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



                                                        S. Hrg. 112-247
 
                      SHALE GAS AND WATER IMPACTS

=======================================================================

                                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

                                   TO

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

                               __________

                            OCTOBER 20, 2011


                       Printed for the use of the
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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
                                 ------                                

                    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

                              ----------                              

                               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

                              ----------                              


                       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
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \34\ SRBC, Water Resource Challenges from Energy Production, June, 
2008.
    \35\ SRBC Consumptive Use Mitigation Plan at pg A-6.
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \36\ Id. at pg. A-14. (Original published amount of 134 mgd updated 
to 230 mgd by SRBC, 2010).
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \37\ Power production facilities, on the other hand, are generally 
located along the mainstem river or major tributaries.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \38\ SRBC Consumptive Use Mitigation Plan, at pg. 23.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \1\ http://www.sandia.gov/energy-water/docs/121-RpToCongress-
EWwEIAcomments-FINAL.pdf
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \1\ http://www.prweb.com/releases/Marcellus/Production/
prweb8855519.htm
---------------------------------------------------------------------------
    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.
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    \3\ Johnson, Nels (2010). Pennsylvania Energy Impacts Assessment, 
Report 1: Marcellus Shale Natural Gas & Wind, p.9. The Nature 
Conservancy, Pennsylvania Chapter.
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            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.
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    \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.
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    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.
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            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
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    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.

                                    

      
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