent with its Compact mandate to
properly utilize the functions, powers and duties of the agencies of
its signatory members.\26\
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\26\ Susquehanna River Basin Compact, Sec. 3.2.
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Given that its member states all have comprehensive well
permitting, construction and hydrofracture stimulation standards,
erosion and sedimentation control, and disposal and treatment
standards, the Commission does not regulate these aspects of natural
gas well development activity. Instead, and so as to not duplicate
those efforts, it requires the industry to comply with the applicable
requirements of state and federal law.\27\
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\27\ 18 CFR Sec. 806.22(f)(8).
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IV. The Marcellus Water Use Profile
The development of the Marcellus shale in the basin unquestionably
represents both a tremendous opportunity and a series of water
resource-related challenges. On the economic side, there are numerous
studies and projections that attempt to quantify the significant
economic value of Marcellus development activity. On the water resource
side, the bigger challenges focus on cumulative impact, from both a
water quality and water quantity perspective.
From a management perspective, there is value in viewing these
challenges in the broader context of energy water use demands and
impacts basin-wide. The amount of water withdrawn and consumed by the
energy sector, principally for power production, dominates all other
industry sectors save for that attributable to public water supply in
the basin.\28\ Of the 563 mgd of total approved consumptive use in the
basin as of 2005, 149 mgd, or 26%, was for power generation.\29\
Deducting from that total the amount authorized as an out-of-basin
diversion to the City of Baltimore, Maryland for public water supply
(250 mgd), power generation jumped to 47%, or nearly half, of the total
approved consumptive use occurring in the basin as of the date of that
report.\30\ Since then, the quantity of approved consumptive use for
that industry has increased from 149 mgd to 192 mgd.
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\28\ See SRBC Consumptive Use Mitigation Plan (March, 2008). Data
contained in the plan are as of 2005.
\29\ Id. at pg. A-6. When (unregulated) consumptive use associated
with grandfathered power generation facilities are added in, the number
increases from 149 mgd to 180.5 mgd.
\30\ Id.
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With regard to the energy profile, the current basin power
production capacity is 15,300 megawatts, of which 37.5% is nuclear, 31%
is coal, 15.5% is natural gas, 12% is hydroelectric and the remaining
4% is other (wood, ethanol, solid waste, etc.).\31\ Combined, these
projects are approved to withdraw 3.44 billion gallons per day (gpd),
which does not include an additional 814 mgd that is currently
grandfathered.\32\
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\31\ SRBC, Water Resource Challenges from Energy Production, June,
2008.
\32\ Id. Groundwater withdrawals for this industry only total 14.2
mgd, and are generally limited in uses to non-thermal related aspects.
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So how does Marcellus shale development activity compare in a
relative sense? First, it should be noted that the full extent of
potential activity has yet to be empirically documented. Estimates have
varied widely, and the Commission will continue to monitor them and
rely on the most contemporary estimates, particularly to enable a more
objective analysis of potential cumulative impact.
Preliminarily, in 2008, it looked at the production build-out of
the Barnett shale in Texas, and other shale plays across the United
States such as the Haynesville and Fayetteville, in order to develop
some estimation of that potential.\33\ It originally estimated the
consumptive use potential at full build-out level to be 28 mgd, on an
annualized basis, and then revised that number to 30 mgd.
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\33\ Galusky, Jr., L. Peter, Ph.D., P.E., ``Fort Worth Basin/
Barnett Shale Natural Gas Play: An Assessment of Present and Projected
Fresh Water Use'', prepared for Gas Technology Institute, April, 2007.
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This estimate still holds based on what has transpired to date, but
will no doubt be modified over time as more objective criteria become
available, particularly in-basin development data over a sustained
period of time.
Interestingly, and for comparative purposes, it should be noted
that air quality control upgrades (scrubbers) at typical power plants
in the basin each consume 4 to5 mgd, and single plant generation
upgrades can require 30 mgd or more.\34\ Nonetheless, and even though
it represents a little more than half of the amount currently used
consumptively by the recreation sector (golf courses, water parks, ski
resorts, etc.)\35\ on a seasonal basis, it does represents a 19%
increase in the amount attributable to the energy sector.
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\34\ SRBC, Water Resource Challenges from Energy Production, June,
2008.
\35\ SRBC Consumptive Use Mitigation Plan at pg A-6.
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For planning purposes, the Commission recently undertook an
analysis of energy sector trends and has estimated a potential 2025
demand of 230 mgd of increased consumptive use for power
production.\36\ This does not include the Marcellus projection noted
above since it is not power production-related, but it does add to the
overall energy water use demand.
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\36\ Id. at pg. A-14. (Original published amount of 134 mgd updated
to 230 mgd by SRBC, 2010).
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A second comparison to note is the water withdrawal demand for the
Marcellus as it relates to the power production sector. Given the
assumption that every gallon withdrawn by the natural gas industry is
consumptively lost to the system, the estimate of 30 mgd is equally
applicable to both withdrawals and consumptive use.
Completion of natural gas wells involves a one-time use of water
for hydrofracture stimulation of the well (which may be repeated over
the life of the well to re-stimulate production). On the other hand,
power generation, especially base load operations, require water on a
constant basis (generally 24/7 year round). Currently, 3.44 billion
gallons per day is authorized for withdrawal from the basin for power
generation.
Using the estimate of 30 mgd, Marcellus shale development activity
would require slightly less than 11 billion gallons per year. Comparing
that to the amounts approved for power production withdrawals, the
annual volume for Marcellus development would be slightly more than
what is authorized for withdrawal in a single 3-day period for power
production. Accordingly, the concern with regard to water demand
associated with development of the Marcellus shale is not focused on
the total quantity, but more on the location and timing of withdrawals
and their impact on smaller order streams.\37\
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\37\ Power production facilities, on the other hand, are generally
located along the mainstem river or major tributaries.
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So what does the current data reported to the Commission tell us
about the nature and amount of actual water use by this industry?
*Attachment 3 provides summarized information concerning withdrawals
and consumptive use for the first three years of development activity
in the basin. *Attachment 4 provides profile information on a per well
basis for the last four reported calendar quarters. Of note are the
following:

Thus far, over the past three years, the industry has
withdrawal 3.6 billion gallons of water from the basin.
Based on average daily withdrawal rates per quarter, average
daily withdrawals over the most recent four quarters equals 7.1
mgd.
Consumptive use, including water obtained from withdrawals
and all other approved sources, totals 4.5 billion gallons for
the past three years.
Based on average daily consumptive use rates per quarter,
the average daily consumptive use over the past four quarters
equals 8.5 mgd, with the most recent quarter representing
approximately 10 mgd.
The pattern for consumptive water use continues to trend
upward, for water withdrawals it is more variable.
Over the most recent four calendar quarters, the average
total water volume for hydrofracture stimulation, per well, is
4.24 mgd.
During that same period, the average recovery of flowback,
as a percentage of total injected water, ranges from 5% to 12%.
More recently, and possibly attributed to formation
characteristics in the area of the play where most activity is
occurring, the reported numbers have been consistently close to
5%.
During that same period, the average amount of flowback
reused per well fracturing event is approximately .5 mgd, or
12% of the total volume.

These data are derived from quarterly monitoring reports over the
past three years and the 654 event-specific post-hydrofracture reports
filed over the past four quarters by the industry.

V. Water Quality Monitoring
As noted above, the Commission is relying on its member
jurisdictions to provide water quality regulatory oversight of the
natural gas development industry. Consistent with its history, the
Commission provides water quality monitoring and assessment support to
its members. As natural gas development activity unfolded across the
basin, the Commission saw the need for additional monitoring in the
more remote areas where this activity was occurring.
In January 2010, the Commission began deployment of a Remote Water
Quality Monitoring Network (Network) designed to monitor water quality
conditions to maintain and protect surface waters in selected remote
portions of the Susquehanna River basin. The monitoring network uses
state-of-the-art monitoring and communication technology to collect and
transmit real time water quality data, including the following
parameters: temperature, pH, conductance, dissolved oxygen, turbidity,
and relative water depth. The data is made available continuously on
the Commission's website, www.srbc.net, and is accessible to resource
agencies and the general public. Additional details concerning the
network are provided in *Attachment 5.
At present, the network consists of fifty (50) monitoring stations
in the Pennsylvania and New York portions of the Susquehanna basin.
These stations were installed over a period of a year and a half, with
the last station installed in August 2011.
While we have been monitoring the data being reported by the
Network on an ongoing basis, the Commission has just now started to
analyze the data in earnest, especially given the need to acquire an
adequate amount of data to work towards establishing baseline
conditions. Thirty-seven (37) stations had sufficient data records to
begin more rigorous analyses. Upon completion of the very initial stage
of the analyses, the dataset is proving to be very complex given the
range of possible influences within each of the monitored watersheds
and the lack of historical data.
In addition, the range of hydrologic conditions experienced in the
Susquehanna River basin over the last year and a half, during the
period of record for the first set of stations, shows the importance of
characterizing water quality conditions over the longer term prior to
making any cause/effect determinations. Although generalized summary
statistics for the entire Network's dataset could be considered within
normal ranges, a select subset of stations have not exhibited what
might be considered predictable water quality conditions based on their
physical setting (geology, land use, topography, soils, etc.). Also, a
subset of stations experience occasional ``spikes'' in certain
parameters not readily explained by typical natural conditions. At
present, seven (7) stations fall into this category and will require
more extensive data collection and analyses. However, in all cases, it
is important to note that natural gas development is not the exclusive
activity within the monitored watersheds, and that irregular water
quality conditions do not necessarily equate to impacts from human
activities.
Beyond the continuous water quality data, we have also been
monitoring for a more extensive suite of parameters more indicative of
natural gas activity (i.e., chloride, barium, bromide, radionuclides)
through the collection of ``grab'' samples throughout the year. Staff
also just completed the first round of biological and habitat data
collection at each of the stations, and will be including those data in
future analyses as well. Upon completion of these comprehensive
analyses, we will be in a better position to characterize conditions in
each of the monitored watersheds. We anticipate publication of our
first analytical report in January, 2012, and we would be happy to
provide it to the subcommittee.

V. Conclusion
As noted above, development of the Marcellus shale formation
represents both an opportunity and challenge for the Susquehanna River
Basin. The Commission's water withdrawal regulations are designed to
allow proper development, utilization and protection of the basin's
water resources. Instream uses, competing uses, localized cumulative
impact analyses and water quality considerations are comprehensively
addressed.
The Commission believes the regulatory adjustments is has made in
response to the industry have been appropriate and it continues to
refine its management controls as it gains more experience.
Additionally, its ongoing work in the area of ecological flows will
also help to assure that we are applying the best science in making
management decisions, whether for this industry or any other.
With regard to water quality issues, the Commission will continue
to look to its member jurisdictions to take the primary regulatory
role, we will continue to provide monitoring support, and we will
continue to participate in the necessary planning and assessment
initiatives attendant with this activity.
The cumulative impact of consumptive use by this new activity,
while significant, appears to be manageable with the mitigation
standards currently in place. This demand, coupled with that
anticipated for public water supply and other industry sectors,
represents a challenge for the Commission, the water users who have an
obligation to mitigate, and for the basin generally. As part of its
consumptive use strategy for the basin generally, the Commission will
continue to evaluate and refine its mitigation standard and pursue
additional opportunities for low-flow augmentation.\38\
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\38\ SRBC Consumptive Use Mitigation Plan, at pg. 23.
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Combined, these efforts will help to insure the proper and
sustainable utilization of the water resources of the basin for this
new energy resource development opportunity.
On behalf of the Commission, I will be happy to respond to any
questions, comments or informational requests of the subcommittee.
Thank you for this opportunity to testify.

Senator Shaheen. Thank you very much.
Mr. Cooper.

STATEMENT OF CAL COOPER, WORLDWIDE MANAGER, ENVIRONMENTAL
TECHNOLOGIES, GREENHOUSE GAS, AND HYDRAULIC FRACTURING, APACHE
CORPORATION, HOUSTON, TX

Mr. Cooper. Thank you, Madam Chairman Shaheen and Ranking
Member Lee.
After that testimony, I think mine will be a lot briefer.
We're going to say a lot of the same things. I think the big
conclusion that I just heard from Tom's testimony is that the
Susquehanna River Authority is doing a great job, and we shall
applaud them.
So today, I was asked to focus on the impact shale gas
production would have on water resources in the eastern United
States. I wanted to talk about protecting water resources from
chemical pollution, balancing competing needs for water
resources, and finally, to talk about something a little
different, how water requirements for natural gas stack up
compared with other major players in the energy and power
section--sector.
So I think all of us agree that we absolutely must protect
water resources, especially drinking water, from chemical
pollution, and that's really fundamental. We've heard from
others that oil and gas operations everywhere address the
protection of aquifers. This includes the disposal of produced
water in a responsible way. The safest, and most efficient, and
economical way is to reinject it.
In the Marcellus area, we've heard there are very few
disposal wells. Initially, the industry disposed of produced
water by trucking it to treatment plants. With the scale up of
operations, that proved unsustainable. It's really not done
anymore. Now, nearly all operators report that they store,
treat, and reuse water, putting it into the next frac job a
mile below the surface. This is a best practice and it's been
an evolution.
Many have asked why companies didn't recycle water to start
with, and a couple of factors played a major role. Operators
were familiar with the chemistries and functional expectations
of using freshwater at facilities to treat water for reuse were
rare and costly. It takes treatment to make flowback and
produced water suitable as base fluids for fracturing. As the
saying goes, necessity is the mother of invention and there's
been a lot of innovative problem solving in this area.
Others have addressed the committee about chemical
disclosure and the merits of FracFocus. This effort also
encouraged companies to think more about what they use in
specific chemicals, and how they can minimize risk by changing
chemical components.
Basically, no one wants to pay for chemicals they don't
need, and we have found that we can often replace non-
biodegradable biocides with much less intrusive additives. A
good thing here is that the slick water fracs from dry gas
common in the Marcellus, lend themselves to really pretty
simple formulations.
I think I'm skipping most of this page. But I'd like to
turn to the size of all of that water that we're withdrawing.
You heard some excellent statistics from Tom, and I really want
to ask: does it all add up to something that's really huge? It
just depends where. If it's in a trout stream up in the top of
the mountains, it's a big deal. But estimates suggest that the
Marcellus Basin total water usage exceeds 3 trillion gallons of
water per year used by people and industry. So in a big
picture, looking at the really big use of water, even 1,000
frac jobs don't add up to much more than a big drop.
Another way to think about that is that a typical frac job
uses about 1.5 seconds of the Mississippi River discharge into
the Gulf of Mexico. So location is really everything.
In Texas where Apache has a very significant presence,
record drought is impacting everything and operators are
scrambling to manage a scarce resource. So recently, we learned
a great deal from our Canadian operations about relatively high
saline water to be used as frac fluids instead of fresh water,
contrary to the general practices and expectations in the
industry, and contrary to what's going on in the Marcellus.
Senator Shaheen. Can you just explain the difference
between the 2?
Mr. Cooper. Why certainly. So we use--in the Marcellus
area, the industry uses fresh water, which is usually surface
water. In Canada in our operations, we decided it was much
better to use saline brines derived from about 3,000 feet below
that are completely unusable as fresh water. We found,
actually, that it worked better for us than using fresh water.
We are going to do our very best to completely stop using fresh
water in Canada except as sort of emergency backup water.
That required a really huge investment and a lot of
innovation, but we think that things like that can work in some
parts of the United States. Apache is very actively looking at
that in the Permian Basin of west Texas where it's very
important to us. We're not sure whether that would even work in
the Marcellus or not, but somebody needs to really investigate
it.
Now, I'd like to turn to that other part of big use of
water and that's power generation. I'm not an expert in power
generation. I'm a geoscientist, but I can look at numbers for
water use and it seems especially pertinent for this committee
to consider the water budget of energy from shale gas compared
to other sources.
The natural gas revolution, after all, is about providing
power to America. In a combined cycle power plant fueled by
natural gas from shale requires less than half the water used
for fuel and cooling compared with thermal coal steam power
plants, a less than a third of nuclear steam turbine
requirements, and even a smaller fraction that's required for
solar condensing plants.
So if we look at natural gas, it uses less water to
generate power. If we look at other fuels, natural gas from
both shale gas and conventional sources requires less water per
million BTUs of power and energy in its combustion than any
other common fuel. That's a pretty good deal.
So thank you for allowing me to share some of my thoughts
with you today.
[The prepared statement of Mr. Cooper follows:]

Prepared Statement of Cal Cooper, Worldwide Manager, Environmental
Technologies, Greenhouse Gas, and Hydraulic Fracturing, Apache
Corporation

Mr. Chairman, and members of the committee,
Today I have been asked to focus on the impact shale gas production
will have on water resources, especially in the Eastern United States.
It is a topic I care passionately about, and I believe it is a
fundamental piece of ensuring the future health of our families and the
economic strength of our country. Some however, are convinced that
shale gas production will ruin everything they cherish. The task before
us is to envision a much more positive outcome, and ensure that we get
there. Shale gas development offers America an opportunity to
demonstrate what it does best. It will improve living standards in many
communities by expanding employment in a variety of industries and
provide income to royalty owners and tax revenues to state and local
governments. It will be done responsibly, and the process will drive a
lot of innovation, while setting new standards for environmental
sustainability. Already a lot of that is underway. The ultimate
timeline may be the next 100 years, but industry appreciates the
imperative of getting things right, and is rapidly moving forward to
respond to the challenge. For our discussion today, some areas are of
general priority interest: protecting water resources from chemical
pollution, balancing competing needs for water resources, providing
perspective on what alternatives we have or in other words
investigating how water requirements for natural gas stack up compared
with other major players in the energy and power sector.

Protecting water resources
Protecting water resources, especially drinking water from chemical
pollution is part of our fundamental commitment to safe operations and
protecting the communities where we live and work. In traditional oil
and gas states, the safest, most efficient and economical way to deal
with water is not so practical in many areas of the Marcellus.
Generally water is sourced from surface or groundwater, and after use
all flow-back and produced water is disposed of into state permitted
deep injection wells.
In the Marcellus area there are very few disposal wells and
initially the industry disposed of produced water by trucking it to
treatment plants. With the scale-up of operations this has proved
unsustainable. Now nearly all operators report that they store, treat
and re-use water, putting it into next frac job a mile below the
surface. As operations expand toward Ohio and western West Virginia,
geology is likely to be more conducive to deep subsurface injection of
waste water.
Many have asked me why companies didn't re-cycling water to start
with. A couple of factors played a major role. Operators were familiar
with the chemistries and functional expectations of using ``fresh''
water, and facilities to treat water for re-use were rare and costly.
It takes treatment to make flow-back and produced waters suitable as
base fluids for fracturing. As the saying goes necessity is the mother
of invention, and there has been a lot of innovative problem solving in
this area.
Others have addressed this committee about chemical disclosure and
the merits of the IOGCC-GWPC FracFocus.org website. From an industry
insiders perspective, this effort has also encouraged companies to
think more about why they use specific chemicals and how they can
minimize risks by changing chemical components. Several major vendors
have developed more environmentally sensitive formulations and some
have developed scoring systems to better quantify and communicate the
advantages of particular chemicals. Nation-wide there is a lot of
variability in the specific chemical needs based on problems of local
geology, reservoir temperature and pressure and the presence of
specific minerals or metals in the reservoir rocks or fluids. In
addition operators have conducted performance-based comparisons to aid
in the selection of chemical additives. Basically, no one wants to pay
for chemicals they don't need, and we have found that we can often
replace non-biodegradable biocides with much less intrusive chemicals
or even with ultraviolet light in some circumstances. We frequently
eliminate clay control additives without detrimental reactions.
The slick-water fracs for dry gas common in the Marcellus lend
themselves to simpler formulations.

Balancing competing needs for water resources
No doubt, hydraulic fracturing requires a lot of water, and the
amount depends on the size and depth of the well, and the specifics of
the competition technique. Water is a local resource and withdrawal
must be managed on a local basis to ensure that the ecological health
of riparian systems and the needs of other major users are met. All
states have significant powers and organizations in place to protect
these rights.
In the Marcellus area most operators report frac jobs requiring 4-8
million gallons of water. That sounds huge considered in isolation, but
compared with the estimates exceeding 3 trillion gallons of water per
year used by people and industry in the Marcellus basin it not so big
even if done 1000 times. Another way to think about it is that a
typical frac job uses 1.5 seconds of the Mississippi River discharge
into the Gulf of Mexico. In the Eastern US, the volumes of water
required for hydraulic fracturing are not likely to dominate decisions
about water use except in very local circumstances. Texas on the other
hand is not so lucky; record drought is impacting everything.
Apache operates in states and provinces where we are permitted to
re-inject 100 percent of flow-back and produced water into deep
underground reservoirs completely isolated from freshwater aquifers. In
Oklahoma and Texas, we normally make-up our frac fluids by mixing fresh
water produced from shallow groundwater sources and surface sources
that are purchased from land owners. Recently, we have learned a great
deal from our Canadian operations about using relatively high saline
water instead of fresh water, contrary to the general practices and
expectations of the industry. In the Horn River Basin, working with our
partner EnCana, we have developed a system for extracting water from a
saline aquifer in the Debolt formation and treating it in a built for
purpose plant to eliminate H2S. The water is piped to our well pad
where we add a minimum of chemicals to create an effective frac fluid.
After fracing we then re-inject the flow-back and produced water into
the Debolt formation in a closed-loop system. This water source
provides many operational advantages, and compliments efficiencies
provided by innovative high-density well pads that allow a minimum
surface footprint. We intend to continue to innovate to protect a
pristine environment using a minimum of surface water and disposing of
none into waterways.
High-flow-rate brackish or salt water aquifer systems are not
present everywhere. In the Permian Basin, Apache believes the brackish
Santa Rosa groundwater system can be adapted for a similar purpose as
the Debolt in parts of the Horn River Basin. We are currently
investigating tests of our concept for frac systems in oil reservoirs
using recycled brackish water as a base fluid. This has many
environmental advantages, and well as practical reservoir management
efficiencies, but it is especially good because if we are successful,
we will minimize our need for fresh water. This is a clear example
where technology enables our business and we aggressively explore what
is possible in order to succeed. So do many others, and we all benefit.

Hydraulic Fracturing, water and power
Although I'm not an expert in power generation, it seems especially
pertinent for this committee to consider the water budget of energy
from shale gas compared with other sources. The natural gas revolution
is about providing power to America. Natural gas from shale powering a
NG combined cycle power plant requires less than half the water used
for fuel and cooling of IGCC and Coal steam Power plants (without CCS),
less than a third of Nuclear steam turbine requirements, and an even
smaller fraction of water required by solar condensing plants.
Consider water requirements for other fuels. Natural gas, from both
shale gas and conventional reservoirs requires less water per MMBtu of
energy generated from combustion than any other common fuel.\1\
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\1\ http://www.sandia.gov/energy-water/docs/121-RpToCongress-
EWwEIAcomments-FINAL.pdf
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The real water ``water-hog'' it seems is not hydraulic fracturing,
but biofuels derived from irrigated corn ethanol or irrigated soy
biodiesel.
Thank you for allowing me to share some of my thoughts with you
today. Certainly shale gas has reputational issues, but a closer
examination of the facts and consideration of the alternatives
underscores what a giant and positive opportunity shale gas production
will have for the eastern United States and the country as a whole.

Senator Shaheen. Thanks very much.
Ms. Dunlap.

STATEMENT OF KATY DUNLAP, ESQ., EASTERN WATER PROJECT, DIRECTOR
FOR TROUT UNLIMITED, ARLINGTON, VA

Ms. Dunlap. Thank you, Madam Chair and Ranking Member Lee.
My name is Katy Dunlap, and I'm the Eastern Water Project
Director for Trout Unlimited. We are a 140,000 member
organization dedicated to conserving, protecting, and restoring
North America's trout and salmon fisheries.
I thank the members of the subcommittee for holding this
hearing today and for the opportunity to testify.
Trout Unlimited supports natural gas development that is
done right, in the right way, and in the right places.
Improperly sited to poorly management natural gas development,
however, can have impacts on water resources. Trout Unlimited
is actively involved at the local, State, and Federal level
trying to find solutions which will promote responsible energy
development.
For example in Pennsylvania, more than 200 Trout Unlimited
members are conducting stream surveillance for impacts
associated with Marcellus Shale gas development. In the field,
our members are witnessing impacts that do not always make the
headlines. My testimony today will focus on the Marcellus Shale
and highlight a few of the surface impacts of gas drilling in
Pennsylvania, where more than 1,600 wells are currently in
production, and where the State has already issued 925
violations to Marcellus well operators this year alone.
By far, the most prominent and concerning impact that our
members are seeing on the ground is the failure or lack of
erosion and sediment controls on wellpad constructionsites and
access roads. Due to an exemption that was mentioned earlier
provided through the Energy Policy Act of 2005, oil and gas
constructionsites and the roads that service those sites are
not covered by the Clean Water Act's storm water provisions.
In addition to affecting the quality of public water
supplies, erosion and sedimentation can gravely impact high
quality coldwater habitat.
In March 2011, erosion from the development of a gas well
site in Potter County resulted in the significant discharge of
sediment and silt from the site into a stream that feeds a
water source serving 1,400 people in the burrow of Galeton.
That incident forced the Galeton Water Authority to switch to
another permitted drinking water source.
Sedimentation also impacts fish by reducing food sources
and spawning habitat, and causing reductions in growth and
direct mortality. Earlier this month Pine Creek, a world
renowned trout stream and a federally designated wild and
scenic river, experienced severe turbidity as a result of the
El Paso pipeline construction happening in Potter County. The
open ditches running up and down the mountain failed to include
appropriate erosion management controls, resulting in excessive
sediment loading that will likely diminish trout spawning this
season.
These are just 2 examples of pollution incidents that have
resulted from DEP inspection at sites where an erosion and
sediment control permit was required. In reality, there are
many more of these types of pollution incidents that go
unnoticed and uninvestigated by the State largely because oil
and gas development sites less than 5 acres are not required to
receive a permit under current Federal or State law.
Collectively, these impacts will result in the overall
degradation of water resources.
Blowouts, spills and leaks related to drilling activity can
also cause significant short and long term impacts on water
resources. In 2009, several leaks and spills from a single site
caused contamination of groundwater springs and high quality
trout waters. Leaks from hoses, tanks and storage pits resulted
in thousands of gallons of water and fracking fluid
contaminating 3 trout streams and Reed Springs, a drinking
water source for nearby camps, hunting camps in Clearfield
County. The same site experienced a blowout in June 2010, which
released at least 35,000 gallons of brine and toxic fluid into
the air for over 16 hours.
The several incidents of contamination to surface and
groundwater from this one site demonstrate the risks that may
be posed by the 50,000 to 80,000 wells that are projected for
Pennsylvania alone.
Other surface impacts from gas drilling relate to the
locations of wellpads, wastewater storage areas, and pipelines.
State law, at least in Pennsylvania, does not prevent
infrastructure from being cited in the 100 year flood plain and
in close proximity to streams, in some cases, within 100 feet.
As Mr. Beauduy pointed out earlier, large consumptive water
withdrawals from small, headwater streams can threaten trout
fisheries and downstream water supplies. State regulators and
the industry have failed to develop and implement comprehensive
wastewater management treatment and disposal plans.
We applaud the EPA's announcement today of a schedule to
develop consistent shale wastewater effluent standards.
In closing, Trout Unlimited urges this Congress to take a
more careful look at the full range of gas development impacts
on water resources, require disclosure of chemicals used in
hydraulic fracturing, and reinstate the Clean Water Act storm
water and Safe Drinking Water Act provisions that should right
now be at work on the ground protecting valuable resources from
gas development.
Thank you.
[The prepared statement of Ms. Dunlap follows:]

Prepared Statement of Katy Dunlap, Eastern Water Project Director,
Trout Unlimited

Madam Chair, ranking member Lee, and members of the subcommittee:
My name is Katy Dunlap, and I am the Eastern Water Project Director
for Trout Unlimited-the nation's largest coldwater conservation
organization dedicated to conserving, protecting and restoring North
America's trout and salmon fisheries. I thank the members of the
subcommittee for holding this important hearing and for the opportunity
to testify.
Most of Trout Unlimited's 140,000 members like to fish, and they
give back to the rivers and streams by dedicating more than 600,000
volunteer hours each year. We are fortunate to have such a committed
group of volunteers, as the challenges we face are great: nearly half
of the rivers and streams in the U.S. are considered to be impaired.
Natural gas development is occurring in several regions in the
Eastern half of the United States, including the Antrim Shale in
Michigan, Fayetteville Shale in Arkansas, and Marcellus Shale in the
northern Appalachians. My testimony today will focus on the Marcellus
Shale, and specifically on the impacts of development in Pennsylvania,
where more than 1,600 wells are in production.\1\
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\1\ http://www.prweb.com/releases/Marcellus/Production/
prweb8855519.htm
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Trout Unlimited supports natural gas development that is done the
right way, and in the right places. Improperly sited or poorly managed
natural gas development, however, can cause serious harm to water
resources, which I will explain in greater detail later in my
testimony. Declines in water quality directly affect Eastern brook
trout, the East's only native trout, and a species whose survival
depends on a steady supply of clean, cold water. A recent assessment
found that brook trout are either greatly reduced or have vanished from
50 percent of their historic range, and are at risk of disappearing
from other areas. The report found that two of the major impacts to
brook trout are habitat fragmentation and sedimentation due to road
crossings and construction-two impacts that are also associated with
drilling in the Marcellus Shale.
With our state and federal agency partners, as well as our
conservation allies, Trout Unlimited members are working hard to
reverse the decline in brook trout populations all along the
Appalachian mountain range, from Georgia to Maine. In Pennsylvania,
Trout Unlimited's 12,000 members and staff have been diligently working
for more than a decade to restore trout streams that suffer the legacy
impacts of past coal mining. And we are making progress. For example,
work to remediate acid mine drainage in the Babb Creek in Tioga County,
Pa. restored water quality to the point that brook trout were able to
repopulate the stream for the first time in decades. Yet in 2011 alone,
181 Marcellus Shale wells have been drilled in Tioga County. As we work
to achieve hard-won fishery restoration gains, it is imperative that we
avoid additional losses that can result from poorly managed natural gas
development.
The potential for natural gas development to impact water resources
and trout fisheries exists at several stages of the development
process. While Trout Unlimited is concerned about the potential
contamination of water resources that can be directly caused by the
hydraulic fracturing process, we are equally concerned about the
surface impacts that can result from the associated activities of
hydraulic fracturing and natural gas development. Specifically, we are
concerned about the locations of well pads, wastewater storage areas,
and pipelines; well pad, pipeline, and access road construction; water
withdrawals from small headwater streams; spills and leaks of toxic
substances; and the management, storage and disposal of drilling
wastewater.
State and local governments are almost entirely responsible for
regulating gas development in the Marcellus Shale region. Federal
regulation of the stormwater and drinking water aspects of gas
development could have been helpful, but were eliminated by the 2005
Energy Bill passed by Congress. With the lack of any federal oversight,
states have taken very different regulatory paths, as I'll explain
below. But in the heart of the Marcellus development area, in places
such as Pennsylvania, well intentioned state regulatory programs are
struggling mightily to keep up with the challenges posed by rapid gas
development.
From what we see on the ground, regulation of gas development is
not adequate to protect water resources, and we are working hard to
fill the gaps. From cradle to grave, water use management for drilling
and hydraulic fracturing needs significant improvement to eliminate or
reduce incidents of water-related pollution and to ensure overall
protection of water resources. My testimony today will illustrate a few
examples of drilling-related surface impacts occurring on the ground,
including: erosion and sedimentation; blowouts, leaks, spills and
illegal discharges; impacts of water withdrawals from headwater
streams; and insufficient regulation of wastewater management. I will
then discuss what Trout Unlimited is doing to prevent harm to water
resources and aquatic habitat, and the policy changes that are needed
in Pennsylvania and beyond to facilitate responsible energy development
while sustaining the healthy ecosystems that support $76.7 billion in
hunting-and fishing-related economic activity across the United States.

I. Water Quality and Quantity Impacts
Of the 925 violations issued by the Pennsylvania Department of
Environmental Protection (DEP) to Marcellus well operators, from
January to August of this year, the greatest percentage of violations
issued were related to spills, leaks, and illegal discharges. However,
by far the most prominent and concerning impact that Trout Unlimited
members are seeing on the ground is the failure or lack of erosion and
sediment controls on well pad construction sites and access roads.
A. Erosion and sedimentation
Erosion and sedimentation can lead to the overall degradation of
water supplies and irreversible impacts on valuable and irreplaceable
trout streams. In March 2011, development of a gas well site in West
Branch Township, Potter County, led to an erosion problem that resulted
in the DEP issuing a cease-work order to Chesapeake Energy. A
significant amount of sediment and silt was discharged from the site
into a stream that is a tributary to a water source serving the Borough
of Galeton. The Galeton Water Authority was forced to use another
permitted drinking water source. If the water supply operator had not
been on site to shut off an intake valve, the water supply for 1,400
Pennsylvanians would have experienced irreparable damage. DEP issued a
violation to Chesapeake for failure to implement erosion and sediment
controls required in the permit.
In addition to affecting the quality of public water supplies,
erosion and sedimentation can greatly impact high quality coldwater
habitat. At least 15 different direct negative effects from
sedimentation have been demonstrated to impact trout and salmon,
ranging from stress, altered behavior, reductions in growth and direct
mortality:

Suspended sediment blocks light affecting feeding and movement of
fish and causes direct gill damage (if concentrations are high enough)
that may lead to death. Excessive sediment in the stream bottom may act
as a physical barrier and stop the emergence of fry or prevent proper
flow of water to redds . . . Proper water flow is necessary to carry
dissolved oxygen to incubating eggs and to remove waste products from
developing embryo.\2\
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\2\ Lloyd, D.S. 1987. Turbidity as a water quality standard for
salmonid habitats in Alaska. Pages 34-35. North American Journal of
Fisheries Management. American Fisheries Society. Bethesda, MD.

Earlier this month, a world-renowned trout stream in north central
Pennsylvania was seriously impacted by the construction of a Marcellus
natural gas pipeline. Pine Creek-a federally-designated Wild and Scenic
River--experienced severe turbidity as a result of vegetation clearing
for the El Paso pipeline in Potter County. The open ditches running up
and down the mountain failed to include appropriate erosion and
sediment management controls, resulting in excessive sediment loading
that will likely negate spawning in the exceptional value trout stream.
This incident is currently being investigated by Pennsylvania's DEP,
Fish & Boat Commission and the Potter County Conservation District to
determine the ultimate impact on Pine Creek and its coldwater fishery.
These are just two examples of sedimentation pollution incidents
that have resulted from DEP inspection at sites where an erosion and
sediment control permit was required. In reality, there are numerous
sedimentation pollution incidents that go un-noticed and uninvestigated
by the state-largely because oil and gas development sites less than
five acres are not required to receive a permit under current federal
and state law. Collectively, these impacts will result in the overall
degradation of water resources.
It is estimated that by 2030 between 38,000 and 90,000 acres of
Pennsylvania's forest cover will be cleared by Marcellus gas
development.\3\ The loss of forest cover will leave bare soil exposed
and lead to significant increases in erosion and potential water
quality impacts, if left unregulated and unchecked. Without oversight
on oil and gas development-related construction sites of one acre or
more, this pollution problem will perpetuate.
---------------------------------------------------------------------------
\3\ Johnson, Nels (2010). Pennsylvania Energy Impacts Assessment,
Report 1: Marcellus Shale Natural Gas & Wind, p.9. The Nature
Conservancy, Pennsylvania Chapter.
---------------------------------------------------------------------------
B. Blowouts, leaks, spills and illegal discharges
Blowouts, spills, and leaks related to drilling activity make the
news much more often than erosion and sediment control violations.
These activities may cause immediate short-term impacts to water
resources and contribute to overall water resource degradation in the
long-term.
On April 19, 2011, equipment failure at a Chesapeake Energy gas
well site near LeRoy Township, Pa. caused a leak, resulting in the
release of 30,000 gallons of salty flowback water from the site and
into a tributary to Towanda Creek. The well site was located less than
500 feet from the tributary that drains into Towanda Creek-too close to
prevent drilling fluid from entering the creek. Towanda Creek is a
well-known trout stream that meets the Susquehanna River about 16 miles
downstream of the spill. The Susquehanna River supplies 45 percent of
the fresh water in the Chesapeake Bay.
In March 2010, Airfoam HB-a wetting chemical used in gas drilling-
was discharged into Pine Creek near Waterville, Pa. The material
originated from a Pennsylvania General Energy Company LLC (PGE) well
site approximately 2,000 feet uphill from Pine Creek and was found by
local citizens in Pine Creek. Pennsylvania Fish & Boat Commission
investigators determined that the surfactant was pumped down the well
during the drilling process and, in all probability, accumulated in a
void in the sedimentary rock layers. The surfactant was then flushed
laterally through the underground rock strata by heavy rain runoff
before emerging as a soapy discharge at a spring, on the mountainside
approximately 2,000 feet away.\4\
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\4\ http://www.fish.state.pa.us/newsreleases/2011press/
pge_settle.htm
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In Clearfield County, Pa., several leaks caused contamination of
groundwater springs and high quality trout waters in 2009. At a well
site owned by EOG, a small hole in a drilling wastewater hose allowed
gas and flowback water to leak and percolate onto the ground and into
Little Laurel Run for over two months, contributing to the
contamination at Reed Springs and Alex Branch. Another accident
occurred at the site, when almost 8,000 gallons of water and fracking
fluids leaked from a tank and into the Alex Branch and Trout Run. Alex
Branch is a tributary of Trout Run, one of the area's better fishing
creeks, which flows into the West Branch of the Susquehanna River.
Investigations by the DEP and the Pennsylvania Fish & Boat Commission
subsequently determined that several accidental discharges of
contaminated water and fluids at EOG's Marcellus operations, including
leakage from the pit over a two-month period from August through
October 2009, had caused the contamination of Reeds Spring.\5\ That
same EOG well experienced a blowout in June 2010, releasing at least
35,000 gallons of brine and toxic fluids from hydraulic fracturing into
the air over 16 hours. The DEP shut down the company's drilling
operations for 40 days statewide, and six weeks later, fined EOG and a
drilling contractor a total of $400,000.\6\ Just this one well site
alone caused several incidents of contamination to surface and ground
water sources, demonstrating the potential contamination that may be
caused by the 50,000 to 80,000 wells that are projected for
Pennsylvania alone.
---------------------------------------------------------------------------
\5\ http://www.post-gazette.com/pg/11156/1151527-503.stm
\6\ http://www.post-gazette.com/pg/11156/1151527-
503.stm#ixzzlasSTB7RA
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C. Water quantity concerns
While the states overlying the Marcellus Shale region are blessed
with abundant rivers and streams, these water resources are not
infinite. Large, consumptive withdrawals for gas drilling can have
deleterious effects on sensitive watersheds and their aquatic life. To
hydraulically fracture each Marcellus well, approximately five million
gallons of water is needed. The timing and location of water
withdrawals for gas drilling, as well as consideration of other major
withdrawals in the basin during the same period, will determine the
short-and long-term impacts on the watershed. Because many of the more
productive Marcellus drilling areas are in or nearby smaller watersheds
containing headwater streams, such large water withdrawals could be
devastating to coldwater habitat and other aquatic resources.
For example, Horton Run, a tributary of the East Fork of
Sinnamahoning Creek and classified as an ``Exceptional Value'' trout
stream, was virtually de-watered by water withdrawals for gas well
development. Fish kills have occurred as a result of water withdrawals
that de-watered Cross Creek and Sugarcamp Creek in Washington County,
Pa. Four gas companies have paid a total of $1.7 million to settle
charges of illegal water withdrawals from Pennsylvania trout streams,
including Chief Oil & Gas, which took 3.5 million gallons from a
tributary of Larry's Creek, and Range Resources, which took 2.2 million
from Big Sandy Run. Additionally, water withdrawals have damaged
Meshoppen, Pine and Sugar creeks. These examples clearly demonstrate
the risk that water withdrawals from small headwater streams pose to
aquatic habitat.
D. Wastewater management
Marcellus Shale operators in Pennsylvania have reported that
approximately 15 percent of the roughly 5 million gallons of water used
to fracture a well is returned to the surface during the initial
flowback period, and the Secretary of Energy Advisory Board's (SEAB)
90-day report found that `` . . . in the Marcellus, primarily in Ohio,
New York, Pennsylvania and West Virginia, the flow-back water is
between 20 and 40 percent of the injected volume.''^7,8
Flowback from Marcellus Shale hydraulic fracturing contain pollutants
of concern--particularly high levels of dissolved salts, often several
times saltier than sea water. High Total Dissolved Solids (TDS) levels
can have significant impacts on trout populations and the waterways
they rely upon.
---------------------------------------------------------------------------
\7\ http://www.pagoppolicy.com/Display/SiteFiles/112/2011Hearings/
112_4_21_11_Jugovic_DEP_Testimony.pdf
\8\ The SEAB Shale Gas Production Subcommittee Ninety-Day Report-
August 11, 2011, p.9.
---------------------------------------------------------------------------
Hauling fresh water and wastewater to and from a well pad site is a
service that is often sub-contracted to several hauling companies. Each
of those trucking crews may be operating several trucks, and each of
those drivers may be making several trips a day. In southwest
Pennsylvania, one such hauler was recently charged with illegally
dumping millions of gallons of Marcellus Shale drilling wastewater into
holes, mine shafts and waterways in a six-county region between 2003-
2009. Robert Shipman and his company, Allan's Waste Water Services, are
collectively facing 175 criminal charges.\9\
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\9\ http://www.post-gazette.com/pg/11077/1132812-454.stm
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While the return water (flowback plus produced water) is
increasingly being re-used and recycled by the industry, ultimately
decreasing the demand for freshwater, there continues to be a lack of a
comprehensive treatment plan for wastewater generated from hydraulic
fracturing and drilling practices. In Pennsylvania, the DEP asked
drillers to voluntarily stop taking wastewater to municipal treatment
plants, as these facilities are designed to treat biological agents and
not equipped to treat the chemicals and high salts found in drilling
wastewater. Several companies have complied. However, there is still a
need for long-term wastewater management planning, as even recycled
wastewater must be partially treated before re-use and will eventually
need to be disposed. Other avenues for wastewater disposal have been
underground injection wells. In general, Pennsylvania drillers have
been sending their wastewater to Ohio for underground injection.
In the face of these hazards for water resources, states in the
region have responded differently. Pennsylvania and West Virginia have
the most active Marcellus Shale gas development and the most active
state regulatory programs. Conversely, not one horizontal Marcellus gas
well has yet been developed in Maryland or New York, and in fact,
drilling will not be permitted in the drinking watersheds for New York
City and Syracuse because of water quality concerns. New York has been
working on a study of the impacts of gas development since 2008, and is
on the verge of allowing active development in other parts of the state
in 2012. Maryland is undergoing a study to determine whether and how
Marcellus Shale gas development might occur in the state. A final
report is expected by August 2014.
II. Solutions
TU is actively involved at local, state, and federal levels to find
solutions which will allow well sited, well planned, and well executed
gas development. The large numbers of wells being developed in
Pennsylvania, and the hugely important trout fisheries which are a
hallmark of the state and its $1.3 billion angling-related economy,\10\
make it ground zero for our work.
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\10\ http://www.cenus.gov/prod/2008pubs/fhw06-pa.pdf
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To address the next challenge facing Pennsylvania's coldwater
streams, Trout Unlimited launched a Marcellus Shale campaign aimed at
working with state agencies and the industry to identify, avoid and
mitigate the impacts of gas development on trout populations and
coldwater habitat. Trout Unlimited and other sportsmen and women have
met with state regulators to discuss protections for ecologically-
sensitive watersheds and opportunities for improving monitoring,
oversight and enforcement of drilling related activities. We have
developed a partnership with a drilling company in southwest
Pennsylvania to create a model well pad site and demonstrate how best
management practices and appropriate well siting and design can
increase the likelihood that water resources and trout populations are
protected.
To provide an extra set of eyes and ears on the ground, Trout
Unlimited initiated the Pennsylvania Coldwater Conservation Corps in
2010. We have trained more than 200 volunteers to conduct stream
surveillance to monitor the impacts of Marcellus Shale development on
the commonwealth's valuable water resources. Our members conduct water
quality testing on sensitive coldwater streams and survey watersheds
for impacts associated with drilling-related activity where Marcellus
development is occurring or is projected to occur in the near future.
In the field, Trout Unlimited members are witnessing impacts that do
not always make the headlines.
Volunteer efforts and industry best practices form two legs of the
stool, with the third being effective regulations. Trout Unlimited
recommends the following changes to deal with the problems identified
above.
A. Erosion and sedimentation
Unlike other construction sites, due to an exemption provided
through the Energy Policy Act of 2005, oil and gas construction sites
are not covered by the Clean Water Act's stormwater provisions.\11\
This exemption prevents the application of Clean Water Act stormwater
runoff rules to the construction of exploration and production
facilities by oil and gas companies and the roads that service those
sites. In light of the impacts of construction-related stormwater from
natural gas development on fish habitat and water resources, this
exemption makes little sense and should be repealed.
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\11\ Section 323 of the Energy Policy Act of 2005, P.L. 109-58.
---------------------------------------------------------------------------
In Pennsylvania, an erosion and sediment control permit is required
only if a well operator is proposing five acres or more of earth
disturbance. However, the average Marcellus Shale well pad size in
Pennsylvania is approximately three acres--making the majority of well
pads exempt from the state's erosion and sediment control permit
requirements.\12\ Due in large part to gaps in regulatory oversight,
streams are turning turbid and muddy from the erosion, sedimentation
and runoff from nearby Marcellus construction sites.
---------------------------------------------------------------------------
\12\ Johnson, Nels (2010). Pennsylvania Energy Impacts Assessment,
Report 1: Marcellus Shale Natural Gas & Wind, p.9. The Nature
Conservancy, Pennsylvania Chapter.
---------------------------------------------------------------------------
B. Blowouts, leaks, spills and illegal discharges
Steps should be taken to reduce the risk of impacts to water,
including removal of the exemption to the Safe Drinking Water Act for
hydraulic fracturing. Some spills and other accidents may be
unavoidable. For these, we should reduce their direct impacts on water
resources by requiring setbacks from waterways for natural gas
infrastructure. Construction of well pads, compressor stations, storage
pits and other drilling infrastructure should not be authorized, at a
minimum, within 300 feet of surface waters. Well pad development and
construction of impoundments should be prohibited in 100-year
floodplains.
C. Water quantity concerns
In Pennsylvania, one-third of the state does not have a
comprehensive water withdrawal permitting program. While the state
requires each company to submit a Water Management Plan for drilling
within a region, the plan only requires identification of the source,
the amount, the counties where the water will be used and a low flow
analysis. The plan does not require monitoring to ensure compliance
with the permit or signage at the withdrawal site, making it difficult
for the public to know whether a withdrawal is legally permitted.
Additionally, while the plan is valid for five years, there is no
specific time restriction associated with the withdrawal and the
operator has 30 days to notify the DEP after initiation of the
withdrawal. At that point, the damage could be done. In the Ohio River
basin, the DEP established ``guidelines'' similar to the Susquehanna
River Basin Commission, but these are merely guidance-not requirements-
and DEP inspectors do not visit water withdrawal sites to ensure
compliance with the water management plan.\13\ Furthermore, the DEP has
never suspended a water withdrawal approval for drilling because of
inadequate streamflow conditions, even during recent drought
declaration periods.
---------------------------------------------------------------------------
\13\ Information provided by Scott Perry, Chief of Pennsylvania DEP
Bureau of Oil & Gas Management (12/28/10).
---------------------------------------------------------------------------
Pennsylvania's current water quantity management fails to
comprehensively manage the impacts on stream flows. State regulators
should conduct a cumulative impact assessment to determine how taking
billions of gallons of water out of a watershed will impact the small
headwater streams that provide integral ecosystem services for
downstream users and that support trout spawning. And where necessary,
the state should establish ecologically-based withdrawal limitations to
prevent damage to headwater streams.
D. Wastewater management
A comprehensive management plan for wastewater generated during the
drilling process, using a cradle-to-grave approach including
disclosure, tracking and proper treatment and disposal, must be
developed to protect valuable water resources. Trout Unlimited supports
the SEAB Committee's recommendation that regulators begin working with
industry and other stakeholders to develop and use an integrated water
management system. An integrated water management system should include
common principles, such as adoption of a life-cycle approach for
tracking and reporting all water flows throughout the process;
measurement and public reporting of the composition of water stocks and
flow throughout the process; and manifesting of all transfers of water
among locations.\14\ Real-time tracking systems should be required for
trucks hauling fresh water, flowback water and chemicals, including GPS
systems and electronic manifest systems, to allow for regulatory
entities and emergency personnel to track and respond to potential
accidents and to prevent haulers from disposing of drilling wastewater
illegally.
---------------------------------------------------------------------------
\14\ The SEAB Shale Gas Production Subcommittee Ninety-Day-Report--
August 11, 2011, p. 22.
---------------------------------------------------------------------------
In Pennsylvania, permits were issued, drilling began and wastewater
was generated before the industry or the state had a solid plan for
managing and treating wastewater. To date, short-term fixes have been
utilized to dispose of wastewater. However, as with any commercial
industrial sector, the natural gas drilling industry must invest in
long-term wastewater treatment and disposal solutions.
Finally, Trout Unlimited supports the SEAB Committee's
recommendation that regulatory entities immediately adopt rules for
full disclosure of the chemicals used in the fracturing process and the
chemical composition on a well-by-well basis. Such disclosure should be
made on a publicly available website.
The management actions described above would do much to reduce the
risk of harmful impacts on water resources and aquatic habitat from
natural gas development. However, it will never be possible to fully
eliminate the impacts of intensive energy development. The SEAB 90-Day
Report stated that: ``The combination of impacts from multiple drilling
and production operations, support infrastructure (pipelines, road
networks, etc.) and related activities can overwhelm ecosystems and
communities.'' Due to unavoidable impacts, Trout Unlimited supports the
SEAB recommendation to ``Declare unique and/or sensitive areas off-
limits to drilling and support infrastructure as determined through an
appropriate science-based process.'' Such areas include high quality
brook trout habitat identified through Trout Unlimited's Conservation
Success Index,\15\ for example key watersheds in the Monongahela
National Forest in West Virginia where no wells have yet been
permitted, and the George Washington National Forest, which now is
considering adopting a strong policy on horizontal drilling for natural
gas.
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\15\ http://www.tu.org/science/conservation-success-index
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III. Conclusion
Trout Unlimited thanks the subcommittee for holding this timely
hearing, and for its interest in the issue. There is no doubt that
natural gas is now, and will be, a major component of the nation's
energy supply. But gas development in the Marcellus region is harming
fish habitat and water resources, and the long term cumulative impacts
are not being adequately studied. Both of these facts are troubling to
those of us who care about balanced resource extraction.
We urge this Congress to take a more careful look at the full range
of gas development impacts on water resources, and to consider
reinstating the Clean Water Act stormwater and Safe Drinking Water Act
provisions that should right now be at work on the ground protecting
those resources from gas development.
Thank you for the opportunity to provide testimony today.

Senator Shaheen. Thank you very much, Ms. Dunlap.
I want to start with where you ended, which is, are you
suggesting that shale gas development should not have gotten an
exemption when it did in 2005?
Ms. Dunlap. I'm suggesting that perhaps at that time the
potential for erosion and sedimentation was not known. Most of
the development that is occurring in Pennsylvania is happening
in the upland-highland areas, and the relatively undeveloped
areas of Pennsylvania. This requires developing new roads to
access those areas and, of course, clearing forests to put in
place these wellpads, which are, on average, about 3 acres in
size.
Senator Shaheen. Given what Ms. Dunlap has said with
respect to some of the challenges that they've seen in
Pennsylvania, Mr. Beauduy, how does--that seems to be in
conflict with some of what you had to say about what the
commission that you serve on has been doing with respect to
overseeing and regulating what's going on with shale gas
development. So can you talk a little bit about some of the
concerns that she's raised, and what you've seen, and whether
you think what is currently going on with respect to regulation
is adequate?
Mr. Beauduy. She raises some very legitimate concerns. Our
role in this is, particularly in the headwater areas, is trying
to restrict withdrawals so that they don't cause impacts. Our
member jurisdictions are responsible for the sighting and
location of pad sites, access roads, and ENS related to this
activity.
Any time you have industrial activity in these areas,
you're going to have to have extremely tight controls in order
to be able to avoid impact. There have been impacts. We have a
few poster child examples in our Basin, a town in Dimock and a
few other places, where we've had well blowouts.
So we've had some activity like that, but the concern that
is raised about erosion sedimentation control is a legitimate
one. I indicated to you that our water quality monitoring
network is showing, at least on the chemical side that things
are staying within range, but some of the spikes that I
mentioned have to deal with those sediment loads getting into
the system. So, and we are providing that data to our member
jurisdictions, and they continue to evolve those programs and
those controls.
But I would agree that in terms of sensitive habitat in our
Basin, in the headwater areas, the greatest threat is probably
the issue of land disturbance more than anything else.
Senator Shaheen. So, should that be addressed through State
regulation? Is it that we don't have adequate enforcement of
current regulations? Should we expect that there should be more
sharing of best practices in the industry to help address that?
What's the answer to some of these concerns?
Mr. Beauduy. I think it's all of the above, quite honestly.
Yes. It's been a dynamic process.
Some of the traditional ENS mechanisms that have worked
elsewhere don't seem to be working with this industry. There
have been modifications. Some of our jurisdictions have
modified the delivery mechanisms and who's responsible for
overseeing that activity and permitting that activity.
So there are--it's an evolution right now, I will tell you
that. It's very dynamic, but that probably is the greatest
threat to the system right now, and that's land disturbance
activity. Particularly when you get into these mountainous
areas where, you know, you don't have a piece of flat ground
anywhere, and the potential for erosion is significant, and
it's directly discharged into headwater streams.
Headwater streams by definition scientifically, and I'm not
a scientist, but fundamentally what you'll see if you study the
science is that headwater streams don't have any flood plain.
You're talking about slopes that come right down to those
streams, and so therefore, any level of discharge off of these
sites is going to find its way into those streams, and can have
an impact.
Senator Shaheen. Thank you. I'm almost out of time, but I
wanted to go back, Ms. Wrotenbery, because you talked about the
Website for----
Ms. Wrotenbery. FracFocus?
Senator Shaheen. Yes. Thank you. I was--I had written it
down. That 5,000 wells are--have currently, voluntarily posted
on the Website the chemicals that they were using. How many
wells? That's 5,000 out of how many? Do you know? Because Ms.
Dunlap was just talking about 70,000 to 80,000, is that what
you said?
Ms. Dunlap. I said 50,000 to 80,000 projected in
Pennsylvania.
Ms. Wrotenbery. I'll say. I will try to get that
information for you. What I can tell you is the FracFocus site
is available for wells that were hydraulically fractured since
January 1. So, we've got 5,200 wells out of that universal
well.
Senator Shaheen. I'm trying to get some sense of, and what
we think is the percentage of companies that are voluntarily
posting that information.
Ms. Wrotenbery. I can tell you that was 49 different
companies that posted that information. We've got another 66
companies that have registered and intend to put information
about their wells on that site, and the specific information is
not up yet, but we expect it will be there.
As far as the percentage, I'll have to go back and do some
analysis, but I will follow up on that question to try to give
you a sense.
Senator Shaheen. Thank you. Dr. Cooper, did you want to add
to that?
Mr. Cooper. Yes, sure. I recently listened to some
testimony by Leslie Savage, the commissioner who works in the
Texas Railroad Commission and she concluded that almost half of
all hydraulically fractured wells in the Texas have been
reported on the FracFocus Website.
My company is very proud to have reported all of their
wells on the FracFocus Website. I realize that there are many
smaller operators in some parts of the world, and even here in
the Marcellus area that may not have been so generous with
their information. But I think that also States like Texas have
decided they're going to make everybody report, and I think
that's really happening across a broad swath of States.
Senator Shaheen. For those people who aren't reporting and
I certainly commend Apache for doing that, what's the
impediment to that? Because it gets interpreted as, ``They
don't want to report because they're worried about what
chemicals are being used and what the public's going to think
about those chemicals.'' So that, I fear, is the perception
that people have for those people not reporting.
Mr. Cooper. I think it's fair to say that everybody hates
big change, and no one really likes a lot of regulation. So
some people went kicking and screaming just for those reasons.
I think, though, that in reality when they got their heads
around what they were being asked to do, they thought it was a
really good idea. So, industry is rushing to provide that
information. There are some things that are being protected.
There are some really legitimate intellectual property issues,
and it's confidential business information that has to be
handled. So far, the proposals have had the State government
agencies get access to that information, but it wouldn't be
shared publicly.
I think that it's been a really good thing for companies
themselves, and I can say that our company has learned a great
deal about what we were buying from our vendors, and full
disclosure is a really great thing.
Thank you.
Senator Shaheen. Thanks, very much.
Senator Lee, I appreciate your patience.
Senator Lee. Thank you.
Ms. Wrotenbery, tell me a little bit about how FracFocus is
funded and what your funding requirements are on that?
Ms. Wrotenbery. FracFocus was developed initially with a
grant from the U.S. Department of Energy. That was the seed
money for the system. Along with that, there was an in-kind
contribution from the State participants in the process, and
the participation by other stakeholders.
Some of the enhancements that we've already seen to the
system, for instance, just within the last couple of weeks,
we've added a GIS component to that system. We've gotten some
support from the industry in developing some of that
enhancement. They've participated in the project on a kind of a
cost share basis. So we've got some additional funding there.
But we have submitted requests to the Department of Energy,
and EPA, and talked to some of the folks here on the Hill about
needs going forward for the system.
Senator Lee. OK. So you see that as sort of a model moving
forward to keep it going?
Ms. Wrotenbery. Definitely. It's a system that's in a state
of evolution. As we use it, we learn more about what's there,
and what's not there and what people need in order to be able
to access the information.
Senator Lee. Then how, and to what extent, do you find the
State regulators are using the system or taking advantage of
it?
Ms. Wrotenbery. The--what's happening at the State level,
States like Texas have recently adopted requirements that
companies submit chemical information on their frac fluids.
Typically what they've done is say if they use the FracFocus
site, that will satisfy their reporting requirements.
Senator Lee. Right. But that's probably----
Ms. Wrotenbery. So the States individually have addressed
their own funding needs there.
Senator Lee. Probably provides for a streamlining of their
regulatory burdens, then?
Ms. Wrotenbery. It does, and I will say Oklahoma is one of
the States that is considering a requirement that the companies
in Oklahoma use FracFocus.
Senator Lee. OK. Thank you.
Then, Mr. Beauduy, can you explain your in-stream
monitoring system a little bit, how that works? Particularly
with--I'm kind of curious as to how it works with regard to
this industry as compared to others.
Mr. Beauduy. The system--the system is comprised of, at
these 50 stations, of a specialized probe that's called a data
sonde that is put into the water. It's cabled to a data
platform on the shore, powered by solar, and either via
satellite or cell, it's--that data sonde is analyzing for 6
parameters on a continuous basis. Every 5 minutes, it's sending
that data to the data platform. Once an hour, that data is
uploaded to the computer system; that's to conserve battery
life. So that the data is never more than 1 hour old that's in
our system.
But we are looking at several parameters. One of the most
notable ones is conductance, because conductance will give you
an indication of metals and salt. So, if you see increases in
conductance, that means you've got an issue that doesn't
necessarily mean it's a gas operation that's causing that
problem, but----
Senator Lee. But it could be.
Mr. Beauduy. But it could be. These are indicators. This
system isn't designed to establish causation or anything else
like that. It is out there to monitor the system to see, is
dissolved oxygen changing? Is turbidity changing? Is
conductance changing? What are those values? You have to have
enough data in the system over a certain period of time in
order to be able to see basically background and what are the
natural fluctuations, either natural or human-induced, that are
normally going on in those watersheds. Then, how does that
compare to what you're seeing, you know, when the industry
comes into town and begins to frac, or begins to develop
wellsites, or put in access roads, or develop pipelines, or
anything else like that.
So it's--we're trying to build a baseline of data
throughout this network of watershed so that we can see if
there's any trend changes over time.
But also, there are alarms built-in to the system. So if
any one of those parameters gets exceeded over a certain level,
that triggers sampling and it triggers inspection. We notify
the agencies, the other agencies that actually actively
regulate water quality and provide them with that data so that
they know that there may be some incident occurring in that
watershed that needs an investigation.
Senator Lee. So once you can acquire that additional data
and view your initial warning data in context, you can usually
rule out the false, the possibility of a false-positive alert?
Mr. Beauduy. Yes, but it takes some time. It's a fairly
complicated analytical process that you have to go through and
a lot of QA/QC with the data. In fact, we pull those sondes
every 6 to 8 weeks, replace them in the field on a continuous
basis, bring them back to recalibrate just to make sure that
they're being--that they're very accurate on an ongoing basis.
We don't just stick them in and leave them there. Every 6 to 8
weeks they're being pulled, replacements put in, and then
having those ones that come out of the field recalibrated at
the lab.
Senator Lee. OK. I see my time's expired. Thank you, Madam
Chair.
Senator Shaheen. Thank you.
I want to go back and to your comments, Mr. Beauduy, about
virtually all of the water being recycled, the produced water
being recycled--
Mr. Beauduy. Yes.
Senator Shaheen. At this stage. Ask if that's consistent,
Ms. Dunlap, with what you've been seeing as you've looked at
the wells that are being done in Pennsylvania.
Ms. Dunlap. In large part, we believe that the industry is
recycling most of the wastewater that's coming back out of the
well. Now, we have--there's some discrepancy in exactly what's
happening. That information's not really made available
publicly.
We know that the Secretary of the DEP in May asked the
industry to voluntarily stop taking their wastewater to the
municipal treatment plants, and we know that many of them did
comply. We also know that the wastewater is being taken to Ohio
and in injected in underground injection wells there.
But in terms of the amount of water that's being recycled
and reused, I've been told through a report of the Marcellus
Shale Advisory Commission that was done in Pennsylvania that
about 15 percent of the water was actually being recycled and
reused.
Senator Shaheen. That's different than what you're seeing,
Mr. Beauduy, is that correct?
Mr. Beauduy. Yes. A number of the operations, the larger
operations are already at 100 percent recycling, but that's not
all of them. They all have that as an objective.
I think that what we don't have access to data-wise, but we
can get, we can try to provide it to you is we know how much is
being used/reused on frac operations. In fact, our profile data
that comes in from the industry on every frac job shows us that
over the last year, the industry is using about 1/2 million
gallons of flowback per frac job.
So of a 4 1/2 million gallon total quantity of water being
used for a frac operation, 1/2 million of that is flowback. So
that's the extent. It's about 12 to 15 percent by volume, but
that's not 12 to 15 percent of all the fluids being generated.
It's extremely costly for this industry to transport and
treat flowback. So if they can reuse it and they have the
ability to transport it from pad to pad to pad, that's what
they do. We've tried to incentivize that because we don't want
to see it going to discharge. But in our Basin, we don't have
that discharge. We do have 3 or 4 treatment facilities that
have been permitted to treat that material, but all that
material goes back out into the field for reuse on the next
frac job.
Senator Shaheen. OK.
Mr. Beauduy. But we are aware that there's a certain
percentage that is going to Ohio for deepwell injection. They
attempted to develop some deepwell injection capability in our
Basin. The formations are much too tight; it just won't take
it. Unless they give up the natural gas storage fields which
supply the Northeast, and they don't want to do that, and so
therefore deepwell injection is not an option in our Basin. So
it's either reuse or shipment to Ohio, and that's one of the
drivers for making sure that they recycle up to 100 percent of
it.
Senator Shaheen. Thank you.
Dr. Cooper, we were talking earlier about the transparency
with respect to use of chemicals in the process. I think, Ms.
Wrotenbery pointed out that Texas has required that now for
full disclosure. Should all States put in place that kind of a
requirement?
Mr. Cooper. So to clarify a little bit, Texas passed a law,
and the Texas Railroad Commission has proposed regulations, and
they are in their final review of the proposed regulations,
which they have suggested to industry, will be in force by the
1st of January. Certainly my company supports that Texas style
reporting everywhere.
Senator Shaheen. Does--do others want to weigh-in? Is this
something that should be done everywhere, Ms. Wrotenbery?
Ms. Wrotenbery. I will say there are other sites--States
besides Texas that have adopted chemical disclosure and
reporting requirements, and there are still others that are in
the process of considering it.
In Oklahoma, we're considering it at this point. We're
talking to the various stakeholders. There are--you talked
about why some companies may not already be reporting their
hydraulic fracturing chemicals on the Website yet.
I do know there are a number that are working on it, but
it's a new system. We're in a transition process where they're
trying to make sure they can get the information from the
companies that supply the chemicals and perform the hydraulic
fracturing operations for them. So, there is some work being
done to make sure that they can compile this information, and
get it reported fully and accurately to the system.
So it's an evolutionary process, and we're certainly
supportive of all companies using this system to report the
chemicals in their frac jobs.
Senator Shaheen. Should it be required by States?
Ms. Wrotenbery. That's something, you know, my agency is
going to have to address. We're seriously considering doing
that, but my commission hasn't made that call yet. So it would
be premature for me to comment on that one.
Senator Shaheen. OK. Mr. Beauduy.
Mr. Beauduy. Our commission supports the maximum amount of
transparency as possible. Particularly with this industry,
there's a lot of concern, there's a lot of misinformation. The
more transparent all of us that are involved in some aspect of
this industry, the more transparent we are, I think that the
better off we are as a country. I think that all of us are
moving in that direction.
We have invested millions to put applications online, to
put approvals online, to put monitoring data online of all
types; water use as well as water quality data. We believe that
as much data as can humanly possibly be made available and
transparent to the general public is a good thing.
Senator Shaheen. So I'd put you in the ``yes'' column.
Mr. Beauduy. Yes.
Senator Shaheen. Ms. Dunlap?
Ms. Dunlap. Yes, you can put Trout Unlimited in the yes''
column as well. We support full disclosure and that that
information be available to the public on a Website.
Senator Shaheen. Thank you.
I wanted to go back to the question about well casing and
cementing because I don't know if you heard me ask Ms.
Dougherty that question, Ms. Wrotenbery, but she suggested that
I defer it to you. So I wonder if you could respond whether
that's being adequately regulated at the State level the well
design including casing and cementing?
Ms. Wrotenbery. What I can tell you is the well casing and
cementing requirements are a core part of the State oil and gas
regulations.
We are in a process right now of reviewing whether our
historical casing and cementing requirements are adequate in
the shale gas development context, and what changes need to be
made to ensure that, that the casing and cementing procedure is
effective in isolating the fluids. You know, keeping them in
the zones until they're piped up to the surface and onto
market, and that freshwater resources are protected in that
process. Many States are in the process of evaluating those
requirements.
Pennsylvania has already completed an evaluation. Ohio has
done an extensive review of their requirements. We've been--
we've amended some of our rules in the last couple of years to
make sure we've got good, strong rules in place.
So it is a critical component of an oil and gas regulatory
program, and the States are in the process of evaluating their
requirements to make sure they're strong and effective.
Senator Shaheen. What have you learned in Pennsylvania, Mr.
Beauduy?
Mr. Beauduy. The commonwealth has learned quite a bit. What
we have seen in the Basin, the stray, we refer to it as the
stray gas issue, has been the dominant issue in terms of
impacts from this industry. Places like Dimock, Pennsylvania
where we've got methane that's getting to fresh groundwater
systems. That's the result of improper--one of the questions is
are the standards adequate as opposed to whether they were--
whether the activity was conducted properly within those
standards?
What Pennsylvania found out after a series of stray gas
incidents is that, as you just heard, newer technologies are
brought to bear. They've enhanced their casing standards. We
haven't seen any issues with the new standards. There have been
incidents at the wells done under the older standards, and
they've had to either shut them in or redo them.
But stray gas has been an issue and not so much Marcellus
gas. This is, you know, when you're going down 7,000 feet, you
get below the freshwater bearing table at, say, 300 to 700
feet, you hit other formations. They all have a certain amount
of gas in them and it's these upper horizon formations that can
leach and have gas go up the wellbore and into fresh
groundwater. The new standards are designed to do that.
The other thing--aspect of the new standards, which I think
I have to commend them for, is the testing that has to e done,
the integrity testing to make sure that the construction was
done properly. So as we get better capability, I think those
will be improved even more.
But we were very pleased to see Pennsylvania move forward,
once it realized that it had a problem, and upgrade. As far as
I know, their standards are as strong as any in the country
right now.
Senator Shaheen. Thank you very much.
I think this is a final question for you, Dr. Cooper. One
of the things that has inhibited the ability to get data about
some of the challenges and the problems that have occurred with
fracking and getting access to shale gas has been that when
there is an issue with a property owner, that often the
property owner signs a nondisclosure agreement so that that
information is then not available to add to the research, as
we're thinking about how to solve those problems going forward.
Is there anything that you can talk about with respect to
the industry that you think might help with that issue?
Dr. Cooper. I think they are very large issues that have
nothing to do with fracking that you're talking about. You're
talking about how knowledge is dispersed in our society, about
how the media plays into it, about how people like
sensationalism as opposed to sort of being calm and realizing
what actually might have happened.
I think that, you know, in our society, I call it lawyering
up.'' Around here, you probably all understand that.
Senator Shaheen. I'm not an attorney, so I----
Dr. Cooper. Neither am I, so. You know, when incidents
happen, it's hard for everybody to be open about what's
happening until legal issues are resolved.
I do think that the industry actually has a very good, long
term understanding that sharing knowledge between companies
about what went wrong is a central part of our business. We do
that all the time. It's an ongoing thing. It isn't just to rush
in and say, ``Oh, it happened at that one well incident,'' but
it's about the safety of our systems in general.
We do have professional organizations that very carefully
analyze data to look at cement failure, for instance, and why
it might happen under certain circumstances, and that
information is shared across the industry.
You know, I tell people, you know, ``You think that Apple
is really innovative? The oil and gas business is pretty
innovative too. You just don't notice it.''
We don't stand still. We try to fix problems. We try to
understand. We apply a lot of high technology to what we do and
I think this is a very essential part of our business.
So lawyering up will always happen. But the industry is
going to try to figure out why things happen and solve the
problem.
Senator Shaheen. As you point out, most of us don't walk
around with an ``iDrill'' like we have our iPad.
Mr. Cooper. I think that's right.
Senator Shaheen. Let me just, before I close, point out
that I would be remiss if I didn't call attention to the story
that appeared on the front page of ``The New York Times'' today
about the challenges with respect to mortgages, and property
owners who have signed agreements with--for gas drilling, and
some of the issues that are expected going forward.
Is that anything that you've seen, Dr. Cooper, in your
company?
Dr. Cooper. No. Actually, I was sort of amused by this
story because my initial reaction was, ``Gee, all of a sudden
these guys have money to pay for their mortgages because they
just got paid some sort of lease fee for their mineral
rights.''
I thought that in places like, you know, Oklahoma and Texas
where people think those mineral rights are a really valuable
resource, you know, sometimes they even get severed from
property. I think they look at it as, you know, if you're a
banker, you'd look at it as a reason that you'd get your money
back as opposed to losing it on the guy's mortgage.
I'm not--I don't want to be flippant about anybody and the
problems they have with the economy, and mortgages, and stuff
like that. But I think the issue sounds a little strange to me.
Senator Shaheen. So you haven't seen it. Has anybody else
heard that this is an issue? Ms. Dunlap?
Ms. Dunlap. Yes, this is, of course, a little off topic
from trout but.
Senator Shaheen. Right.
Ms. Dunlap. I do live in the Finger Lakes region of New
York State, and I do know that there are some banks who are
concerned there that a person who has leased their subsurface
mineral rights, who then goes to sell that house, the
prospective buyer will not be able to obtain a mortgage.
Apparently, that has to do with the setback requirements under
Fannie Mae/Freddie Mac mortgage requirements, some sort of
secondary mortgage requirement.
So I have heard some--some stories in our region about
concerns from banks and potential sellers.
Senator Shaheen. As you say, it's off topic of today's
hearing, but it was an interesting story, and it doesn't sound
like it's got too much--having too much impact on the industry.
So Senator Lee, any final comments you would like to make?
Hearing none. Thank you all very much. Your testimony's
been very insightful and we really appreciate your staying with
us a little later than expected.
At this time, I'll close the hearing.
[Whereupon, at 4:42 p.m., the hearing was adjourned.]

APPENDIX

Responses to Additional Questions

----------

Responses of Cal Cooper to Questions From Senator Shaheen

Question 1. Can you speak to industry's process for implementing
best management practices or standards to keep pace with the drilling
and production activities with the bounds of sustainable water use?
Answer. We do have formal industry processes for reviewing
innovation and establishing ``best practices.'' Some of the most
effective ``best practice guidelines'' have been established by
technical committees of the API. Specifically for water, in nearly all
oil and gas producing states there is little ambiguity about best
management practices for sustainable water use. Water withdrawal is
governed by local authorities from property owners to state agencies.
As for the processes in place to ensure sustainable water use, we do
not wait until something is formally declared a best practice before we
adopt it. Best management practices are constantly evolving and
responding to challenges in this industry. Someone tries something new
or sees that some other operator has done something interesting, and
broadens the scope. And there is productive dialogue between different
companies regarding the success of technology. In a very practical
sense, the structure of this industry allows companies to see something
that works better and apply it. Sometimes this is encouraged by the
observations of regulators.
For example, injection wells in Pennsylvania and the Marcellus
Basin are simply not capable of dealing with the volumes of water
required for drilling. In this area, best practices have significantly
advanced over the past three to five years. Earlier this year,
Pennsylvania required all operators to recycle fluids in subsequent
frac jobs instead of disposing them in publicly owned treatment works
(POTW). As development continues, so too does environmental sensitivity
to emerging concepts like surface storage and enhanced wastewater
treatment.
Question 2. In your experience, what steps can be taken to reduce
erosion and sediment run-off into streams from road and pad
construction?
Answer. Many construction related industries have developed
effective controls for sediment erosion and stream runoff. And in most
of these cases, success involves rather simple efforts to prevent and
block sediment flow in unwanted areas. The oil and gas industry is
really no different than any other construction industry in this
regard. It continues to employ proven simple and effective measures to
mitigate surface damage.
You mention better efforts by the industry to disclose the chemical
composition of the fracking fluids.
Question 3a. What is prohibiting the industry from disclosing their
fracking fluids prior to drilling so that communities can be made aware
ahead of time?
Answer. In a general way, disclosure vehicles like FracFocus make
it possible for the public to see chemicals used by companies in
particular geographic areas. From a more practical point of view, the
precise chemicals used in any given frac job are subject to changes in
both planning and availability, which makes substitutions commonplace.
Quite a bit can change in a matter of seconds and successful extraction
depends upon adaptability. Furthermore, it is hugely expensive to stop
or slow completion of any given frac job. If a state wishes to
discourage or even ban certain chemicals, FracFocus provides solid
information for them to use in the decision making process.
Question 3b. What steps is the industry taking to ensure their safe
use and disposal?
Answer. Industry is committed to the safe transportation, delivery,
and use of chemicals on well pads. In addition to protecting the
surrounding environment, proper handling protects our people at work on
these well-pads. It is a personnel issue as well as an environmental
one. There are many strategies that ensure safe chemical transportation
from the creation of impoundments to lining well-pads to mixing
chemicals in large blender machines. For further enumeration, I invite
the committee to see examples at: http://fracfocus.org/.
Question 4. The NY Times recently published a story on the negative
financial impacts to a local Pennsylvania community that showed
residents weren't able to get the new high paying jobs associated with
the industry due to a lack of skills. Is industry doing anything to
close this gap and ensure that the local community derives maximum
benefit?
Answer. We remind the committee that Apache does not operate in the
Marcellus Basin. That being said, the industry generally has a range of
training and educational requirements for jobs related to hydraulic
fracturing. We need people from high school graduates to commercial
truck drivers to highly specialized chemists and engineers. However,
the financial benefit of shale gas development is not limited to the
immediate area of drilling itself. While it certainly benefits local
communities, industry presence also drives regional and statewide
economies in a larger sense. As a result, the economic value of
exploration spills over to all kinds of people who may or may not be
directly linked to oil and gas.
Question 5. Are there any incentives that you can identify that
would encourage operators to responsibly manage wastewater at the
surface?
Answer. Operators are motived by financial incentives as well as
the continued license to operate in a region. They will immediately
embrace economically advantageous ways of dealing with water that can
include sensible and sustainable environmental practices. The notion
that environmental sensitivity comes at greater cost to operation is
flawed. At Apache, we are evolving practices that unite financial and
environmental sensibility.
Question 6. Looking at the Pennsylvania Department of Environmental
Protection's (DEP) own numbers for the past two years, every well
inspection discovers roughly two violations. And these don't appear to
be merely technical violations. Violations include:

``Discharge of pollutional material to waters of
Commonwealth.''
``Failure to report defective, insufficient, or improperly
cemented casing w/in 24 hrs or submit plan to correct w/in 30
days''
``Failure to report release of substance threatening or
causing pollution''
``Improper casing to protect fresh groundwater''

Answer. For response, see Question 7.
Question 7. Does two violations for every inspected well strike you
as an acceptable level of industry compliance? Does the Apache
Corporation have information on the number of violations per inspected
well for its own wells?
Answer. We support the efforts of individual states to inspect and
verify well sites. Two violations for every inspected well is not
acceptable, although it does indicate the efficiency of state
regulatory bodies in ensuring industry compliance.
Specific to Apache, we operate in Texas, New Mexico, Louisiana, and
Oklahoma where in the past two years there have been more than 800
agency inspections performed at our operating sites. In total, there
were 168 noted deficiencies (these include both administrative and
operational items). Two compliance orders were issued and one penalty
was paid to a regulatory agency. So on average Apache experiences a
deficiency in one of every five recorded inspections. This also means
that more that 79% of Apache's inspected operational facilities were
found compliant with regulatory standards.
It is worth noting that while records indicate 807 inspections, the
actual number was almost certainly greater. Regulatory agencies
routinely visit sites at their own discretion. In unmanned facilities
inspections are commonly conducted without our knowledge. In these
cases, Apache is only notified if there is a deficiency.

Responses of Cal Cooper to Questions From Senator Lee

Question 1. Dr. Cooper, you mentioned in your testimony that state
permitted deep injection wells--the safest, most efficient and
economical way to deal with water--are not practical because of the
geology in many areas of the Marcellus. As you rightly point out,
necessity is often the mother of invention and now nearly all operators
report that they store, treat and re-use water, in subsequent hydraulic
fracturing jobs, minimizing the need to transport produced water to
water treatment facilities. Can you please describe this industry trend
as you have seen it? Is this only going on in the Marcellus, or are you
seeing the industry taking this step across the country?
Answer. In parts of the country with water access issues such as
Texas and North Dakota, industry is identifying ways to recycle used
water in subsequent frac jobs. It should be noted that this process is
an emerging trend. Currently, it is standard practice to re-inject
extracted water into disposal wells. In coming years we expect that it
will become more common for companies to treat water for reuse. With
that said, movement towards recycling treated water depends heavily
upon the comfort of regulatory agencies with this practice.
Question 2. Can you please describe Apache's water management
approach throughout the hydraulic fracturing process?
Answer. In areas where Apache does not use saline brines, as we do
in the Debolt formation, we purchase water from local owners and public
suppliers. As a result, we are keenly aware of water quantity and use.
The fresh water we purchase is often stored in holding ponds where it
is kept for later use at the well site. At times this can require the
transportation of water over several miles in irrigation pipes to a
given well site. If water is trucked on to site, it is immediately put
in to holding tanks or placed on trucks for direct mixture in to wells.
Flow back and produced water is then sent to tanks on site where it is
partially treated and then trucked to treatment plants offsite. It is
then re-injected in to licensed disposal wells.
Apache is paying for this water and we aim to use it as efficiently
as possible. We are currently investigating plans to build treatment
facilities to recycle produced fluids for later frac jobs. This is an
emerging concept and is sure to progress as available technology begins
to keep pace with industry innovation.

Response of Cal Cooper to Question From Senator Coons

Question 1. It is my understanding that there may be several new
and innovative ideas and technologies that will reduce the
environmental impact of hydraulic fracturing such as using saline
instead of fresh water in the fracturing process or actually using
natural gas in place of the liquid fracturing solution. What do you
think are some of the most innovative emerging technologies on the
horizon and how can the federal government work with private sector
interests do to help bring these technologies into commercial
operations?
Answer. The oil and gas production business has a long tradition of
making enormous strides in both innovation and technology. Yet it is
admittedly difficult to pinpoint the precise origin of many of these
developments and even more challenging to predict future winners. The
industry has a large number of inter-connected service companies and a
lot of motivation to try things. In general, we all benefit from
sustained innovation in the fields of science, technology and
engineering in universities throughout the world. More crucially we
rely on a talented and pioneering workforce that transforms practices
in the private sector.
In the specific case of hydraulic fracturing related research and
development, much of the success came from leveraging applied
engineering, and the willingness of independent operators to risk
trying new things. Neither major oil companies nor university research
were needed to get started. Arguably, we have reached a stage where
advanced technical innovations very well might make step changes in our
processes. These will come from the technology development machine that
includes universities and private companies. There are some latent
concerns that regulations may stifle innovation due to hysterical
exaggerations of risk.
The industry already engages in some very useful sponsored research
initiatives at a number of universities, although it is rare for
smaller companies to participate. Perhaps it would be helpful to have
some matching funds program in order to broaden the base, without
establishing a huge administrative bureaucracy. Perhaps R & D tax
credits would encourage more spending in this area. Surely we will all
benefit from programs that encourage youth to pursue their research
interests in applied science and engineering in general. Investing in
people is the key to sustaining future success.
______

Responses of Katy Dunlap to Questions From Senator Shaheen

Question 1. We have heard from several of our witnesses that the
necessary regulations and procedures are in place to adequately protect
public health and the environment but you have raised specific examples
of contamination and in your opinion what accounts for this
discrepancy?
Answer. Trout Unlimited's testimony at the hearing on Shale Gas
Development and Water Resources in the Eastern United States focused
largely on the surface impacts of Marcellus Shale development in
Pennsylvania. Specifically, I explained that Trout Unlimited members
are witnessing significant erosion and sedimentation runoff from well
pad, access road and pipeline construction, as well as impacts from
spills, leaks and illegal discharges of drilling wastewater. The reason
for the discrepancy may be a tendency to overlook surface impacts such
as those associated with erosion and sedimentation. In large part, the
growing number of water resource pollution incidents from oil and gas
development has resulted from the absence of federal and state
regulation.
Due to an exemption provided through the Energy Policy Act of 2005,
oil and gas construction sites, including the construction of
exploration and production facilities by oil and gas companies and the
roads that service those sites, are not covered by the Clean Water
Act's stormwater runoff provisions. In Pennsylvania, the Department of
Environmental Protection (DEP) only requires an erosion and sediment
control permit for earth disturbances of five acres or more. As the
average Marcellus well pad size in Pennsylvania is approximately three
acres in size, the five acre threshold required to obtain a permit
excludes the majority of well pads. The gap in erosion and sediment
control regulation at both the federal and state levels is a
contributing factor to the increasing volume of erosion and
sedimentation pollution incidents and may lead to long-term water
quality impacts and overall degradation in watersheds where drilling is
prolific.
Spills, leaks and illegal discharges from Marcellus Shale-related
development are posing risks to valuable trout streams and to
groundwater resources. Regulation of the hydraulic fracturing process
under the Safe Drinking Water Act could help to minimize these types of
pollution incidents. While some accidents are unavoidable, in many
cases, contamination of water resources could have been evaded if the
well pad and other related infrastructure was set back an appropriate
distance from waterways. In Pennsylvania, the well bore can be as close
as 100 feet to a stream. Again, given that the average well pad is
approximately three acres in size, this means that a well pad can be
constructed right next to a stream. Additionally, well pads may be
constructed in the 100-year floodplain meaning that when a major flood
event occurs, contaminants on the well pad itself may be carried
downstream with floodwaters. To reduce the risk of contamination from
spills, leaks and illegal discharges, oil and gas-related development
should not be allowed in the floodplain and adequate buffers-of at
least 300 feet from the edge of a well pad-must be required.
Question 2. Do you think that hydraulic fracturing can be conducted
in a responsible manner to enable extraction but prevent environmental
impacts? If so, how?
Answer. Hydraulic fracturing for natural gas development requires a
substantial amount of infrastructure development and carries the risk
of spills, blowouts, and other impacts. The level of ground disturbance
alone makes it impossible to prevent environmental impacts altogether.
However, hydraulic fracturing can be conducted responsibly. Through
proper siting and management, the risks can be reduced and the
environmental impacts minimized.

Much of the natural gas development in the East occurs in
forested areas. When forests are cleared and roads, pipelines,
and well pads are constructed, the hydrology in a watershed
changes, and surface runoff increases. The affect of these
changes on water resources and aquatic habitat can be reduced
through consistent and effective stormwater controls.
Road-stream crossings present a risk of aquatic habitat
fragmentation. Constructing crossings with properly sized and
designed culverts or bridges can prevent fragmentation and
enable fish and other aquatic organisms to move freely up- and
downstream.
Water withdrawals, if taken from small waterways or during
low flow conditions, can harm aquatic ecosystems. The right
timing and location of water withdrawals can avoid such
impacts.
Waste water from shale gas development carries pollutants
that can harm water resources if improperly treated and
discharged. Sound wastewater management can reduce these risks.
Well blowouts have introduced pollutants to waterways and
caused harm to water resources. These can be reduced through
proper well casing and pressure testing requirements.

The steps listed above are components of responsible development
that can help to avoid or reduce the impacts of natural gas development
on water resources. However, development will never be 100 percent
risk-free or without impact. In recognition of this, it is important to
properly site infrastructure so that when spills or blowouts occur, or
runoff controls fail, the impact on water resources is minimized. For
example, development should not be allowed in the floodplain and
adequate buffers-of at least 300 feet from the edge of a well pad-must
be required. Certain areas of high sensitivity or exceptional habitat
value should be avoided altogether.
Finally, the disclosure of chemicals used in hydraulic fracturing
would provide needed information to regulators, managers and the public
to help avoid or mitigate impacts to water resources.
Question 3. In areas that have been impacted from shale gas
development, what will be required to mitigate and/or reverse the
damages?
Answer. Many of the impacts from shale gas development on water
resources-both groundwater and surface waters-may not be known for
decades. As we have seen with coal mine extraction in Pennsylvania, it
takes time for the impacts of industrial energy extraction to
materialize, and then decades to restore streams and waterways from the
resulting pollution. In Pennsylvania, at least $70 million in grant
money has been distributed to conservation and restoration efforts over
the past decade to try to clean up acid mine drainage that resulted
from coal production. Much of the damage could have been avoided if
adequate regulations were in place before the resource was developed.
The same planning concept holds true for shale gas development.
Marcellus Shale gas has been developed at a rapid pace and large scale
across Pennsylvania over the past three years, before the state
realized that its regulations were inadequate to assure protection of
water resources. Pennsylvania has since recognized that it needs to
update its regulations to address the new and different types of
impacts that will result from shale gas development and is making
strides toward that aim. Many of the impacts from shale gas development
can be avoided up front, with the proper regulations.
Each company uses a proprietary blend of chemical, lubricants and
other drilling fluid to fracture a well, and that ingredient list
changes with each well depending upon the chemical and physical
properties of the reservoir being accessed. Therefore, it is difficult
to know at this time the precise level and severity of impacts that
will result when specific fracturing chemicals are used in combinations
or independently. In order to mitigate or reduce the risk of water
quality impacts associated with contamination from drilling wastewater
and fluids, shale gas development and hydraulic fracturing should be
regulated under the Safe Drinking Water Act and the public disclosure
of chemicals used during hydraulic fracturing should be made mandatory.
Continued erosion and sedimentation will lead to degradation of water
resources and loss of aquatic life. Oil and gas exemptions from the
stormwater runoff rules under the Clean Water Act should be repealed to
avoid the slow, long-term degradation of water resources.
If the appropriate regulations are not in place now-as Marcellus
Shale gas resources are being developed-then it will take significant
financial resources and time to restore waterways and aquatic life to
pre-development condition.
Question 4. What happens to wildlife and ecosystem health if too
much water is pulled from the water supply for industrial/municipal
purposes-particularly during low water periods?
Answer. Healthy streamflows support native fish, wildlife and
instream and streamside habitat. Streamflow is the principal driver for
all stream ecology, directly affecting channel formation, habitat, fish
migration, temperature, oxygen levels and numerous other critical
factors. Water withdrawals for industrial and municipal purposes can
alter naturally varying streamflows, and affect the amount of water
available for stream function, aquatic life and downstream users. Trout
and other aquatic life, as well as streamside wildlife, rely on natural
fluctuations to support their life cycles.
The timing, location and volume of the water withdrawal will
determine the level of impact on the river system and aquatic life. If
significant volumes of water are withdrawn from small headwater streams
during natural low flow periods, streambeds can dry up-killing the
aquatic life that resides therein or affecting trout spawning, thereby
influencing overall population stability. During summer months when
stream flows are naturally low, large water withdrawals can also impact
water quality and the ability of a stream system to dilute potential
pollutants, and exacerbate water temperature increases.
Question 5. We heard from our first panel regarding issues that
arise when produced water is sent to traditional treatment plants. Can
you discuss whether this was happening in Pennsylvania and New York and
whether it will be allowed going forward?
Answer. Until recently, several traditional wastewater treatment
plants in Pennsylvania were accepting shale gas wastewater for
treatment and then discharging treated wastewater into the
commonwealth's waterways. Because most treatment plants were designed
to treat biological wastes and not brine water containing chemicals
used in hydraulic fracturing, the receiving streams were showing high
levels of total dissolved solids and chlorides. Last week, Professor
Jeanne VanBriesen, a civil and environmental engineering professor from
Carnegie Mellon University, concluded a two-year study that found that
bromide and chloride levels-both components of total dissolved solids-
started to increase in 2010 in eight sampling locations near public
drinking water intakes in the Monongahela River.\1\ Professor
VanBriesen pointed to produced wastewater from Marcellus Shale drilling
operations as a potential cause in the increased levels.
---------------------------------------------------------------------------
\1\ http://www.post-gazette.com/pg/11308/1187389-113.stm
---------------------------------------------------------------------------
In early 2010, a specific incident along the Monongahela River that
reportedly fouled a water intake of a large water supplier spurred
attention to the pretreatment standards for shale gas wastewater that
is ultimately sent to a wastewater treatment plant that intends to
discharge its effluent into a stream. In response to that incident, the
Pennsylvania Environmental Quality Board adopted changes to the rules
generally, with specific rules for the natural gas industry. Wastewater
from natural gas operations may not be discharged into a sewage
treatment plant that in turn discharges to a stream unless that
wastewater has a concentration of total dissolved solids (TDS) below
500 milligrams/liter. Some wastewater treatment plants were
``grandfathered'' and exempt from the TDS rule.
In New York, several wastewater treatment plants in the Finger
Lakes region have, in the past, accepted Marcellus Shale wastewater.
The City of Auburn Water Pollution Control Facility reportedly received
more than 16 million gallons of gas well drilling process wastewater
from 7/1/09 to 6/30/10, from more than eight gas companies and certain
parameters known to be constituents of Marcellus Shale wastewater, like
total dissolved standards, were not sampled.\2\ The facility discharges
into Owasco outlet, and reports have indicated that the estimated
Chloride concentration in Owasco outlet downstream of Auburn WPCP
outfall was elevated. The Canandaigua Wastewater Treatment Facility
reportedly received 177,000 gallons of gas drilling wastewater
generated in Pennsylvania by EOG Resources, Inc.\3\ These facilities
have reported that they are no longer accepting Marcellus Shale
wastewater.
---------------------------------------------------------------------------
\2\ http://toxicstargeting.com/sites/default/files/pdfs/
AubDEC__Jan09letter-NSmrkd.pdf
\3\ http://toxicstargeting.com/sites/default/files/pdfs/EOG-26R-
part-1-2-3-18.pdf
---------------------------------------------------------------------------
As stated earlier, the overall degradation of water quality and
related impacts that may be caused by years of discharging diluted
Marcellus Shale wastewater into streams and rivers may not be known for
decades.
Question 6. What steps are being taken by states in the Marcellus
region to prevent or even prohibit produced water from going to
wastewater treatment facilities that are not equipped to handle this
kind of water?
Answer. In April 2011, the Secretary of the Pennsylvania Department
of Environmental Protection (DEP) asked natural gas operators to stop
taking wastewater from shale gas operations to wastewater treatment
facilities and asked the operators to certify under penalty of law that
they were no longer accepting shale gas wastewater. Several treatment
facilities are exempt from the TDS rules adopted in 2010. To further
restrict the number of exempt facilities that may accept shale gas
wastewater, the DEP is proposing new chloride limitations for shale gas
wastewater.
According to the Commissioner of the New York State Department of
Environmental Conservation (DEC), no private industrial treatment
plants or traditional wastewater treatment plants in New York are
equipped to treat, or are permitted to accept, wastewater with the
range of contaminants expected to be in fluids produced from high-
volume hydraulic fracturing. In September, the DEC issued a revised
draft supplemental generic environmental impact statement (revised
DSGEIS) intended to assess the environmental impacts associated with
high-volume hydraulic fracturing. In its environmental review plan, the
DEC is proposing to require a comprehensive analysis demonstrating that
wastewater treatment plants can safely treat the waste before DEC will
grant or modify a State Pollution Discharge Elimination System (SPDES)
permit. At this time, New York has not yet conducted a full cumulative
impact assessment to determine how much wastewater will be generated,
how it will be transported and how it will be treated and disposed of,
and the state is essentially leaving it to the industry to find
solutions for addressing treatment and disposal of wastewater from
drilling operations.
Recycling has been widely hailed as a solution to many of the
issues related to the problems associated with water consumption and
waste water disposal.
Question 7. Yet, there have been reports that as recycling becomes
more common, the result is a briny byproduct that is more concentrated
with radioactive materials and other contaminants. It has been reported
that these brine waste streams are being sold to Pennsylvania counties
as road deicers or used as dust suppressants, from which they could
wash into rivers and streams. Are you concerned that such uses threaten
water quality and potentially endanger human health? What kind of
reaction did these reports generate in the local communities?
Answer. Trout Unlimited is very concerned about the use of shale
gas wastewater for de-icing and dust suppression purposes. A
significant amount of the Marcellus Shale development is occurring in
highland, largely undeveloped areas, with thousands of miles of dirt
roads that run along streams. If nearby shale gas wastewater tanks or
ponds are tapped to suppress dust on dirt access roads or to de-ice
roads, there could be significant impacts to the headwater streams that
support trout spawning and feed larger rivers and public drinking water
supplies.
In New York, the DEC has permitted, with conditions, the
``beneficial use'' of wastewater from non-shale vertical wells for de-
icing roads and suppressing dust on dirt roads. However, according to
the new revised DSGEIS for high volume hydraulic fracturing, flowback
water from any formation including the Marcellus may not be spread on
roads. The revised DSGEIS states that beneficial use determinations for
reuse of production brine from Marcellus Shale will not be issued until
additional data on naturally occurring radioactive material (NORM)
content is available and evaluated.
In Pennsylvania, a general permit (WMGR064) is required to apply
natural gas wastewater to roads for de-icing purposes and the permit
sets certain water quality parameters for known constituents of natural
gas wastewater, such as total dissolved solids (>170,000 mg/l) or
chlorides (>80,000 mg/l). The permit does not include parameters for
other constituents of concern known to be present in Marcellus Shale
produced water and flowback, such as strontium, bromide, radiologicals,
surfactants and biocides. DEP staff has reported that they are not
aware of any Marcellus Shale wastewater being used to de-ice roads
pursuant to the general permit. However, the general permit does not
include specific language prohibiting the application of Marcellus
Shale gas wastewater to roads. In fact, DEP is currently accepting
public comments on whether the permit should be expanded to include
dust suppression purposes and whether the permit should be amended to
specifically include or exclude application of Marcellus Shale
wastewater on roads.
Communities are confused and are expressing concern about the use
of Marcellus Shale wastewater for road application, whether for de-
icing purposes or for dust suppression. Concerns stem in part from the
lack of transparency and clear language prohibiting the use of
Marcellus Shale gas wastewater for road application. In the northeast,
the use of road salt in general contributes to the degradation of
groundwater in urban areas and water quality in suburban streams and
even in cleaner, rural streams. As shale gas wastewater could contain
additional polluting contaminants, communities and conservation
organizations are deeply concerned about the application of this brine
source to roads.

Responses of Katy Dunlap to Questions From Senator Lee

Question 1. Are you working with State regulators to ensure that
your interests are being addressed? What has generally been the process
through which you have communicated your concerns?
Answer. Individually and through the Sportsmen Alliance for
Marcellus Conservation, Trout Unlimited has developed a set of policy
recommendations and regulations for improving oversight of Marcellus
Shale gas development. Trout Unlimited has provided feedback and input
to Pennsylvania regulators through meetings with the Secretary of the
Department of Environmental Protection, the Lt. Governor, state
legislators and representatives from the DEP Bureau of Oil and Gas
Management. Additionally, Trout Unlimited has submitted written
recommendations to the Governor's Marcellus Shale Advisory Commission
and comments on state regulatory processes related to shale gas
development, including proposed casing and cement standards and total
dissolved solid standards for wastewater treatment plants proposing to
accept shale gas wastewater.
Question 2. Please describe the process you undertake to train
volunteers to do water quality sampling.
Answer. In 2010, TU launched its Coldwater Conservation Corps (CCC)
program-a stream surveillance program designed to train TU members and
other sportsmen and women to (1) conduct routine inspections of stream
conditions in watersheds where shale gas development is occurring or is
projected to occur, and (2) to report problems to the appropriate
agencies. Trout Unlimited members spend considerable time on these
streams, and thus are well positioned to monitor water quality in areas
where Marcellus Shale development is occurring.
The CCC program is based upon a field manual developed by Trout
Unlimited, with input and review by experts from the Pennsylvania
Department of Environmental Protection, Pennsylvania Fish and Boat
Commission, the Potter County Conservation District, the Alliance for
Aquatic Resource Monitoring and the Pennsylvania Council of Trout
Unlimited and local chapters. CCC volunteers undertake a full-day
training focused on material found in the field manual, including: (1)
learning how to conduct water quality monitoring and collect soil
samples; (2) determining what types of activities or impacts to look
for during visual assessments; (3) learning about personal conduct and
safety; and (4) determining whom to contact if a problem is suspected.
Water quality parameters sampled include flow, pH, temperature, total
dissolved solids (TDS) and conductivity. The Alliance for Aquatic
Resource Monitoring (ALLARM), based at Dickinson College, provides
quality assurance/quality control and technical support. TU staff
members conduct trainings, provide monitoring kits to local TU
chapters, assist volunteers in choosing monitoring sites, and assist
with data collection and data storage. In the first year of the
Coldwater Conservation Corps program, approximately 200 volunteers were
trained to monitor sensitive watersheds throughout Pennsylvania's
Marcellus Shale region.
Question 3. TU has recently established a partnership with the gas
producing company EQT. Can you describe the parameters of your
agreement and what are your primary areas of concern?
Answer. TU and EQT established a letter of understanding in April
2011 in order to develop a collaborative project between our two
entities focused on the review, evaluation, and potential development
of drilling siting and operation practices for the protection of
sensitive trout habitat.
______

Responses of Lori Wrotenbery to Questions From Senator Shaheen

Question 1. What regulatory steps/requirements pertaining to water
are different in the East than elsewhere? Have these steps had a
measureable affect on preventing industrial accidents and protecting
citizens?
Answer. The regulatory structure pertaining to water is complex.
Understanding what the requirements are and how they work to prevent
and manage accidents and to protect water supplies requires an in-depth
review of the specific set of requirements applicable in each
jurisdiction. Key differences exist not just from West to East, but
also from state to state within a particular region.
A comparative analysis of state regulatory programs would find many
common elements in state oil and gas regulations across the country,
but would also reveal that the states have tailored their regulations
to address regional circumstances and issues. I would again refer you
to the STRONGER reports on the regulatory programs in the states of
Pennsylvania and Ohio to illustrate this point.
These reports show that both states have established regulatory
programs designed to ensure that water resources are protected in the
development of oil and gas resources. The two states share a number of
basic regulatory requirements, such as the requirement to obtain a
permit before drilling a well. There are also some key differences
between the regulatory programs in these two neighboring states.
In Pennsylvania, for example, discharges to surface waters
regulated under the federal National Pollutant Discharge Elimination
System (NPDES) program have been a key concern. Due to the regional
geology, Pennsylvania has limited capacity for the use of injection
wells to dispose of oil and gas wastewaters underground. As a result,
oil and gas operations in Pennsylvania have had to find other ways of
managing oil and gas wastewaters. In Ohio, by contrast, almost all oil
and gas wastewaters are disposed of in injection wells permitted under
the UIC (Underground Injection Control) program of the federal Safe
Drinking Water Act. Ohio, therefore, has not experienced the surface
water issues that have received so much attention in Pennsylvania.
The ultimate disposition of oil and gas wastewaters is just one
example of the differences from state to state. The STRONGER reports
document others. The STRONGER reports also document how the individual
states are addressing their particular issues. Pennsylvania, for
instance, has already essentially eliminated the discharges that caused
concern there. The regulatory responses of the states to the water
protection issues raised by shale gas development demonstrate the
unique ability of the states to respond quickly and appropriately to
the special circumstances within their own borders.
Question 2. From your perspective, are there lessons learned from
other regions that can be applied in Eastern shale operations?
Answer. Yes, there are always lessons to be learned and shared.
State regulatory agencies routinely compare notes with their
counterparts in other states on their experiences in responding to new
developments in technology, the economy, and public policy. Much of
this exchange occurs on an informal basis. Oil and gas regulators from
different states regularly communicate with one another to share
information on regulatory approaches and emerging issues. In addition,
several national organizations facilitate this process, including the
Interstate Oil and Gas Compact Commission (IOGCC), the Ground Water
Protection Council (GWPC), and State Review of Oil and Natural Gas
Environmental Regulations, Inc. (STRONGER). STRONGER, in particular,
provides an effective mechanism through which states can work
collaboratively with other stakeholders to benchmark state regulatory
programs and obtain recommendations for improvement.
Question 3. Given the more aggressive regulatory steps recently
taken by NY, are there lessons learned that could be applied at other
drilling sites in other regions?
Answer. My understanding is that New York is still in the process
of completing the updates of the regulatory requirements that will
enable shale gas development to proceed in that state. Through the
exchange mechanisms mentioned in the response to the prior question,
other states are monitoring developments in New York. Undergoing a
STRONGER review would be an excellent way for New York to share lessons
learned and best practices with the various stakeholders in other
states.
Question 4. If the best-case scenario simultaneously allows
successful extraction of natural gas while also ensuring that public
health and the environment are preserved, how can this be achieved and
maintained?
Answer. I believe my written testimony addresses this question
directly. In summary, this is being done right now in states such as
Oklahoma, and other states that regulate oil and gas exploration and
production operations to achieve these very purposes. They have
developed comprehensive oil and gas regulations, which they continually
evaluate and refine to stay current with developments in the industry.
They also work closely with the various stakeholders to address
regional and local concerns. By being open and responsive and by always
working to improve, states have built regulatory programs that ensure
natural gas is produced safely.
Looking at the Pennsylvania Department of Environmental
Protection's (DEP) own numbers for the past two years, every well
inspection discovers roughly two violations. And these don't appear to
be merely technical violations. Violations include:

``Discharge of pollution material to waters of
Commonwealth.''
``Failure to report defective, insufficient, or improperly
cemented casing w/in 24 hrs or submit plan to correct w/in 30
days''
``Failure to report release of substance threatening or
causing pollution''
``Improper casing to protect fresh groundwater''

Question 5. Does two violations for every inspected well strike you
as an acceptable level of industry compliance? What is the comparable
rate in Oklahoma and across the industry?
Answer. My understanding is that the Pennsylvania DEP's total
inspection, violation, and enforcement numbers appear in the year-end
workload reports available at the following link: http://
www.dep.state.pa.us/dep/deputate/minres/oilgas/reports.htm. These
reports indicate that, in the past two years, the DEP conducted a total
of 30,743 inspections and identified 6065 violations. That is not a
ratio of two violations to every inspection.
It appears to me that the ratio of two violations to every
inspection may have been derived from a different set of reports
available at the following link: http://www.dep.state.pa.us/dep/
deputate/minres/oilgas/OGInspectionsViolations/OGInspviol.htm. Please
note that these particular reports cover only those inspections during
which an inspector found violations. Inspections during which no
violations were identified are not included in these reports.
I urge anyone with further questions about the inspection and
enforcement data for Pennsylvania to contact the Pennsylvania DEP. That
agency is the best source of answers to questions such as what
parameters are tracked, how these parameters are defined, and how they
are tallied. Any meaningful analysis of the data will require answers
to these kinds of questions.
Without doing a more extensive analysis of the data on violations,
I am unable to draw conclusions about the level of compliance in
Pennsylvania or to compare it with the level of compliance elsewhere.
I'm not aware of a standard method of assessing this measure of
performance in any federal or state regulatory program.
Your question is difficult for me to answer even for Oklahoma,
where we continually assess our inspection and enforcement activities
to evaluate our performance. Here we conducted 125,129 inspections over
the past two years. Through those inspections we identified 6,977
violations that the inspectors considered serious enough to be
documented on a formal report.
Are we satisfied with that level of compliance? I have to say no.
We work with the operators, most of which are small businesses, to help
them stay in compliance. However, we continue to find violations, and
accidents do happen. We respond rapidly to accidents through a well-
established emergency management structure. And we take swift and
decisive enforcement action when necessary to achieve compliance and to
deter repeat offenses.
A sound inspection and enforcement effort is a core component of
any effective regulatory program, and my division dedicates most of its
resources to this activity. I do not see the need for this kind of
effort diminishing substantially in the future.
Health and safety regulations are complex and continually evolving.
Human enterprises are complicated and constantly changing. When
applying health and safety regulations to human enterprises, an
experienced inspector can always find room for improvement. Our job is
to make sure that improvement occurs, especially when a violation
presents a risk to our people or our water resources.

Responses of Lori Wrotenbery to Questions From Senator Lee

Question 1. You mentioned in your testimony that the states are
well equipped to regulate hydraulic fracturing. I have heard that North
Carolina, where there is a less developed regime surrounding oil & gas
development, has actually reached out to STRONGER, requesting a review
so that they can ensure that they have adequate regulations in place
before any activities begin there. Are there many other examples of
states reaching out to STRONGER in the interest of developing
regulations?
The hydraulic fracturing review in Pennsylvania is another example
of a review that was conducted at the request of a state that was in
the process of developing regulations. Pennsylvania, of course, has a
long history of oil and gas drilling and production, being the location
of the first commercial oil well in the country. But drilling and
production in the Marcellus Shale in Pennsylvania represented an
entirely new type of development and necessitated a comprehensive
review and revision of the existing oil and gas regulations. The
Pennsylvania DEP invited STRONGER to conduct a review under the
STRONGER hydraulic fracturing guidelines in order to assist the state
in addressing the fundamental changes in the nature of oil and gas
operations being conducted there.
STRONGER has had preliminary discussions with representatives of
other states that have expressed interest in the possibility of using
STRONGER's services in developing or updating oil and gas regulations.
And STRONGER continues to offer its services to all oil and gas states.
Even states like Oklahoma, with long-established and well-developed
programs, must continue to evolve to address changing circumstances,
and STRONGER provides a mechanism for obtaining recommendations for
improvement from an independent and balanced group of stakeholders.
Question 2. Your testimony indicates that STRONGER is governed by a
balanced board of stakeholders that includes state regulators,
environmental groups, and oil and gas producers. You mentioned that
STRONGER has now completed hydraulic fracturing reviews in five states.
Given that your board members in some cases bring very different
perspectives to the table, could you comment on how well you are all
able to work together to achieve your common goals?
Answer. Based on my own experience, I can attest that the STRONGER
process works. I have participated in eleven state reviews in eight
different states, and I am currently participating in another hydraulic
fracturing review. In four of those reviews, I was an employee of the
state being reviewed. In the other eight, I have been involved as a
member of the review team. I would characterize each of the reviews as
being an educational and productive experience for all of the
participants.
So how does the STRONGER process work when, as you say, the review
participants bring so many different perspectives to the table? I
believe it works because the various stakeholders come together in a
collaborative endeavor. They get to know one another as people. They
get to know the employees of the state regulatory agencies as people.
They also have a specific task to complete, which is to learn how the
state program works and to make findings and recommendations based on
the STRONGER guidelines (which have themselves been developed by a
stakeholder workgroup). Any recommendation must be tied to a specific
provision of the guidelines or must be identified as beyond the scope
of the guidelines. The review teams focus their attention on how the
state regulatory program measures up against the guidelines rather than
debating the personal opinions or organizational objectives of any
particular review team members.
When the review team members sit down with one another and with the
state officials under these circumstances, the conversations are
usually extremely productive. Please do not surmise that the teams do
not ask pointed questions of the state officials or carry on intense
discussions among themselves. They certainly do. But the process of
working through the key elements of the state regulatory program using
the guidelines as a measuring stick promotes a deeper and more complete
understanding of the way the state programs operate and the challenges
they face. Furthermore, one of the key ground rules of the process is
that any criticism made of a state program must be accompanied by a
specific recommendation for improvement, which requires the team to
articulate what concrete actions the review team suggests the state
take.
I'm sure other participants in the process would share with you
their own ideas why STRONGER and the state review process work so
effectively. They may emphasize different aspects of the process or
point out some elements I have not mentioned. But I feel quite
confident that they too would tell you that it works well.
______

Responses of Tom Beauduy to Questions From Senator Shaheen

Question 1. How does SRBC prioritize competing water demands by
different industries and municipalities especially at times of low
water?

Where does fracking rank in that priority list?
Can you elaborate for the Committee what the process is for
conducting an environmental review for water withdrawal?

Answer. The Commission applies uniform standards for all types of
water withdrawal and use projects and does not prioritize the water use
of different sectors. Applicants seeking Commission approval are
required to demonstrate reasonable foreseeable need for the amounts
requested, and the Commission needs to be satisfied that the request
will not impact water resources or other water users. This is
consistent with the requirement in the Susquehanna River Basin Compact
to provide uniform treatment to all water users.
With regard to drought periods, the Commission relies on its member
jurisdictions to impose restrictions on water use during drought and
all of the member states recognize public water supply as a priority
use in drought declarations. Also, in its own review and approval
process, the Commission restricts the ability of projects to withdraw
water during low flows to protect other downstream uses and aquatic
resources, following standards set forth in its passby flow guidance.
In this regard, fracking is treated like all other industrial water
uses.
The timing and location of proposed withdrawals is critical to the
technical review of applications, as are both potential individual and
cumulative impacts within a watershed. In its environmental review, the
Commission assesses the baseline stream condition at a proposed water
withdrawal location. These data are used in conjunction with water
availability and stream hydrology to determine whether the proposed
withdrawal would adversely impact other water users, fish, wildlife,
other living resources or their habitat, recreation and flows in
streams; or cause water quality degradation that may be injurious to
water uses. Staff recommends appropriate protective measures, as
needed, to avoid or minimize impacts to the subject waterway.
If current data regarding aquatic resources are not available,
Commission staff conducts a comprehensive field investigation at the
proposed withdrawal site that involves a detailed assessment of the
physical, chemical and biological components of the stream. More
information about the Commission's aquatic resource surveys may be
found at http://www.srbc.net/pubinfo/docs/
Aquatic%20Resource%20Surveys%20Info%20Sheet%20(Oct%202011).pdf.
Question 2. What steps are being taken by states in the Marcellus
region to prevent or even prohibit produced water from going to
wastewater treatment facilities that are not equipped to handle this
kind of water?
Answer. Currently, the Commonwealth of Pennsylvania is the only
state in the Susquehanna River basin that has permitted development of
natural gas in shales using unconventional technologies.
Pennsylvania has addressed the issue of disposal of produced water
by upgrading its standards for treatment facilities. These require that
any facility seeking to increase its discharge of treated wastewater or
to any facility seeking to start accepting wastewater must treat the
wastewater to the federal drinking water standard of less than 500
milligrams per liter of total dissolved solids prior to discharge. In
addition, all facilities that accept shale gas extraction wastewater
that has not been fully pre-treated to meet the discharge requirements
must develop and implement a radiation protection plan. Such facilities
must also monitor for radium-226, radium-228, uranium and gross alpha
radiation in their effluent.
Produced fluids from Marcellus shale may only be transported to
facilities that have been specifically approved to accept that waste
for treatment or disposal. No flowback or produced fluids from the
Marcellus are going to any publicly owned treatment facilities in the
Susquehanna River basin. In New York, the draft SGEIS likewise proposes
that flowback and produced fluids will be tracked in a manner similar
to that for medical waste and only be directed to facilities permitted
to accept those wastes.
Recycling has quickly emerging and the preferred (alternative)
method, rather than disposal.
Question 3. Recycling has been widely hailed as a solution to many
of the issues related to the problems associated with water consumption
and waste water disposal. Yet, there have been reports that as
recycling becomes more common, the result is a briny byproduct that is
more concentrated with radioactive materials and other contaminants. It
has been reported that these brine waste streams are being sold to
Pennsylvania counties as road deicers or used as dust suppressants,
from which they could wash into rivers and streams. Are you concerned
that such uses threaten water quality and potentially endanger human
health?
Answer. The Commission supports the reuse by this industry of
flowback and produced fluids in hydrofracing as each gallon used
represents a one-for-one reduction of fresh water that is injected
downhole. These fluids must remain isolated from the fresh waters of
the basin during any transport between drilling pads. Some water is
reused without treatment. Any by-products of the treatment process must
be disposed of following state requirements, and most fluid waste is
currently shipped out of state for disposal through deep well
injection. Crystallized brines created from the thermal distillation of
wastewater is commonly landfilled at approved facilities.
Brines from the Marcellus Shale formation are not being used as
dust suppressants.
As described in the fact sheet produced by the Pennsylvania
Department of Environmental Protection (PADEP), http://
www.elibrary.dep.state.pa.us/dsweb/Get/Document-84809/5500-FS-
DEP1801.pdf, brine produced from oil and gas wells and other sources
such as brine treatment plants and brine wells has been used for
beneficial use as a dust suppressant and road stabilizer on unpaved
secondary roads for many years. This use does not include brine from
shale formations. DEP regulates rates and frequencies of brine
spreading to protect water quality; operators must develop alternative
disposal options for excess brine and all brine produced from shale
formations. Similarly, NYS in its draft SGEIS proposes to restrict the
use of all brines related to Marcellus so that it is not spread on
roads.

Response of Tom Beauduy to Question From Senator Lee

Question 1a. If I understand correctly, it sounds like Pennsylvania
has strengthened its water withdrawal regulations, has strengthened its
drilling standards, now requires a buffer between operations and
streams, has increased the fee required for an application for a
drilling permit, and has increased its staffing from 88 to more than
200. How long did it take to do this and how do you expect the PA
regulatory framework to continue to evolve?
Answer. Please review the following PADEP fact sheet, http://
www.elibrary.dep.state.pa.us/dsweb/Get/Document-84024/0130-FS-
DEP4288.pdf which details a number of ways that Pennsylvania has
increased its oversight of gas drilling in the Marcellus shale over the
last 3 years. In addition to the provisions noted above, PADEP has also
required every application for a Marcellus Shale drilling permit to
include a mandatory water management plan that covers withdrawal and
disposal, the disclosure of chemicals used in fracking, implemented
strong blowout prevention policies, and undertaken greater enforcement
practices. These changes have been implemented over the past three
years.
It is anticipated that PADEP will continue to revise its
regulations and strengthen its program as necessary to keep pace with
the natural gas industry. There are also a number of legislative
proposals being actively considered in the Pennsylvania General
Assembly at the current time that will result in a number of enhanced
provisions Pennsylvania's Oil & Gas Act, if and when approved, and
which will likely result in additional regulatory modifications.
Question 1b. Can you please explain your in-stream water monitoring
system? I am specifically interested in understanding more about water
withdraws for shale gas development compared to other industries/uses.
Answer. The Commission has deployed a remote water quality
monitoring system to track water quality conditions within smaller
rivers and streams throughout the portion of the basin experiencing
natural gas development. The network consists of fifty (50) monitoring
stations in the Pennsylvania and New York that continuously monitor and
record the following five parameters: temperature, pH, conductance,
dissolved oxygen, and turbidity. This advanced technology provides
real-time data to effectively monitor rapid changes in water quality
conditions that will enable water resource agencies, water users, and
the public to make informed decisions regarding management and use of
the resource.
The Commission estimates that at full build out, the natural gas
industry may withdraw and use, as an annual average, 30 million gallons
of water per day. Current usage for the second quarter 2011 is
approximately 10 million gallons of water of per day. To provide
context with other uses, approved consumptive water use for power
generation is approximately 192 millions of gallons of water per day.
Question 1c. What do your regulations say about low-flow days and
how has the industry has responded?
Answer. In its review and approval process, the Commission
restricts the ability of projects to withdraw water during low flows to
protect other downstream uses and aquatic resources, following
standards set forth in its passby flow policy. Most natural gas
withdrawals have been approved with a protective passby flow condition
and the withdrawal is interruptible during predetermined low flow
conditions. The Commission has conducted numerous inspections of
withdrawal locations and strenuously enforced these protective
conditions; the industry as a whole has a good compliance record.
As a result of these protective provisions, the industry has
responded by developing centralized storage capacity for water supply,
and it draws on that storage during low flow conditions.

Response of Tom Beauduy to Question From Senator Coons

Question 1. Currently the Delaware River Basin Commission (DRBC) is
in the process of developing new rules to manage hydraulic fracturing
in the Delaware River Watershed. One issue that I hope the Commission
addresses carefully is the substantial effect on water resources such
as reduced flows in streams and aquifers used to supply the significant
amounts of water necessary in the hydraulic fracturing process. I
understand that the Susquehanna River Basin Commission has an approval
process in place for companies to attain permission to take water from
a tributary or ground source. Are you aware of the efforts underway by
the DRBC? Have the regional river basin commissions communicate on
issues related to energy production and environmental impacts? What
recommendations would you have for the DRBC as it moves forward with a
plan to balance the increased demand for water with the need to
maintain minimum levels in streams and aquifers?
Answer. The Commission is very much aware of activity in the
Delaware and the efforts of the DRBC. We have shared all of our data,
data management strategies, and policies with the DRBC. We have also
shared our experiences and noted those aspects of our program that have
worked well with this industry. Our objective is to give DRBC the
benefit of what we have learned about the natural gas industry, and we
will continue to do that in the future.
As far as recommendations for DRBC, we would suggest that they
utilize the best available science to make informed decisions about
what is necessary to protect water resources and other users in their
basin. Another recommendation might be to invest in information
technology systems/ applications as we have found them to be critical
to effectively and efficiently regulate natural gas development
projects.
______

Responses of David P. Russ to Questions From Senator Shaheen

Question 1. Water availability does not seem to be a barrier to
development of shale gas in the East at the moment but given USGS's
latest projected assessments of economically recoverable gas in this
country, what does this mean for future demands on water availability
and the likely impacts in the East?
Answer. As stated above, water availability does not appear to be a
barrier to shale-gas development in the Northeast, but water
availability is a region by region issue. In the East, water use is
largely a seasonal, and a very localized issue. Although there are
likely hotspots for natural gas drilling, it is not clear exactly where
future drilling and hydrofracturing will take place.
The Susquehanna River Basin Commission (SRBC) has projected the
consumptive use of water by the gas industry within the Susquehanna
Basin will be about 28 million gallons per day at the peak future
demand, which is a little more than half the current consumptive use
for recreation in the basin. Accommodating a New Straw in the Water:
Extracting Natural Gas from the Marcellus Shale in the Susquehanna
River Basin. http://www.srbc.net/programs/docs/
Marcellus%20Legal%20Overview%20Paper%20(Beauduy).pdf.pdf
Though the total water use by the gas industry will not make a
large impact on total water use in the Susquehanna River (or other
major basins in the Northeast), withdrawals will need to be managed to
prevent overdraft from local aquifers or small streams during low-flow
summer months and during periods of drought. For example, though 2011
will surely be one of the wettest years on record in Pennsylvania,
during a drought period in July 2011, water withdrawals were prohibited
at 36 of the permitted surface-water intakes used by the gas industry
because stream flows were less than the pass-by criterion prescribed by
the SRBC for these locations. Potential effects on the quality of water
can also impact the quantity of freshwater that is available for human
and ecological uses. The careful stewardship and judicious use of water
are critical to minimizing the impacts of shale-gas development on the
region's water resources.
Question 2. One of the key differences between shale gas production
in the East vs. the West is water scarcity. We have a lot more water in
the East. However, such surpluses may not always be available. What
does long term production of shale gas mean for water consumption,
particularly in light of climate change and its impact on water
availability?
Answer. Water withdrawn for shale-gas development is generally
considered a `consumptive use', that is, it is not returned to the
water cycle. In reality, some of this water either is returned just
following the hydraulic fracturing process (flowback water), or is
recovered over time during gas production (produced water). Flowback
water is currently being recycled by the gas industry, thereby somewhat
reducing the need for new water for hydraulically fracturing the next
well. Flowback water usually represents about 5 to 12 percent of what
was injected into a Marcellus well, according to data recently
summarized by the SRBC in northeastern Pennsylvania.Produced water from
Marcellus wells in Pennsylvania is generally minimal - several hundreds
of gallons per one million cubic feet of gas produced from the well,
according to the gas industry.
In relation to potential effects of climate change, it is expected
that changes in precipitation patterns due to climate variability would
govern the judicious withdrawal of water for shale gas production. It
would be expected during periods of drought that water needed for
shale-gas development would be curtailed as is currently the case when,
during seasonal dry periods, flows that fail to meet pass-by criteria
result in restrictions on water withdrawals for shale gas applications.
Question 3. What steps should be taken to prevent harm to our water
resources, particularly due to cumulative withdrawals from headlands or
when there are drought-like conditions?
Answer. The amount of water to be withdrawn depends on the number
of wells drilled, when the wells are drilled (seasonally), where they
are drilled, and over what period of time they will be drilled.
Assessing the cumulative impact is extremely difficult due to these and
other unknowns.
Protecting the Nation's water resources will require decision
makers to use scientific research and monitoring data when considering
actions for determining where, when, and to what degree (or amount)
water is withdrawn from any particular water resource. Water managers
will need to ensure appropriate consideration of the various potential
users, including the gas industry, water consumers (drinking water),
agricultural production, waste assimilation, and ecological needs.
Additional protection of the water resource may be needed during
`extreme' water resource conditions, while allowing users the ability
to judiciously utilize water during periods of high water availability.
Understanding the limitations on withdrawals and the flow requirements
of other water use needs depends on a network of long-term streamgages
and groundwater monitoring wells to provide baseline data.
Question 4. Different sources report that fracking fluids are
either a ``benign'' mixture of water, sand, bleach, and other household
agents, or that they contain known neurotoxins and carcinogenic
compounds. What is your understanding?
Answer. Each `service company' (that is, a company that performs
the hydraulic fracturing process) has its own `recipe' for hydraulic
fracturing fluids. These mixtures will change dependent on the
properties of the rock being fractured and the fluids encountered in
the bedrock. Changes to the formulation might occur during the
fracturing process at the site. While most of the chemical compounds
are easily found on company websites or at FracFocus (http://
fracfocus.org/), the proprietary chemicals are not divulged; therefore,
it is difficult to determine the toxicity of all the chemical compounds
used by these different companies.
The U.S. Environmental Protection Agency's national ``Plan to Study
the Potential Impacts of Hydrofracturing on Drinking Water Resources''
will characterize the toxicity and human health effects of fracturing
fluids\1\.
---------------------------------------------------------------------------
\1\ Environmental Protection Agency: Nov. 2011, Plan to Study the
Potential Impacts of Hydrofacturing on Drinking Water Resources, p. 71-
72.
---------------------------------------------------------------------------
Question 5. Recently a USGS scientist, Zachary Bowen, heading one
of the agency's water quality studies stated that ``there's very, very
little information in the scientific literature, there are very few
studies looking at potential effects [on water quality] of these
activities.'' Would you agree that there are many unresolved questions
in this area and that more needs to be done to understand potential
adverse effects of shale gas development on water?
Answer. Yes. In order to understand potential adverse effects of
shale gas development on water resources, scientists would need access
across the region to surface water and groundwater quality data. It
would be necessary to use monitoring wells to test for the potential
presence of natural gas and to determine how the chemistry of waters is
altered deep within the bedrock as they are injected and create the
micro-fractures. It would be important to attain and analyze samples of
the flowback and formation waters and to monitor where and how these
wastes are treated and ultimately disposed of. It would also be
necessary to sample surface waters to evaluate the possible
contamination of these waters from accidental spills and/or by elevated
amounts of sediment generated by pipeline and road construction.
Question 6. Typically when a company that settles with a property
owner who claims that their water has been contaminated by shale gas
production, the property owner is forced to sign a non-disclosure
agreement. Given the need for further study in this area, do you
believe the use of non-disclosure agreements inhibits your and other
state regulatory bodies' ability to collect adequate data? Wouldn't
this lack of information affect our ability to ensure that regulations
designed to protect public health and the environment are sufficient?
Answer. As a Federal science agency, the USGS does not have
regulatory responsibilities. The general lack of scientific data can
and does limit our ability to effectively evaluate the potential
effects of the consequences of shale gas development across the United
States. The impact of different stressors on water quality and quantity
requires targeted monitoring and data collection and analysis. Access
to gas company data would improve our ability to evaluate, understand,
and communicate to the public the potential impact of shale gas
production.
______

Responses of Cynthia C. Dougherty to Questions From Senator Shaheen

Question 1. Is the EPA testing or monitoring ground water and/or
drinking water in the vicinity of drilling operations before and after
fracking operations commence? If so, what chemicalconstituents are
monitored?
Answer. At the direction of Congress, the EPA launched a study last
year to better understand the potential impacts of hydraulic fracturing
on drinking water resources. To establish baseline conditions in the
EPA's study areas, the EPA will conduct prospective case studies which
will include sampling of theareas before hydraulic fracturing is
initiated as well as after hydraulic fracturing occurs. The types
ofchemicals\1\ and other analytes to be considered in the case studies
can be found in Appendix H of thestudy plan' and include groups such as
volatile organic compounds, semi-volatile organic compounds, metals,
radionuclides, and polycyclic aromatic hydrocarbons. The complete list
ofchemicals is included in the Quality Assurance Project Plans\2\
---------------------------------------------------------------------------
\1\ http://epa/gov/hydraulicfracturing
\2\ http://epa.gov.hfstudy/qapps.html
---------------------------------------------------------------------------
Question 1a. Are there known health implications for exposure to
any of these constituents? If yes, what is the minimum ``safe'' level?
Answer. Examining the possible health implications of exposure to
potential contaminants is one of the goals of the study. As part of the
study, the EPA will summarize existing data regarding the toxicity
andpotential human health effects associated with these possible
drinking water contaminants. The EPAmay pursue additional studies to
screen and assess the toxicity associated with chemical contaminants of
concern.
As part of the ``Plan to Study the Potential Impacts of Hydraulic
Fracturing on Water Resources''\3\,the EPA has compiled a list of
chemicals that are publicly known to be used in hydraulic
fracturing.Though this list does not represent the entire set of
chemicals used in hydraulic fracturing activities,a number of the
chemicals included are regulated as contaminants under the Safe
Drinking WaterAct's National Primary Drinking Water Regulations
(NPDWR). NPDWRs protect public healthfrom potentially acute and chronic
effects by limiting the levels of contaminants in drinking water.The
table below contains NPDWR contaminants that appear in the study list.
---------------------------------------------------------------------------
\3\ http://epa.gov/hfstudy/HF__Study__Plan_110211_FINAL_508.pdf

------------------------------------------------------------------------
NPDWR Category Contaminant
------------------------------------------------------------------------
Disinfection Byproducts Bromate
------------------------------------------------------------------------
Inorganic Chemicals Antimony, Arsenic, Barium,
Beryllium,
Cadmium,Chromium, Copper,
Cyanide, Fluoride, Lead,
Mercury,Selenium, and
Thallium
------------------------------------------------------------------------
Organic Chemicals Arcylamide, Atrazine,
Benzene, Benzo(a)pyrene
(PAHs),Chlorobenze, 1,1-
Dichloroethylene,
Epichlorohydrin,Ethylbenze
ne, Styrene,
Tetrachloroethylene,
Toluene, and Xylenes
------------------------------------------------------------------------
Radionuclides Radium 228 and Uranium
------------------------------------------------------------------------

Question 2. There is a long history of oil and gas exploration in
the east. With that, there have been many hundreds (if not thousands)
of wells that were drilled prior to the current shale gasboom. I am
aware that abandoned wells can pose health and environmental risks if
theyare not properly plugged prior to abandonment. Can you comment as
to how much of anissue you feel this could be for shale gas production
in the same area?
Answer. The Interstate Oil and Gas Compact Commission (IOGCC)
estimated, in 2008, that properclosure was needed for approximately
50,000 orphaned oil and gas wells nationwide. At the timeof the study,
New York, Pennsylvania, and West Virginia (the eastern states most
directlyexperiencing the current shale gas boom) had 4,800, 8,700, and
1,260 orphaned wells on theirplugging lists, respectively.\4\
---------------------------------------------------------------------------
\4\ http://iogcc.myshopify.com/products/protecting-our-countrys-
resources-the-states-case-orphaned-well-plugging-initiative-2008.
---------------------------------------------------------------------------
The EPA recognizes that orphaned and improperly abandoned wells can
be a risk to undergroundsources of drinking water (USDWs) and human
health because the wells are a potential conduitfor contamination.
Under the Safe Drinking Water Act (SDWA), the EPA's
UndergroundInjection Control (UIC) program covers underground injection
activities related to oil and gas,including enhanced recovery, fluid
disposal, hydrocarbon storage and diesel fuel hydraulicfracturing. The
majority of oil and gas production activities fall outside of UIC
requirements.
A useful technical resource addressing well construction, plugging,
and abandonment ofinjection wells covered by the UIC program authorized
by SDWA is technical guidanceavailable on the EPA's website.\5\ This
guidance, which pertains to the UIC program morebroadly (not specific
to oil and gas production activities), may provide useful technical
guidancefor operators and states, regardless of the regulatory context
in which they operate.
---------------------------------------------------------------------------
\5\ These documents can be found at http://water.epa.gov/type/
groundwater/uic/guidance.cfm.
---------------------------------------------------------------------------
In addition, states may have their own requirements for addressing
abandoned wells under theiroil and gas regulations. For those wells
associated with the UIC program, well owners andoperators must perform
corrective action (e.g., proper plugging) on improperly abandoned and/
ororphaned wells within the prescribed ``Area of Review'' before
receiving an injection permit.
Question 3. A number of potential mechanisms-such as improper well
construction and casing orabandoned wells nearby newly producing shale
gas wells-have been identified by which fugitive methane might escape
into drinking water wells. Could you explain these potential
mechanisms? Have these mechanisms been comprehensively studied in order
to quantify the risks of well water contamination? Is more study
warranted?
Answer. Common pathways for methane migration may include movement
through faulty well casing ormovement through the aimulus located
between the casing and well bore. In addition, wellsdrilled into
adjacent, shallower formations that are not plugged, or are improperly
plugged, couldpotentially become pathways for methane migration.
The EPA has experience and data on methane migration from
underground injection wellsthrough its Underground Injection Control
(UIC) program. In establishing the UIC Program, theagency recognized
that potential endangerment of underground sources of drinking
water(USDWs) could occur via these pathways and designed federal
requirements to mitigate these risks. In the current Hydraulic
Fracturing Research Study, the agency is studying the potential risks
to water resources that will include risks from faulty well
construction and improper plugging and abandonment.
Question 4. What are the potential harms arising from fugitive
methane emissions? Has anyone studied the health effects of consuming
water contaminated by methane?
Answer. According to the National Institute for Occupational Safety
and Health (NIOSH), methaneexposure poses fire, explosion, and
inhalation hazards.\6\ Methane is extremely flammable andforms an
explosive mixture with air at concentrations of 5%-15% by volume. Other
factors suchas water temperature, ventilation of the well, air
movement, and the percent composition of thegas determine the exact
concentration that is capable of producing an explosive hazard. There
isno federal standard for methane in drinking water and the risk of
ingesting methane is unknown.
---------------------------------------------------------------------------
\6\ See http://www.cdc.gov/niosh/ipcsneng/nengO291.html
---------------------------------------------------------------------------
Question 5. A Congressional investigation recently found that
between 2005 and 2009, hydraulicfracturing companies had injected 32
million gallons of diesel and diesel laced fluids inhydraulic
fracturing operations in 19 different states. The investigation showed
thatcompanies had not obtained the required permits for injecting
diesel under the SafeDrinking Water Act. EPA has the authority to
regulate both diesel injections in hydraulicfracturing and the disposal
of wastewater. Are you investigating these incidents? What willEPA do
if it finds that these companies did violate the law?
Answer. The EPA is aware that the investigation found that a number
of oil and gas service companiescollectively injected 32.7 million
gallons of diesel fuels and fluids containing diesel fuels intowells
between 2005 and 2009. The EPA will evaluate on a case-by-case basis
potential violationsfrom the injection of diesel fuels into wells and
the disposal of wastewater that it discovers,including whether to
initiate follow-up enforcement action.
Question 6. Recently a USGS scientist, Zachary Bowen, heading one
of the agency's water qualitystudies stated that ``there's very, very
little information in the scientific literature, there arevery few
studies looking at potential effects [on water qualityj of these
activities.'' Wouldyou agree that there are many unresolved questions
in this area and that more needs to bedone to understand potential
adverse effects of shale gas development on water?
Answer. The EPA agrees there are unresolved questions about the
potential impacts of hydraulicfracturing on water resources. As
described in the final study plan, the agency has identified anumber of
key primary and secondary scientific questions associated with the five
stages of thehydraulic fracturing water cycle: water acquisition,
chemical mixing, well injection, flowbackand produced water, and
wastewater treatment and waste disposal. Answering questionsassociated
with each of these stages will enable the agency to assess the
potential impacts ofhydraulic fracturing on drinking water resources,
and the specific causes of any identifiedimpacts.
Question 7. Typically when a company that settles with a property
owner who claims that their water has been contaminated by shale gas
production, the property owner is forced to sign a
nondisclosureagreement. Given the need for further study in this area,
do you believe the use of non-disclosure agreements inhibits your and
other state regulatory bodies' ability to collect adequate data?
Wouldn't this lack of information affect our ability to ensure that
regulations designed to protect public health and the environment are
sufficient?
Answer. Non-disclosure agreements could hinder the EPA's access to
data on contamination due to shalegas production. For example,
landowners with non-disclosure agreements may feel that they are unable
to cooperate voluntarily with the EPA's requests for information or
access to well sites for sampling.

Responses of Cynthia Dougherty to Questions From Senator Lee

Question 1. Ms. Dougherty, in 2004, when EPA completed its study of
hydraulic fracturing of coal bed methane reservoirs, your agency
reported that diesel fuel was sometimes used in fluids for hydraulic
fracturing within underground sources of drinking water. Congress
responded by giving EPA the authority to regulate hydraulic fracturing
under the Safe Water Drinking Act if diesel fuel is used. Five years
after it was granted this authority, EPA began to act-first issuing a
notice that it would consider all wells that fracture with fluids
containing diesel fuel as Class II wells under the Underground
Injection Control program, and second by initiating the development of
guidance for implementing its Safe Water Drinking Act authority.
Clearly, the definition of diesel fuel is critical to EPA's regulatory
action, yet EPA has not yet provided this definition and has
consequently created an ongoing environment of uncertainty. Do you
agree that the definition for diesel fuel should be clear, specific and
narrow, and should use the already established Chemical Abstract
Service numbers?
Question 1a. Can you please tell us when EPA plans to provide this
clarification and whetherEPA will use Chemical Abstract Service
numbers?
Answer. The EPA is in the process of developing draft guidance for
permitting hydraulic fracturing whendiesel fuels are used in fluids or
propping agents. The EPA anticipates that the guidance willinclude
recommendations for a permit writer to consider when determining if
diesel fuels arebeing used. We have heard a wide range of stakeholder
views about how to define diesel fuels,including to only use the few
Chemical Abstract Service Registry Numbers for diesel fuels 1 and2, and
to be as broad as including substances with any of the physical or
chemical properties ofpetroleum-based diesel. Once the draft guidance
is ready, it will go out for public comment(planned for 2012).
Question 2. The press release you issued on October 20th states
that you are proposing a schedule to develop new standards for
wastewater discharges produced by shale gas extraction. Is theNPDES
program insufficient in some way?
Question 2a. Why is EPA doing this and not simply working with
states to ensure that stateregulations are adequate?
Answer. The National Pollutant Discharge Elimination System (NPDES)
program, as prescribed by theClean Water Act, is sufficient; however,
as industries evolve, changes to requirements need to beconsidered to
keep the program consistent with new technologies and changes in
industry practices. Currently, except in limited circumstances,
wastewater associated with shale gas extraction is prohibited from
being directly discharged to waterways and other waters of the U.S.
While most of the wastewater from shale gas extraction is reused or re-
injected, a significant amount still requires disposal. Shale gas
extraction wastewaters may be indirectly discharged into waters of the
U.S. through sewer systems connected to publicly owned treatment works
(POTW) that discharge directly to waters of the U.S. or by being
introduced by truck or rail into a POTW that discharges directly. Shale
gas extraction wastewater may also be disposed of at centralized waste
treatment facilities and then discharged directly or discharged to a
sewer system connected to a POTW that discharges directly. As a result,
some shale gas wastewater istransported to treatment plants, some of
which may not be properly equipped to treat this type ofwastewater
effectively prior to discharge to surface waters. In a November 22,
2011 letter to theEPA commenting on the 2010 Effluent Guidelines Plan,
the American Petroleum Institute (API)said:

API supports the development of pretreatment standards for
existing and new sources inthe SGE subcategory. SGE wastewater
generators should have the alternative ofdischarging to
publicly owned treatment words (POTW) provided that the
producedwaters do not interfere with treatment operations and
the SGE pollutants do not passthrough to the POTW to cause
adverse receiving water quality impacts.

The EPA has been, and will continue to, provide support to states
and permitting authorities.Under the Clean Water Act statutory and
regulatory framework, POTWs must establishrequirements for any
introduction of wastewater to the POTW or its collection system if it
eitherwould cause ``pass through'' or ``interference'' (e.g., cause the
POTW to violate its permits limits,or interfere with the operation of
the POTW or the beneficial use of its sewage sludge). POTWsare subject
to the secondary treatment effluent limitations at 40 CFR part 133,
which do notaddress the parameters of concern in shale gas extraction
wastewater (e.g., TDS, chloride,radionuclides, etc), and site-specific
local limits as necessary to protect water quality. Therefore,the EPA
is developing a categorical pretreatment standard and has provided
other guidance toassist NPDES permitting authorities to develop
appropriate permit requirements for facilities thataccept this
wastewater.
To ensure that the EPA proposes environmentally and cost-effective
rules that satisfy allapplicable Clean Water Act and other regulatory
process requirements, the EPA will gather data,consult with
stakeholders, including ongoing consultation with industry, and solicit
publiccomment on a proposed rule for coal bed methane in 2013 and a
proposed rule for shale gas in2014.
Question 2b. Why is EPA proposing these standards ahead of the
completion of your study?
Answer. The EPA's study and this rulemaking are complementary. Any
data collected pursuant to thisnew rulemaking will be shared with the s
Office of Research and Development that is conducting the
congressionally-directed study and any relevant information that is
gathered as part of the study will be shared with the EPA' s Office of
Water that is working on the rulemaking.
Question 3. EPA announced in June that it had selected seven case
studies for its Draft HydraulicFracturing Study Plan that the Agency
believes will provide the most useful informationabout the potential
impacts of hydraulic fracturing on drinking water resources. We have
been hearing, through industry, state regulator sources, and the media
that EPA has already begun field work on one of the prospective sites.
What is the schedule for releasing the Final Study Plan?
Question 3a. Would it be safe to assume that EPA's Draft Study Plan
is the Final Plan, since EPAis already in the field taking samples?
Answer. The EPA's draft study plan is not identical to the final
study plan, which was released onNovember 3, 2011. However, the core
research questions and general research approach are unchanged. The
final study plan includes more details about the research activities
being undertaken to improve the public's understanding of how the
agency is carrying out the study.
To ensure that the study is complete and results are available to
the public in a timely manner, the EPA initiated some activities this
summer to provide a foundation for the full study.Importantly, all of
these initial activities were explicitly described in the draft study
plan andsupported by the agency's Science Advisory Board during its
peer review. As laid out in both thedraft study plan and the final
study plan, we have conducted an initial literature review,requested
and received information from industry on chemicals and practices used
in hydraulicfracturing, discussed initial plans for case studies with
landowners and state, local and industryrepresentatives, and conducted
baseline sampling for retrospective case studies using scientifically
sound approaches that have been shared with collaborators. This work
will enable us to provide timely and scientifically sound results in
our 2012 and 2014 reports.
Question 4. What is EPA's overall schedule for both the
retrospective and prospective case studyanalysis and will you make that
schedule available to the public by posting it on the EPA website?
Answer. The overall schedule for the five retrospective and two
prospective case studies is shown below:

Retrospective Case Studies

Killdeer, ND: 3 rounds of sampling and
analysis through mid-2012,
with additional sampling
as necessary

Southwest PA: 2 rounds of sampling and
analysis through mid-2012,
with additional sampling
as necessary

Wise Co., TX: 2 rounds of sampling and
analysis through mid-2012,
with additional sampling
as necessary

Raton Basin, CO: 1 round of sampling and
analysis through mid-2012,
followed by 2 additional
rounds of sampling in late
2012, with additional
sampling as necessary

Northeast PA: 2 rounds of sampling and
analysis through mid-2012,
with additional sampling
as necessary

Prospective Case Studies

DeSoto Parish, LA and Washington County, 3 rounds of sampling and
PA: analysis, with additional
sampling as necessary,
through mid-2014

This general schedule assumes continued cooperation from relevant
parties. The 2012 report willinclude some sampling results and data
analysis for each of the five retrospective case studies,based on
information collected and analyzed by mid-2012. The 2014 report will
include the finalresults for all seven case studies.
Specific sampling dates are shared with local property owners,
state authorities and wellowner/operators who are conducting studies in
parallel with the EPA. The sampling dates willnot be posted on the
website, as specific dates for site visits are subject to change. We
will,however, keep the public updated on our progress on all seven of
the case studies throughout theprocess.
Question 5. Do you have an estimate of how much EPA's study will
cost?
Answer. In fiscal years 2010 through 2012, a total of $12.3 million
has been either already enacted byCongress (FY2O1O, $1.9M obligated;
FY2O11, $4.3M enacted; FY2012, $6.1M). Further expenditures will be
required in 2013 and 2014 to complete the study, but a budget has not
yet been proposed.
Question 6. What additional opportunities is EPA undertaking to
involve stakeholders in this ``public process?''
Answer. As the study progresses, the EPA will continue to engage
multiple stakeholder groups, includingthe public; industry; non-
governmental organizations; federal, state, and tribal agencies;
andinterstate organizations. Examples of planned activities include
quarterly progress updates thatmay take place in a variety of formats,
including web postings and briefings via webinars.Additionally, the
results of the study will be synthesized in a 2012 report and a 2014
report thatwill both undergo a thorough peer review process. The
reviews will be conducted by the ScienceAdvisory Board, and
opportunities for the public to submit comments to the peer review
panelwill be provided.
Question 7. For the sake of transparency, will EPA provide a list
of the operators you have contacted to participate in both the
retrospective and prospective studies and make that list available
tothe public?
Answer. The EPA posted the list of operators with interests in the
retrospective and prospective casestudies on our website.\7\ For the
retrospective case studies, these companies include: Denbury Resources,
Inc.; XR-5, LLC; White Stone Energy, LLC; Aruba Petroleum, mc; Primexx
Energy Partners, Ltd; Chesapeake Energy Corporation; Range Resources
Corporation; Atlas Energy, L.P.; Pioneer Natural Resources Company;
Petroglyph Energy, mc; Cabot Oil and Gas Corporation; and Chief Oil and
Gas, LLC.
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\7\ http://water.epa.gov/type/groundwater!uic/class2/
hydraulicfracturing/case--studies.cfm
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Answer. Our partners in conducting the prospective case studies
are: Range Resources Corporation inWashington County, PA and Chesapeake
Energy Corporation in DeSoto Parish, LA.

Response of Cynthia C. Doughtery to Questions From Senator Coons

I am encouraged by the ongoing EPA study that is intended to more
comprehensively examine the environmental and other challenges posed by
hydraulic fracturing. Your testimony indicates that two reports will be
completed. One will be released in 2012 summarizing existing data and
other laboratory studies. Another will be finalized in 2014 that will
provide additional scientific results on these topics and report on
prospective case studies and toxicological analyses. Though the full
results of the study will not be released until 2014, I am hopeful that
this study will help the federal government, states,communities,
industry and environmental groups better manage natural gas production
inthe Marcellus Shale and across the country.
Question 1. The Delaware River Basin Commission (DRBC) is set to
finalize its new rules for managing hydraulic fracturing in the next
month, and every state with gas production and a varietyof river basin
commissions have conducted studies and produced rules for how to manage
hydraulic fracturing. Are you aware of the work being done by the DRBC?
In the course of this study, how is the EPA planning to incorporate the
work that has already been done by river basin commissions and other
similar entities as it seeks to better understand the effects of
hydraulic fracturing?
Answer. The EPA is aware of DRBC's efforts to finalize its natural
gas regulations as well as efforts by other state and interstate
agencies to collect water quality data in areas where hydraulic
fracturing is occurring. The DRBC gas drilling regulations will address
protective measures to be undertaken during natural gas development. We
do not expect that it will result in short-term data being collected
that will prove useful in the Hydraulic Fracturing Research Study.
However, as a result of meetings with several key state and federal
agencies, the EPA has identified work underway by others that the EPA
can use to inform its study. Information such as the collection of
water quality or water use data, may be used to inform the EPA!s study.
The EPA continues to discuss opportunities to collaborate in
information gathering and research with other agencies.