Post on 23-Sep-2020
THE FUTURE OF REGULATION IN HYDRAULIC FRACTURING
Presented by:
JOHN MCFARLAND
Graves, Dougherty, Hearon & Moody
401 Congress, Suite 2200
Austin, TX 78701
(512) 480-5618
(512) 480-5818 (fax)
PETER E. HOSEY
Jackson Walker L.L.P.
112 E. Pecan Street, Suite 2400
San Antonio, TX 78205
(210) 228-2423
(210) 242-4610 (fax)
Presented and Written by:
BRENDA L. CLAYTON
Kelly Hart & Hallman LLP
301 Congress Ave., Ste. 2000
Austin, TX 78701
(512) 495-6409
(512) 495-6401 (fax)
State Bar of Texas
34th
ANNUAL
ADVANCED REAL ESTATE LAW July 12-14, 2012
San Antonio
CHAPTER 23
ACKNOWLEDGEMENTS
This paper is largely an update of a paper I gave in the fall, and that paper, in turn, drew on several
other papers. I am indebted to the following for their work on papers from which I initially drew: Steve
Ravel, Holly Vandrovec, Chad Smith and Alicia Ringuet. I am also indebted to the people who kindly gave
me information and advice on this and former versions of this paper: David Cooney, Leslie Savage and
Michael Sims of the Railroad Commission, Ray Oujesky of Chesapeake Operating, Inc., Tony Thornton of
Devon Energy Corp., and Ben Sebree of TXOGA. I am eternally indebted to my assistant, Stacey Supak-
Diaz, for her work on this and other papers.
John McFarland
Represents land and mineral owners in all aspects of oil, gas, and mineral law.
Mr. McFarland is the author of the Oil and Gas Lawyer Blog, www.oilandgaslayerblog.com
Admitted to bar 1975. Board Certified, Oil, Gas and Mineral Law, Texas Board of Legal
Specialization. Briefing Attorney to the Honorable Ruel C. Walker and to the Honorable Ross E. Doughty,
Supreme Court of Texas, 1975-1976.
Education: Yale University (B.A., cum laude, 1972); University of Texas (J.D., 1975). Order of
Telephone: 512-495-6403 Coif.
Peter E. Hosey
Peter E. Hosey is a Partner in the San Antonio, Texas office of Jackson Walker L.L.P. He received
a Bachelor of Arts degree from The University of Texas at El Paso in 1976, and is a 1979 graduate of St.
Mary‘s University School of Law. He practices primarily in the areas of oil, gas and mineral law, title and
transactional matters, real estate law, business law, and international business law. Since 1998, he has
served on the Joint Editorial Board for the development of the Texas Title Examinations Standards
established by the Real Property, Probate and Trust Law and Oil, Gas and Energy Resources Law Sections
of the State Bar of Texas, which are published in the Texas Property Code. He is a member of the San
Antonio Bar Association (has been several times as President and Treasurer of the Natural Resources
Committee of the San Antonio Bar Association), a member of the American Bar Association and the State
Bar of Texas. He is also a member of the College of the State Bar of Texas. He is a frequent lecturer and
writer on oil, gas and land title issues. He recently spoke at the 50th
Annual Rocky Mountain Mineral Law
Foundation Institute, the State Bar of Texas, 23rd
Annual Advanced Oil, Gas and Energy Resources Law
Course, the 2007 University of Houston Advanced Oil and Gas Short Course, and the 33rd
and 35th
Annual
Ernest E. Smith Oil, Gas & Mineral Law Institutes. He also wrote, ―Title To Uranium And Other Minerals
(Still Crazy After All These Years),‖ which was published in the Oil, Gas and Energy Resources Law
Section Report, December 2008. He is a member of the Council of the Oil, Gas and Energy Resources
Law Section of the State Bar of Texas. He has also been named a Texas ―Super Lawyer‖ by Thomson
Rueters. He is currently an Adjunct Professor of Law at St. Mary‘s University School of Law, teaching
Texas Land Titles. Mr. Hosey was named a San Antonio ―Best Lawyer‖ by Scene in S.A. (2007-2009) and
a ―Super Lawyer‖ (2009-2011) by Thomson Reuters. In 2011, he was named an ―Outstanding Lawyer‖ by
the San Antonio Business Journal.
Brenda L. Clayton
A partner in Kelly Hart & Hallman‘s Austin office, Ms. Clayton‘s practice centers on environmental
and administrative law, oil, gas, and mineral law, and appellate law.
Education
J.D. with honors, University of Texas Law School, May 1992
B.A. in Economics with honors, University of Texas at Austin, 1980
Practice
Environmental and administrative law. Ms. Clayton‘s environmental and administrative law practice
includes regulatory matters involving waste and water, such as those arising under the Resource
Conservation and Recovery Act (―RCRA‖), the Clean Water Act (―CWA‖), the Safe Drinking Water Act,
the Texas Natural Resources Code, Texas Water Code, the Texas Solid Waste Disposal Act, and the Texas
Asbestos Health Protection Act. She also defends or prosecutes private environmental litigation such as
suits under the Comprehensive Environmental Response, Compensation and Liability Act and the Texas
Solid Waste Disposal Act, citizen suits under RCRA and the CWA, and common law tort actions.
Ms. Clayton regularly represents private third parties before the Attorney General in Public
Information Act proceedings in which the third party seeks to protect trade secret or other confidential
information from disclosure by a governmental entity.
Oil, gas, and mineral law. Ms. Clayton‘s oil, gas and mineral law practice includes regulatory matters
before the Railroad Commission of Texas (both traditional and environmental matters) and litigation
arising from the exploration and production of oil, gas and other minerals.
Appellate law. Ms. Clayton‘s appellate practice includes both suits for judicial review of agency
decisions and appeals from trial court decisions.
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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TABLE OF CONTENTS
I. HYDRAULIC FRACTURING IN GENERAL. ....................................................................................... 1
II. PRESERVING WATER QUALITY. ....................................................................................................... 1
A. Federal water quality regulation. ....................................................................................................... 1
1. The Safe Drinking Water Act and the Underground Injection Control Program (―SDWA‖). ... 1
a. Structure and history. ........................................................................................................... 1
b. Enforcing the SDWA. ......................................................................................................... 2
i. Before and after delegation of enforcement authority to a state. ................................. 2
ii. Emergency Orders – and the Range Resources matter. ............................................... 3
iii. Supreme Court hands down decision in Sackett. ......................................................... 7
c. EPA‘s pending permitting guidance on the use of diesel fuel in hydraulicfracturing
fluid. ..................................................................................................................................... 7
d. EPA‘s pending hydraulic fracturing study. ......................................................................... 9
e. Department of Energy‘s (―DOE‘s‖) Advisory Reports. .................................................... 10
f. Other studies. ..................................................................................................................... 11
2. The Clean Water Act. ............................................................................................................... 11
a. Structure and history. ......................................................................................................... 11
b. Pending natural gas wastewater effluent limitations under § 304(m) ............................... 12
c. Enforcing the CWA. .......................................................................................................... 12
3. RCRA. ...................................................................................................................................... 13
4. CERCLA................................................................................................................................... 13
5. National Environmental Policy Act (―NEPA‖). ....................................................................... 15
6. The BLM: Regulation of hydraulic fracturing on federal lands. .............................................. 15
7. Federal Partnership for Unconventional Natural Gas and Oil Research .................................. 15
B. State water quality regulation. ......................................................................................................... 15
1. Railroad Commission of Texas. ............................................................................................... 15
2. The Texas Commission on Environmental Quality. ................................................................. 17
3. The University of Texas‘s Energy Institute Report. ................................................................. 17
C. Local water quality regulation. ........................................................................................................ 18
1. Municipalities. .......................................................................................................................... 18
a. City of Fort Worth. ............................................................................................................ 18
b. City of Hurst. ..................................................................................................................... 19
2. Other local governments, including groundwater conservation districts. ................................ 19
III. PROTECTING PUBLIC HEALTH AND THE ENVIRONMENT: TSCA .......................................... 20
IV. PRESERVING WATER RESOURCES. ................................................................................................ 20
A. Water supply. ................................................................................................................................... 20
B. Water usage. ..................................................................................................................................... 21
1. Regulation of surface water rights. ........................................................................................... 21
2. Regulation of groundwater rights. ............................................................................................ 22
a. Ownership of groundwater rights. ..................................................................................... 22
b. Regulation of groundwater usage: the groundwater conservation district. ....................... 22
C. Water recycling. ............................................................................................................................... 24
1. In general. ................................................................................................................................. 24
2. Regulation of stationary and mobile recycling units. ............................................................... 26
3. Use of reused or reclaimed water for fracturing. ...................................................................... 26
4. Future developments. ................................................................................................................ 26
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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V. PRESERVING PROPERTY – INDUCED SEISMICITY. .................................................................... 26
A. Quakes in Youngstown, Ohio. ......................................................................................................... 27
B. USGS study. ..................................................................................................................................... 27
C. National Academy of Sciences study of induced seismicity. .......................................................... 27
VI. PRESERVING AIR QUALITY. ............................................................................................................ 28
A. Federal air quality regulation. .......................................................................................................... 29
1. Current regulations. .................................................................................................................. 29
2. Proposed and final regulations. ................................................................................................. 29
a. Overview of proposal. ....................................................................................................... 29
b. New source performance standard for volatile organic compounds (―VOCs‖). ............... 30
c. New Source Performance Standards for Sulfur Dioxide. .................................................. 31
d. Air Toxic Standards. .......................................................................................................... 31
i. Air toxics – oil and natural gas production. ............................................................... 32
ii. Air toxics – natural gas transmission and storage. ..................................................... 32
3. The DOE‘s criticisms of EPA‘s rules. ...................................................................................... 32
B. State air quality regulation. .............................................................................................................. 32
1. In general. ................................................................................................................................. 32
2. The new PBR. ........................................................................................................................... 33
a. Applicability. ..................................................................................................................... 34
b. Types of authorizations. .................................................................................................... 34
c. Additional authorizations that may be required. ............................................................... 35
d. Elements of new permit by rule (―PBR‖). ......................................................................... 35
e. Level 0: existing authorized OGS. .................................................................................... 37
f. Level 1 registration. ........................................................................................................... 37
g. Level 2 registration. ........................................................................................................... 37
3. The new non-rule standard permit. .......................................................................................... 38
a. Application. ....................................................................................................................... 38
b. Registration. ....................................................................................................................... 39
c. Best Management Practices and Best Available Control Technology. ............................. 39
4. TCEQ enforcement of its air program. ..................................................................................... 39
C. Local air quality regulation. ............................................................................................................. 41
1. The City of Fort Worth. ............................................................................................................ 41
2. The City of Hurst. ..................................................................................................................... 42
D. Various studies of public health impacts. ........................................................................................ 42
VII. EFFECTIVE DATES AND DEADLINES. ............................................................................................ 44
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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THE FUTURE OF REGULATION IN HYDRAULIC FRACTURING
I. HYDRAULIC FRACTURING IN GENERAL.1
Hydraulic fracturing has been used on more than one million wells since the 1940s, with little
controversy.2 The current controversy regarding ―fracking,‖ as it is colloquially called, is a result both of
the intensity and location of its current use. Fracking in downtown Fort Worth attracts much more
attention than fracking in the Panhandle. This paper addresses some of the recent controversies and some
pending and proposed changes that will affect hydraulic fracturing.
II. PRESERVING WATER QUALITY.
A complex overlay of federal and state laws preserve our water quality. The federal government‘s
power to regulate is limited by the Commerce Clause.3 The federal government regulates the safety of
drinking water, at least in part, on the theory that public water systems sell water across state boundaries.4
The federal government also regulates surface waters that are ―waters of the United States,‖ a phrase with
an abundance of ambiguity, but that ultimately requires some connection to interstate waters or interstate
commerce.5 The federal water programs described below, like most federal environmental programs,
ultimately seek to authorize states to enforce the federal program, should the state desire to do so.
States generally also regulate surface water, as well as groundwater, within their boundaries. And,
in Texas, a grid of groundwater conservation districts, river authorities, and local governments regulate
water quality as well.
A. Federal water quality regulation.
The primary program regulating water quality effects of hydraulic fracturing is the Safe Drinking
Water Act, which regulates the underground injection of fluids. The Clean Water Act would apply only to
activities that affect ―waters of the United States.‖ Other substantive federal regulatory programs are
unlikely to substantively affect hydraulic fracturing due to exclusions for oil and gas exploration activity.
However, NEPA imposes procedural requirements that a federal agency must meet before taking a major
federal action, which could affect hydraulic fracturing on federal land.
1. The Safe Drinking Water Act and the Underground Injection Control Program (“SDWA”).
a. Structure and history.
The Safe Drinking Water Act (―SDWA‖), administered by EPA, is designed to ensure the safety of
public drinking water. It does so through two different programs. First, the SDWA regulates public water
systems, primarily through EPA-set regulations concerning maximum contaminant levels in drinking water,
as well as monitoring and reporting requirements.6 Second, the SWDA protects underground sources of
drinking water by prohibiting the underground injection of fluids without a permit.7 This program is
referred to as the Underground Injection Control (―UIC‖) program.
The UIC program sets minimum standards states must meet for the underground injection of fluids.
The program includes inspection, monitoring, recordkeeping, and reporting requirements.8 Once EPA
1 This paper is an update of an earlier paper, Brenda L. Clayton, Regulation of Fracking, State Bar of Texas 29
th Annual
Advanced Oil, Gas and Energy Resources Law Course, October 6-7, 2011.
2 Hydraulic Fracturing: Unlocking America‘s Natural Gas Resources, July 19, 2010, American Petroleum Institute, available at
www.api.org.
3 Rapanos v. Unites States, 547 U.S. 715 (2006).
4 Nebraska, et al. v. EPA, 331 F.3d 995, 998 (D.C. Cir. 2003).
5 Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers, 531 U.S. 159, 173, 121 S.Ct. 675, 683 (2001).
6 Id; See 42 U.S.C. § 300g to 300g-9 (West 2011).
7 Id. at § 300h(b)(1)(a).
8 Id. at § 300h(b)(1)(c). The EPA‘s regulations regarding state UIC programs can be found at 40 C.F.R. pt. 145 (2010).
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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approves a state‘s UIC program, the state has the primary enforcement responsibility for granting UIC
permits and ensuring that underground injection of fluids does not endanger underground sources of
drinking water (―USDW‖).9
EPA‘s interpretation of ―underground injection‖ did not originally include hydraulic fracturing
operations. That changed in 1997, when the Eleventh Circuit decided Legal Environmental Assistance
Foundation, Inc. (“LEAF”) v. U.S. EPA.10
In LEAF, the plaintiff challenged EPA‘s approval of Alabama‘s
UIC program, arguing that the program was deficient for not regulating hydraulic fracturing associated with
methane gas production.11
EPA argued that ―underground injection‖ did not include wells using hydraulic
fracturing, because ―the principal purpose of these wells is not the underground emplacement of fluids;
their principal function is methane gas production.‖12
The Eleventh Circuit rejected the EPA‘s
interpretation, arguing that the plain meaning of ―underground injection,‖ as well as the legislative history
regarding the passage of the SDWA, ―required the regulation of all underground injection activities,‖
including hydraulic fracturing.13
After the LEAF decision, EPA began studying the process of hydraulic fracturing and its potential
effects on drinking water sources. In 2003, the EPA entered into a voluntary agreement with BJ Services
Co., Halliburton Energy Services, Inc. and Schlumberger Technology Corp. ―to eliminate diesel fuel in
hydraulic fracturing fluids injected into coalbed methane production wells in underground sources of
drinking water.‖14
In 2004, EPA issued its study on the potential effects on USDWs caused by hydraulic
fracturing operations in coalbed methane reservoirs.15
In the 2004 study, the EPA determined ―that the
injection of hydraulic fracturing fluids into [coal bed methane] wells poses little or no threat to USDWs.‖16
Despite this finding, the EPA identified certain chemicals used in hydraulic fracturing, including diesel
fuel, as ―constituents of potential concern.‖17
Congress then passed the Energy Policy Act of 2005. Among other things, the Energy Policy Act
amended the SDWA‘s definition of ―underground injection‖ to exclude ―the underground injection of
fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations.‖18
As a
result, states did not have to require companies to seek permits before engaging in hydraulic fracturing
operations as part of their UIC program, unless diesel fuels were used.
As discussed below, in Texas, the overwhelming majority of all wastewater from oil and gas
operations – including produced water and flowback water – is disposed of by reinjection into a Class 2
UIC well.
b. Enforcing the SDWA.
i. Before and after delegation of enforcement authority to a state.
Where the state does not have primary responsibility for enforcing the UIC program, EPA is
authorized to enforce the program by bringing an administrative action in which it can seek penalties of
9 Id. at § 300h(b)(1)(b).
10 118 F.3d 1467 (11th Cir. 1997).
11 Id. at 1471.
12 Id. (emphasis added).
13 Id. at 1475.
14 Memorandum of Agreement Between the U.S. Envt‘l Prot. Agency and BJ Services Co., Halliburton Energy Services, Inc.,
and Schlumberger Tech. Corp. 2 (Dec. 12, 2003), available at http://www.epa.gov/ogwdw000/uic/pdf
s/moa_uic_hyd-fract.pdf.
15 See U.S. Envt‘l Prot. Agency, EPA 816-R-04-003, Evaluation of Impacts to Underground Sources of Drinking Water by
Hydraulic Fracturing of Coalbed Methane Reservoirs (June 2004).
16 Id. at ES-9.
17 Id. at 7-3.
18 42 U.S.C. § 300h(d)(1)(B)(ii) (West 2011).
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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$10,000 for each day of a violation.19
EPA can also bring a civil action in which it can seek penalties of
$25,000 each day of a violation, or in which, in lieu of the civil penalty, the respondent can be fined and
imprisoned for not more than three years.20
Once EPA has approved a state‘s UIC program, the state
ordinary enforces in EPA‘s stead. However, EPA has the right to enforce in a state with an approved
program if, after notice from EPA, the state has not taken ―appropriate enforcement action.‖21
EPA can
also issue emergency orders ―[n]otwithstanding any other provision‖ of the SDWA.22
ii. Emergency Orders – and the Range Resources matter. Issuance of an emergency order. Section 1431 gives the EPA the power to issue emergency
orders if:
(1) a contaminant in an underground source of drinking water ―may present an imminent and
substantial endangerment to the health of persons,‖ and
(2) ―appropriate State and local authorities have not acted to protect the health of such
persons.‖23
The emergency powers can be exercised ―[n]otwithstanding any other provision of this subchapter,‖
conceivably intended to mean that a violation of the statute or any regulations promulgated thereunder is
not required for EPA to exercise its emergency powers.
The emergency order can be enforced in federal district court. EPA may seek a civil penalty of not
more than $15,000 for each day the violation of the order occurs or the failure to comply continues.24
Judicial review of an emergency order. Section 1448 prescribes the mechanisms for obtaining
any review of agency actions.25
This section provides that ―any other final action of the Administrator
under this chapter may be filed in the circuit in which the petitioner resides or transacts business which is
directly affected by the action.‖26
It further provides that, ―Action of the Administrator with respect to
which review could have been obtained [in the court of appeals] under this subsection shall not be subject
to judicial review in any civil or criminal proceeding for enforcement or in any civil action to enjoin
enforcement.‖27
Therefore, review of final actions in which the court of appeals has jurisdiction precludes
jurisdiction in district court.
The applicable standard of review of a final agency action is whether the EPA‘s action was
―arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.‖28
However,
ordinarily, when EPA brings an original enforcement action in district court, it has to prove its case by a
preponderance of the evidence.29
The Eleventh Circuit, in Tennessee Valley Authority v. Whitman,30
construed a provision in the
federal Clean Air Act (―CAA‖) that was similar to Section 1431 of the SDWA. The Eleventh Circuit held
19
42 U.S.C. § 300-h2(a)(2); 300h-2(c).
20 42 U.S.C. § 300h-2.(b)
21 42 U.S.C. § 300h-2(a)(1).
22 42 U.S.C. § 300i.
23 42 U.S.C. § 300i(a) (West 2003).
24 42 U.S.C. § 300i(b).
25 42 U.S.C. § 300j-7 (West 2003).
26 42 U.S.C. § 300j-7(a)(2) (West 2003) (emphasis added).
27 42 U.S.C. § 300j-7(a) (West 2003) (emphasis added).
28 5 U.S.C. § 706(2)(A).
29 Alaska Dep’t of Envtl. Conservation v. EPA, 540 U.S. 461, 493-494 (2004) (analyzing Clear Air Act).
30 336 F.3d 1236, 1239 (11th Cir. 2003).
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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that the CAA provision was unconstitutional and that the order issued thereunder was not a final agency
action.31
In that case, the EPA issued an unilateral administrative compliance order (―ACO‖) to the
Tennessee Valley Authority (―TVA‖) under Section 113(a)(1)(A) of the CAA32
alleging that TVA had
modified a number of its coal-fired electric power plants without first obtaining a permit.33
The TVA
appealed the order to the Eleventh Circuit.
The Eleventh Circuit described this statutory scheme as one ―in which the head of an executive
branch agency has the power to issue an order that has the status of law after finding ‗on the basis of any
information available,‘ that a CAA violation has been committed,‖ and declared it ―repugnant to the Due
Process Clause of the Fifth Amendment.‖34
This was because, said the Court, noncompliance with an order
automatically triggers civil and criminal penalties, and the respondents never get an opportunity to argue
before a neutral tribunal that they did not violate the CAA provision or regulation at issue.35
Rather, the
Court said, when issuing a unilateral order, ―EPA is the ultimate arbiter of guilt or innocence, and the
courts are relegated to a forum that conducts a proceeding, akin to a show-cause hearing, on the issue of
whether an EPA order has been flouted.‖36
Therefore, EPA ―can always avoid the arduous task of proving
[a] violation in court,‖ ―simply by issu[ing] an ACO based upon ‗any information.‘‖37
The Eleventh Circuit summarized its holding as follows:
We hold that we lack jurisdiction to review the ACO because it does not constitute ―final‖
agency action. Although the CAA empowers the EPA Administrator to issue ACOs that
have the status of law, we believe that the statutory scheme is unconstitutional to the extent
that severe civil and criminal penalties can be imposed for noncompliance with the terms of
an ACO. Accordingly, ACOs are legally inconsequential and do not constitute final agency
action. We therefore decline to assert jurisdiction over TVA‘s petition for review pursuant to
42 U.S.C. § 7607(b)(1). The EPA must prove the existence of a CAA violation in district
court; until then, TVA is free to ignore the ACO without risking the imposition of penalties
for noncompliance with its terms.38
The Range Resources Order.39
On December 7, 2010, EPA – without notice or an opportunity for
a hearing – issued an Emergency Administrative Order (―Emergency Order‖) pursuant to Section 1431 of
the Act to Range Resources Corporation and Range Production Company (collectively, ―Range‖).40
The
Emergency Order contains the following relevant findings: (1) that certain contaminants in the two
domestic water wells ―may present an imminent and substantial endangerment to the health of persons;‖ (2)
that the presence of one of these contaminants in the domestic water wells is ―likely to be due to impacts
from gas development and production activities in the area;‖ and (3) that two gas wells operated by Range
31
TVA, 336 F.3d at 1239.
32 42 U.S.C. § 7413(a)(1)(A) (2003).
33 TVA, 336 F.3d at 1244.
34 Id. at 1258 (emphasis added).
35 Id. at 1243.
36 Id.
37 Id. at 1250.
38 Id. at 1239-40.
39 Kelly Hart & Hallman LLP represents Range Resources in this matter.
40 The discussion of Range Resources matter is largely a synopsis of the description in a paper by J. Stephen Ravel, Holly A.
Vandrovec, & Chad Smith, Hydraulic Fracturing 2011 – the Three Branches of Government and the Fourth Estate, 2011
Environmental Superconference (hereinafter Ravel Vandrovec & Smith).
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―are the only gas production facilities within approximately 2,000 feet of the domestic wells.‖41
The
Emergency Order did not contain a finding of fact that Range actually caused or contributed to the alleged
contamination of the domestic water wells or to the alleged endangerment. Instead, EPA made that
assertion as a conclusion of law in paragraph 46 of the Emergency Order. The Emergency Order required
Range to:
A. Provide, within forty-eight hours of receipt of the Emergency Order, replacement potable
water supplies for the consumers of water from the domestic water wells;
B. Install, within forty-eight hours of receipt of the Emergency Order, explosivity meters in the
dwellings served by the domestic water wells;
C. Submit, within five days of receipt of the Emergency Order, a survey listing and identifying
the location description of all private water wells within 3,000 feet of the wellbore track of
one of Range‘s gas wells and all public water supply system wells in the affected
subdivision, along with a plan to sample those wells to determine whether they are
contaminated;
D. Submit, within fourteen days of receipt of the Emergency Order, a plan to conduct soil gas
surveys and indoor air concentration analyses of the properties and dwellings served by the
domestic water wells; and
E. Develop and submit, within sixty days of receipt of the Emergency Order, a plan to: (i)
identify gas flow pathways to the Trinity Aquifer; (ii) eliminate gas flow to the aquifer if
possible; and (iii) remediate areas of the aquifer that are contaminated.42
Despite its protests that it had not received due process, Range consulted with EPA, provided
alternative water to the homes with contaminated wells, and hired experts to perform gas, water, soil-gas,
and geologic tests. By doing so, Range complied (albeit for different purposes) with requirements A – C of
the Emergency Order.
The RRC Called Hearing and Resulting Discovery Litigation. On December 8, 2010 – the day
after the EPA issued its Emergency Order to Range – the RRC set a hearing ―to consider whether the
operation of the [Range gas wells] is causing or contributing to contamination of certain domestic water
wells in Parker County, Texas and/or whether there is an alternative cause or contributor to any such
contamination.‖43
In its order, the Commission ordered Range to appear at the hearing to present
evidence, and ―encouraged‖ EPA to participate in the hearing and to present evidence supporting the
findings of fact and conclusions of law in EPA‘s Emergency Order.44
To discover the bases for the allegations in EPA‘s Emergency Order, Range obtained deposition
commissions for the EPA personnel responsible for preparing the Emergency Order. After the EPA
refused to allow its personnel to testify or to produce documents and made it known that it would not
participate in the RRC hearing to defend its order, Range filed suit against EPA, challenging EPA‘s final
decision to refuse to allow its employees to appear for deposition and to produce documents in response to
subpoenas issued by the RRC. Range also immediately after filed a motion to compel deposition testimony
and document production.45
The district court required EPA to designate one person to be deposed on
information relevant to the issuance of its Emergency Order and the administrative record on which it was
based. 46
41
Emergency Administrative Order, Docket No. SDWA-06-2010-1208 (hereafter, ―Order‖) at ¶¶ 11, 27, 41.
42 Order at ¶ 50.
43 RRC Order Calling Hearing, Oil and Gas Docket No. 7B-0268629 (hereafter, ―RRC Order‖) at 1-2.
44 RRC Order at 3.
45 See Range Prod. Co. v. EPA, No. 1:11-CV-11 (W.D. Tex. Jan. 1, 2011) Docket No. 1 (Complaint) and Docket No. 4 (Motion
to Compel).
46 See Civil Action No. 1:11-CV-11, Docket No. 32.
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The RRC hearing was held on January 19, 2011. Range presented its case at the RRC hearing,
arguing that no evidence showed that Range‘s operations at its gas wells caused or contributed to the issues
with the domestic water wells in Parker County. Neither EPA nor the owners of the Parker County
domestic water wells showed up at the RRC hearing. The Commission left open the record before it so that
it could be supplemented with information obtained via the motion to compel filed in federal district court.
At the deposition of EPA‘s designated representative, Mr. Blevins, counsel for EPA refused to
allow Mr. Blevins to answer any questions regarding the basis for EPA‘s conclusions of law – including the
conclusion of law asserting that Range caused or contributed to the alleged contamination or endangerment.
Mr. Blevins apparently could not have testified as to the technical issues concerning the alleged causation
of the contamination in any case, testifying that he was not a part of the ―core group‖ of EPA scientists
involved in making that determination.
Range supplemented the record at the RRC with EPA‘s deposition testimony. On March 22, 2011,
the RRC issued an order finding that Range‘s operations had not caused or contributed to the contamination
of either domestic water well.
EPA Sues to Enforce Its Emergency Order. On January 18, 2011, EPA sued Range in the
Northern District of Texas, Dallas Division to enforce its Emergency Order. In the enforcement action,
EPA alleges that Range violated provisions of the Emergency Order and seeks: (1) a permanent injunction
requiring Range to comply with the Emergency Order; and (2) entry of a judgment against Range for civil
penalties of up to $16,500 for each day of each violation of the Emergency Order.47
Range filed a motion
to dismiss, arguing that the Emergency Order should not be considered ―final‖ for purposes of an
enforcement action and that EPA‘s enforcement action should be dismissed for lack of subject matter
jurisdiction because the Emergency Order was not ripe for enforcement. Range argued, in the alternative,
that EPA‘s complaint should be dismissed because EPA failed to state a claim by not pleading the requisite
elements necessary to satisfy due process or facts necessary to state a claim for relief that is plausible on its
face.48
Range’s Petition for Review in the Fifth Circuit. On January 20, 2011, Range filed a petition for
review in the Fifth Circuit to avoid waiving any other right to challenge the Emergency Order, since EPA‘s
Emergency Order provided that it was a ―final agency action for purposes of SDWA § 1448 . . . ‖49
Nevertheless, in its petition for review, Range asserted that the Emergency Order does not constitute a final
agency action. Range further asserted that EPA, in its enforcement action in district court, bears the burden
of proving the essential elements of a claim under the SDWA and that Range has the right to assert any
applicable defenses and constitutional challenges. Range asked that the Fifth Circuit hold that the
Emergency Order is not a final agency action and, thus, is not subject to review under Section 1448 of the
Act. The case was fully briefed on May 26, 2011 and oral argument was heard on October 3, 2011.
The District Court Denies Range’s Motion but Stays Action and Penalties. On June 20, 2011,
the district court denied Range‘s motion to dismiss but stayed the case awaiting a decision on the issues
before the Fifth Circuit.50
Importantly, the court ruled that it would not award any daily civil penalties to
EPA during the stay.51
EPA withdraws its order. Then, on March 29, 2012, EPA withdrew its Emergency Order.52
On
March 30, 2012, Range agreed to conduct four sampling tests every three months over the course of the
next year at each of the twenty private wells thought to have been polluted.53
With the landowners'
47
U.S. v. Range Prod. Co. & Range Resources Corp., Civil Action No. 3:11-CV-00116-F, in the Northern District of Texas,
Dallas Division, Docket No. 1.
48 EPA‘s Response to Range‘s Motion to Dismiss was filed on May 9, 2011.
49 Emergency Order, Finding of Fact 70 (emphasis added).
50 United States v. Range Prod. Co., 793 F. Supp. 2d 814 (N. D. Tex. 2011).
51 Id. at 20.
52 See, e.g., March 29, 2012 Letter from John Blevins of EPA to David Poole of Range Resources Corporation.
53 March 30, 2012 Letter from John A. Riley to Steven E. Chester.
The Future Of Regulation In Hydraulic Fracturing Chapter 23
7
approval, it will test for such dissolved gases as carbon dioxide, hydrogen, nitrogen and methane, as well as
such organic substances as benzene, toluene, ethyl benzene and xylene.
iii. Supreme Court hands down decision in Sackett.
This spring, the United States Supreme Court had the opportunity to review another statutory
unilateral compliance order, this time under the Clean Water Act. That case, Sackett v. EPA,54
involved an
EPA-issued compliance order directed at the Sacketts. The Sacketts own a .63-acre undeveloped lot in
Idaho. In April and May of 2007, the Sacketts filled in about one-half acre of that property with dirt and
rock in preparation for building a house. In November 2007, EPA issued a compliance order alleging that
the parcel is a wetland and that the Sacketts violated the CWA by filing in their property without first
obtaining a permit. The order required them to move the fill material and restore the parcel to its original
condition. The order stated that the violation of the order ―may subject‖ the Sacketts to civil penalty of up
to $32,500 per day for violation or administrative penalties of up to $11,000 per day for each violation.
The Sacketts sought a hearing to challenge EPA‘s findings, but EPA refused to grant such a
hearing. The Sacketts then filed suit in district court seeking injunctive and declaratory relief. The
Sacketts challenged the order on several grounds, including that it was issued without a hearing, in
violation of due process, and that the factual basis on which it issued, that of ―any information available,‖ is
unconstitutionally vague.
The district court granted EPA‘s motion to dismiss for lack of subject-matter jurisdiction. It
concluded that the CWA precludes judicial review of compliance orders before the EPA has started an
enforcement action.
The Ninth Circuit affirmed. In reaching its decision, the Court discussed the enforcement scheme –
similar to that of other environmental statutes – under which EPA can (i) assess an administrative penalty,
(ii) initiate a civil enforcement action, or (iii) issue an administrative compliance order. In the first two
actions – assessing an administrative penalty or initiating a civil enforcement action – the respondent is
entitled to a hearing, and EPA must prove its case before the order issues. However, no statute provides for
pre-enforcement judicial review of compliance orders.
The Ninth Circuit declined to interpret the CWA in a way that would make it unconstitutional, as
the Eleventh Circuit had done in TVA. It rejected the argument that the Sacketts would risk substantial
penalties for violating the compliance order, even if they did not violate the CWA, if EPA established only
that the compliance order was validly issued on the basis of ―any information available.‖55
Instead, the
court held that penalties could be assessed only for violation of a compliance order that is predicated on
actual, not alleged, violations of the CWA, ―as found by a district court in an enforcement action according
to traditional civil evidence rules and burdens of proof.‖56
The United States Supreme Court rendered its decision in Sackett on March 21, 2012. In the
unanimous opinion authored by Justice Scalia, the court held that EPA‘s compliance order was a ―final
agency action‖ for which there was no adequate remedy other than review under the APA. The Supreme
Court further held that nothing in the language or structure of the Clean Water Act suggested that Congress
intended to preclude judicial review of EPA‘s assertion of jurisdiction. Justice Ginsburg‘s concurring
opinion stated that she joined the decision with the understanding that it was limited only to judicial review
of jurisdictional question, ie., whether EPA had jurisdiction to issue an order, so the decision does not
answer the question whether one can obtain pre-enforcement review of a claim that EPA is improperly
exercising its jurisdiction.
c. EPA’s pending permitting guidance on the use of diesel fuel in hydraulic fracturing fluid.
EPA – although authorized by the Energy Policy Act of 2005 to regulate the use of diesel fuels in
hydraulic fracturing – never promulgated rules to do so. In 2010, after Representative Waxman disclosed
54
622 F.3d 1139 (9th
Cir. 2010), rev’d, 132 S. Ct. 1367 (2012).
55 Id. at 1145.
56 Id.
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8
the findings of an investigation showing that companies had continued to use diesel fuel in hydraulic
fracturing fluids after 2005, EPA took steps to impose such rules.
EPA first posted permitting directions for fracturing on its website, without prior notice.57
It was
unclear from the post whether EPA would find that companies who had used diesel without a permit since
2005 had violated the law, even though no permitting process existed. On August 21, 2010, the
Independent Petroleum Association of America (―IPAA‖) sued to challenge the agency‘s website posting
of permitting directions.58
Since April 2011, EPA has been soliciting comments in order to prepare a permitting guidance.59
IPAA‘s position is that guidance is not sufficient; IPAA wants a full rulemaking rather than guidance.60
EPA‘s authority to proceed by informal guidance document rather than a full notice-and-comment
rulemaking will likely be tested on this issue.
On May 10, 2012, EPA published its permitting guidance for comments.61
Important parts of the
proposed guidance include:
Defining ―diesel fuel‖ as one of six CASRNs: 68334-30-5 (Fuels, diesel), 68476-34-6
(Fuels, diesel No. 2), 68476-30-2 (Fuel oil No. 2); 68476-31-3 (Fuel oil, no. 4), 8008-20-6
(kerosene); 68410-00-4 (distillates (petroleum), crude oil).
Authorizing an ―area permit‖ for injection into multiple Class II wells.
Recommending that the permit writer either set a short duration for the permit or
temporarily abandon the well.
Recommending that the ¼ mile area of review be modified so that it is sufficiently
protective of USDWs.
Recommending that the permit writing request additional information from the operator that
includes:
o Maps and cross sections of the AOR showing the extent and orientation of the
planned fracture network, any USDWS, and their connection to surface water;
o A plugging and abandonment plan that incorporates monitoring of USDWs in the
AOR to demonstrate non-endangerment.
o A detailed chemical plan describing the proposed fracturing fluid composition,
including the volume and range of concentrations for each constituent.
o Baseline geochemical information on USDWs and other subsurface formations of
interest within the AOR, which may require characterization of formation fluids
through logging and testing parameters, such as TDS, specific conductance, pH;
chlorides; bromides; acidity; alkalinity; sulfate; iron; calcium; sodium; magnesium;
potassium; bicarbonate; detergents; DRO; and BTEX.
Recommending that permit writers ensure that surface casing and cement extend through the
base of the lowermost USDW and review additional information when specifying casing
and cementing requirements for Class II fraced wells using diesel fuels.
Recommending that the permit writer obtain information to help take adequate precautions,
in light of the high injections pressures, such as
57
See http://www.nytimes.com/gwire/2011/04/13/13greenwire-fracking-for-natural-gas-with-diesel-violated-81979.html.
58 Independent Pet. Ass’n of Am. v. EPA, No. 10-1233, (D.C. Cir. Aug. 12, 2010).
59 http://www.nytimes.com/gwire/2011/04/29/29greenwire-epa-starts-work-on-diesel-fracking-guidance-44996.html
60 Opening Brief of Petitioners Independent Petroleum Ass'n of America and the US Oil & Gas Ass'n, Independent Pet. Ass'n of
Am. and US Oil & Gas Ass'n v. EPA, p. 39, No. 10-1233 (D.C. Cir. March 31, 2011).
61 See 77 Fed. Reg. 27451 (May 10, 2012). See also United States EPA, Permitting Guidance for Oil and Gas Hydraulic
Fracturing Activities Using Diesel Fuels – Draft: Underground Injection Control Program Guidance # 83.
The Future Of Regulation In Hydraulic Fracturing Chapter 23
9
o a description of the geologic formations overlying the production zone, and whether
they might contain gas, oil or other potentially mobile contaminants that should be
isolated from the well by cement.
o Physical and chemical characteristics of the formation fluids and the proposed
characteristics of the well, such as the size of the well bore.
o Location and operating procedures of other active injection wells or wells
undergoing HF in the AOR or nearby injection zones.
o Data on sizes and grades of the casing string and classes of cement to be used.
Recommending that permit writer ensure that the owner or operator applies relevant
construction-related requirements to already constructed Class II wells using diesel fuels.
EPA clarified that the guidance does not apply in states which have UIC primacy, such as Texas.
However, EPA encouraged primacy states to ban diesel fuels in hydraulic fracturing fluids entirely. The
draft guidance is open for comment from May 10, 2012 to July 9, 2012.
d. EPA’s pending hydraulic fracturing study.
EPA, at the direction of Congress, is undertaking a study of hydraulic fracturing to better
understand any potential impacts on drinking water and groundwater.62
EPA has consulted with experts in
the field through peer review and technical workshops.63
EPA has also held public meetings to engage
stakeholders. 64
The purpose of the study is to understand the relationship between hydraulic fracturing and drinking
water resources. The scope of the proposed research includes the full lifespan of water in hydraulic
fracturing, from acquisition of the water, through the mixing of chemicals and actual fracturing, to the post-
fracturing stage, including the management of flowback and produced water and its ultimate treatment and
disposal.
On August 11, 2011, EPA sent letters to nine oil and gas companies requesting their voluntary
participation in EPA‘s hydraulic fracturing study. EPA requested data on well construction, design, and
well operation practices for 350 oil and gas wells that were hydraulically fractured from 2009-2010. All
nine oil and gas companies advised EPA that they would assist it. By sharing information about specific
well construction design and operations, EPA anticipates that these companies will help EPA and the
public better understand they technologies and practices associated with hydraulic fracturing.65
According to EPA, the wells included in the study were selected using a stratified random method
and to reflect the diversity in both geography and size of the oil and gas operator. However, Commissioner
Porter of the RRC contended that the wells were chosen on the basis of complaints, which could skew
results.66
Because of this, and distrust arising from the RRC‘s dispute with EPA regarding Range, the RRC
had personnel on site to split samples with EPA when any samples are taken.67
EPA expects to issue initial research results by the end of 2012, and a final report in 2014.68
62
http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/index.cfm
63 Id.
64 Id.
65 Id.
66 David Porter, Texans don’t fear science; neither should the EPA, Fort Worth Star-Telegram, http://www.star-
telegram.com/2011/09/19/v-print/3380224/porter-texans-dont-fear-science (Sept. 19, 2011).
67 Id.
68 Id.
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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e. Department of Energy’s (“DOE’s”) Advisory Reports.
As discussed above, the EPA administers both the Safe Drinking Water Act and the Clean Water
Act. Nonetheless, the DOE also has taken a role in developing a regulatory framework for hydraulic
fracturing. Because a report based on EPA‘s hydraulic fracturing study will not issue until 2014, President
Obama, on March 31, 2011, asked Steven Chu, the Energy Secretary, to assemble a subcommittee charged
with producing an advisory report within ninety days of its first meeting (the ―90-day Report‖). The
DOE‘s committee was comprised of a group of energy experts from academia, industry, and environmental
organizations.
DOE‘s 90-day Report, issued on August 11, 2011, calls for the following:
Requiring better tracking and more careful disposal of waste to protect water quality.
o Measuring and reporting composition of water stocks and flow.
o Manifesting all transfers of water.
o Adopting best management practices in well development and construction.
Using pressure testing and cement bond longs to confirm formation isolation.
Carrying out microseismic surveys to assure that hydraulic fracture growth is
limited to the gas-producing formations.
Regulating more effectively to ensure operators have repaired defective
cementing jobs.
Performing additional field studies on possible methane leakage from shale
gas wells to water reservoirs.
o Requiring the disclosure of fracturing fluid composition, even though risk of fluid
leakage into drinking water through factures made in deep shale is ―remote.‖
o Reducing or eliminating the use of diesel fuel in fracturing fluid since other, more
innocuous substances can be substituted.
o Reducing the use of diesel engines in favor of natural gas engines or electricity.
o Managing impact on communities, land use, wildlife, and ecologies.
Using multi-well drilling pads to minimize transport traffic and road
construction.
Evaluating water usage at the affected watershed.
Requiring notice of anticipated environmental and community impacts.
Developing ways to minimize impact, particularly in sensitive areas.
Imposing stricter standards on air pollutants, ozone precursors, and methane as quickly as
possible.
Creating a federal database so the public can better monitor drilling operations.
Making available federal financing of more efficient and clean drilling techniques (funded
by fees and taxes).
Undertaking further study to settle disagreements about whether natural gas is actually less
harmful to the environment than coal or other fuel sources. The DOE report discussed two
studies that reached opposing conclusions regarding greenhouse gasses generated by shale
gas production. A group of Cornell professors had published an article concluding that
methane and greenhouse gases from shale formations might contribute more to greenhouse
gasses than does coal.69 The DOE‘s National Energy Technology Laboratory (―NETL‖)
69
Robert W. Howarth, Renee Santoro, and Anthony Ingraffea, Methane and the greenhouse-gas footprint of natural gas from
shale formations, Climate Change, The online version of this article (doi:10.1007/s10584-011-0061-5) contains supplementary
material.
The Future Of Regulation In Hydraulic Fracturing Chapter 23
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reviewed the same information, and concluded that when used to generate electricity, natural
gas – conventional or not – results in far fewer emissions than coal.70
Significantly, DOE’s 90-day Report described contamination of drinking water from
hydraulic fracturing chemicals as remote where the producing zone is far removed from the drinking
water source. Instead, the report refers to the risk of gas migrating into the aquifers as a greater source of
concern needing further study, based in part on a recent peer-reviewed article discussing such pollution in
northern Pennsylvania.71
The DOE was also charged with providing, within 180 days of its first meeting, consensus-
recommended advice to the agencies on practices for shale extraction to ensure the protection of public
health and the environment (―the Second 90-day Report‖). The Second 90-day Report issued on November
18, 2011.72
That report prioritized the DOE‘s various recommendations and focused on means of
implementing them.
f. Other studies.
Researchers at the Durham University in the United Kingdom have found that fracturing at least
2,000 feet below an aquifer will minimize chances of contamination in the United States. The study,
published in the journal Marine and Petroleum Geology, is relevant to the Marcellus Shale in Pennsylvania,
the Barnett and Eagle Ford in Texas, the Niobrara in Colorado, and the Woodford in Oklahoma. Richard
Davies, co-author of the study, concludes that the Earth has a number of ―safety mechanisms‖ that stop
natural hydraulic fractures from going on forever.73
From this, he extrapolates that the Earth will use those
same safety mechanisms to stop induced hydraulic fractures from going on forever.
2. The Clean Water Act.
a. Structure and history.
The Clean Water Act (―CWA‖) prohibits the unpermitted discharge of pollutants by ―point sources‖
into the ―waters of the United States.‖74
The permitting program authorizing such discharges is known as
the National Pollutant Discharge Elimination System (―NPDES‖) program.75
In establishing requirements
for a NPDES permit, the CWA requires the EPA or other permit writer to consider both the technology
available to control pollutants (―technology-based effluent limits‖) and limits that will meet water quality
standards (―water quality-based effluent limits‖).76
As with the SDWA and other federal environmental
programs, EPA administers the NPDES program until EPA has reviewed and approved the state‘s program.
Both direct and indirect discharges into waters of the United States are subject to the NPDES
program. A direct discharge, such as through a pipeline, requires a NPDES discharge permit. An indirect
discharge, such as the one that occurs when an entity disposes of its wastewater into a publicly owned
70
Timothy J. Skone, Life Cycle Greenhouse Gas Analysis of Natural Gas Extraction & Delivery in the United States, DOE,
NETL, May 2011, available at:
http://www.netl.doe.gov/energyanalyses/ pubs/NG_LC_GHG_PRES_12MAY11.pdf
71 90-day Report, p. 20.
72 Secretary of Energy Advisory Board, Shale Gas Production Subcommittee Second Ninety Day Report (Nov. 18, 201).
73 Davies, R.J., et al., Hydraulic fractures: How far can they go?, Marine and Petroleum Geology (2012),
doi:10.1016/j.marpetgeo.2012.04.001
74 The term ―waters of the United States‖ – which is necessary for federal jurisdiction to attach – has been litigated repeatedly.
See, e.g. Rapanos v. U. S., 547 U.S. 715 (2006); Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers,
531 U.S. 159 (2001). See also 40 CFR 122.2 and 230.3(s). EPA and the Corp have proposed additional proposed agency
guidance, which can be found at
http://water.epa.gov/lawsregs/guidance/wetlands/upload/wous_guidance_4-2011.pdf.
75 33 U.S.C. § 1342(a) (West 2001).
76 Id. at § 1311; 40 C.F.R. 125.3(a) (2011).
The Future Of Regulation In Hydraulic Fracturing Chapter 23
12
treatment works (―POTW‖), is also covered under the CWA, when the POTW subsequently discharges into
waters of the United States.77
Often, the entity that discharges into a POTW is required to test or pretreat
its wastewater before discharging it into the POTW.78
Therefore, EPA and the states regulate the indirect disposal of hydraulic fracturing wastewater into
a POTW – whether via a sewer system or a truck – under the CWA, as along as the discharge ultimately
leads to waters of the U.S.79
b. Pending natural gas wastewater effluent limitations under § 304(m)
In 2011, a series of articles in the New York Time sparked a public outcry for more stringent laws
and regulations on the disposal of ―flow-back water‖ or wastewater resulting from hydraulic fracturing
operations.80
The articles focused primarily on alleged contamination caused by the disposal of wastewater
following hydraulic fracturing operations in the Marcellus Shale region. In the Marcellus Shale, in
particular, disposal is an issue because there are far fewer saltwater disposal wells. As a result, saltwater
and produced waters have been discharged through publicly owned treatment works (―POTWs‖),
regardless whether the particular POTW had appropriate pretreatment standards or was able to treat the
water itself. Compounding the problem is the apparent presence of radionuclides in the wastewater (a
problem that we haven‘t encountered in Texas so far).
EPA, on October 20, 2011, announced a schedule to develop standards that must be met before
wastewater produced in extracting natural gas from shale formations is taken to a POTW.81
The standards
would be developed under section 304(m) of the Clean Water Act. EPA‘s stated goal is to develop those
standards based on demonstrated, economically achievable technologies.82
Wastewater associated with coalbed methane extraction is not subject to national standards.
Instead, its regulation is left to individual states. EPA will be considering uniform national standards for
the discharge of wastewater from coalbed methane extraction based on economically achievable
technologies.
EPA plans to propose the new standards for public comment in 2014.83
c. Enforcing the CWA.
The CWA, like the Safe Drinking Water Act, is enforced by EPA until a state is authorized to
enforce in EPA‘s stead. In Texas, the TCEQ is authorized to administer the CWA.84
But discharges from
oil and gas activities are regulated by the Railroad Commission rather than the TCEQ.85
So, for certain
matters over which the RRC has jurisdiction, the operator must work with EPA as well as the RRC.
77
33 U.S.C. §§ 317(b)-(d).
78 Id.
79 Memo from James Hanlon, Director of EPA‘s Office of Wastewater Management, to the EPA Regions, Natural Gas Drilling
in the Marcellus Shale NPDES Program Frequently Asked Questions (March 16, 2011), available at
http://www.epa.gov/npdes/pubs/hydrofracturing_faq_memo.pdf.
80 Ian Urbina, Regulation Lax as Gas Wells’ Tainted Water Hits Rivers, NY TIMES, Feb. 26, 2011, at A1; Ian Urbina,
Wastewater Recycling No Cure-All in Gas Process, NY TIMES, March 1, 2011, at A1; Ian Urbina, Pressure Limits Efforts to
Police Drilling for Gas, NY TIMES, March 3, 2011, at A1.
81 http://www.epa.gov/hydraulicfracture/oil_and_gas_research_mou.pdf (visited April 15, 2012).
82http://yosemite.epa.gov/opa/admpress.nsf/bd4379a92ceceeac8525735900400c27/91e7fadb4b114c4a8525792f00542001!Open
Document (visited on June 23, 2012).
83 http://water.epa.gov/scitech/wastetech/guide/shale.cfm (visited May 15, 2012).
84 Texas has been delegated such authority. See 63 Fed. Reg. 51164 (Sept. 24, 1998).
85 See, e.g. TEX. WATER CODE ANN. § 26.131 (West 2008); see also 16 TEX. ADMIN. CODE § 3.30 (2012) (MOU between the
RRC and the TCEQ).
The Future Of Regulation In Hydraulic Fracturing Chapter 23
13
To enforce the CWA, EPA can seek administrative penalties of up to $10,000/day for a maximum
of $125,000.86
EPA can seek civil penalties up to $25,000 per day or an amount up to $1,000 per barrel of
oil discharged.87
3. RCRA.
RCRA regulates the handling of hazardous wastes. In 1980, RCRA was amended to exempt
―drilling fluids, produced waters, and other wastes associated with the exploration, development, or
production of crude oil or natural gas or geothermal energy‖ from RCRA‘s federal hazardous waste
regulation until at least six months after EPA submitted to Congress a comprehensive study of the adverse
effects, if any, of such wastes on human health and the environment.88
After EPA completed its study, it
decided ―not to regulate wastes generated by the exploration and development of geothermal energy
resources under RCRA Subtitle C. . . because of the relatively low risk of these wastes and the presence of
generally effective State and Federal regulatory programs.‖89
In addition, EPA noted that ―imposition of
Subtitle C regulations for all oil and gas wastes could subject billions of barrels of waste to regulation
under Subtitle C as hazardous wastes and would cause a severe economic impact on the industry and on oil
and gas production in the U.S.‖90
4. CERCLA.
CERCLA is a liability rather than a regulatory statute. Section 107 of CERCLA creates liability for
potentially responsible parties ("PRPs"), if a release or a threatened release of a "hazardous substance‖ has
caused any person to incur response costs.91
CERCLA defines a "hazardous substance" broadly, but
excludes from the definition of a hazardous substance ―petroleum, including crude oil or any fraction
thereof which is not otherwise specifically listed or designated as a hazardous substance . . . and the term
does not include natural gas, natural gas liquids, liquefied natural gas, or synthetic gas usable for fuel."92
This exclusion is referred to as the "petroleum exclusion." For that reason, upstream oil and gas
contamination is not generally subject to CERCLA‘s provisions.
Pavillion, Wyoming. Regardless, EPA has recently used its CERCLA authority to investigate
groundwater pollution at a site in Pavillion, Wyoming that was potentially impacted by oil and gas
production activities.93
Several potential sources of pollution existed. On December 8, 2011, EPA released
a draft report (―Draft Pavillion Report‖) concluding that fractured wells were the source of the
contamination.94
The Draft Pavillion Report does not condemn hydraulic fracturing in general. Instead, it
focuses on what it identifies as specific limitations on wells in the area – i.e., the lack of sufficient surface
casing or defective surface casing. The Draft Pavillion Report noted several shortcomings with cementing
practices in the area:
Hydraulic fracturing in gas production wells occurred as shallow as 372 meters below
ground surface with associated surface casing as shallow as 110 meters below ground
surface. Domestic and stock wells in the area are screened as deep as 244 meters below
ground surface. With the exception of two production wells, surface casing of gas
86
33 U.S.C. § 1321(b)(6).
87 33 U.S.C. § 1321(b)(7).
88 Solid Waste Disposal Act of 1980, Pub. L. No. 96-482, S. 1156.
89 53 Fed. Reg. 25446 (July 6, 1988).
90 53 Fed. Reg. 25446 (July 6, 1988).
91 42 U.S.C. § 9607(a)(4).
92 42 U.S.C. § 9601(14).
93 http://www.epa.gov/region8/superfund/wy/pavillion/Pavillion_Ph2PublicPresentation083110.pdf
94 Dominic C. DiGiulio, Richard T. Wilkin, Carlyle Miller, and Gregory Oberley, Draft Investigation of Ground Water
Contamination near Pavillion, Wyoming (U.S. EPA Dec. 2011).
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production wells do not extend below the maximum depth of domestic wells in the area of
investigation.95
. . . .
A review of well completion reports and cement bond/variable density logs in the area
around MW01 and MW02 indicates instances of sporadic bonding outside production casing
directly above intervals of hydraulic fracturing. Also, there is little lateral and vertical
continuity of hydraulically fractured tight sandstones and no lithologic barrier (laterally
continuous shale units) to stop upward vertical migration of aqueous constituents of
hydraulic fracturing in the event of excursion from fractures. In the event of excursion from
sandstone units, vertical migration of fluids could also occur via nearby wellbores. For
instance, at one production well, the cement bond/variable density log indicates no cement
until 671 m below ground surface. Hydraulic fracturing occurred above this depth at nearby
production wells.96
Regardless whether the casing issues caused contamination or not – this would not happen in Texas.
As it is, the operator of the wells, EnCana Oil and Gas (USA) Inc. (―EnCana‖), strongly disputes
EPA‘s initial conclusions.97
EnCana notes that the water from the groundwater wells EPA tested did not
exceed any contaminant levels.98
Further, EnCana argues, the natural gas constituents found in EPA‘s deep
monitoring wells are naturally occurring, and, in fact, EPA could have produced gas in paying quantities
had EPA dug its well slightly deeper.
On January 17, 2012, EPA sought nominations for peer reviews for the Draft Pavillion Report.99
EPA will accept public comments on the Draft Pavillion Report through October 2012.100
Dimock, Pennsylvania. On January 19, 2012, EPA announced it would use its CERCLA § 104(a)
authority to test 61 water wells in Dimock, Pennsylvania,101
where residents say drilling activity by Cabot
Oil & Gas Corp. (―Cabot‖) has polluted their water wells.102
Cabot trucked water to residents for three
years until November 2011, when it stopped with permission from state regulators.
EPA‘s action memorandum states that inorganic hazardous substances are present in four home
wells at levels that present a public health concern. The memorandum speculates that historic drilling
activities may have used materials containing hazardous substances, and also that spills and other releases
occurred during those activities.
Cabot takes issue with EPA‘s statements and with its interpretation of the data, largely collected and
produced by Cabot.103
On May 11, 2012, EPA released the results of its testing.104
The testing showed that no
contaminants exceeded action levels.105
95
Id. at xi.
96 Id. at xiii.
97 http://www.oilgaslawbrief.com/hydraulic-fracturing/encanas-response-to-epas-draft-report-on-pavillion/
98 Id.
99 77 Fed. Reg. 2292 (Jan. 17, 2012).
100 http://www.epa.gov/region8/superfund/wy/pavillion/index.html (visited on June 16, 2012). The deadline was not yet
published in the Federal Register, as of June 16, 2012. The earlier deadline had been Jaunary 27, 2011. See 76 Fed. Reg. 77829
(Dec. 14, 2011).
101 http://yosemite.epa.gov/opa/admpress.nsf/0/8eb78248ce13d9dc8525798a0070f991?OpenDocument
102 http://www.epaosc.org/sites/7555/files/Dimock%20Action%20Memo%2001-19-12.PDF
103 http://www.cabotog.com/pdfs/Cabot_Statement_EPAWaterDelivery.pdf
104 http://www.epa.gov/aboutepa/states/pa.html (visited June 16, 2012).
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5. National Environmental Policy Act (“NEPA”).
The National Environmental Policy Act (―NEPA‖) is a federal statute requiring federal agencies to
consider the environmental impacts of major federal actions.106
Under NEPA, the appropriate agency must
prepare an Environment Impact Study (―EIS‖) and allow for public comment before taking a major federal
action.107
The EIS must consider the adverse environmental impacts of the proposed action, as well as
describe the available alternatives.108
Although the NEPA requirements are ―essentially procedural,‖109
the
requirements can have major substantive effects. The preparation of an EIS is a time-consuming and costly
endeavor that can delay projects for years. Further, plaintiffs opposed to a particular project (including
hydraulic fracturing) have sued for purported NEPA violations under the APA to further delay or even kill
the proposed project.110
6. The BLM: Regulation of hydraulic fracturing on federal lands.
On May 11, 2012, the Bureau of Land Management (―BLM‖) issued proposed rules that would
require companies to publicly disclosure the chemicals used in hydraulic fracturing operations on federal
and Indian lands.111
The proposed rule also strengthened regulations related to well-bore integrity and
addressed issues related to flowback fluid management. The rules were criticized by industry as
unnecessary and duplicative of existing state laws.112
On June 26, 2012, the BLM extended the public
comment period until September 10, 2012.113
7. Federal Partnership for Unconventional Natural Gas and Oil Research
On April 13, 2012, three federal agencies announced a formal partnership to coordinate the
development of unconventional natural gas and oil. The three agencies are the Department of the Interior,
Secretary of Energy, the EPA. Under the terms of the Memorandum of Understanding, the DOI, DOE and
EPA will identify research priorities and collaborate to sponsor research that ―improves our understanding
of the impacts of developing our Nation's unconventional oil and gas resources and ensure the safe and
prudent development of these resources.‖ 114
B. State water quality regulation.
1. Railroad Commission of Texas.
The Railroad Commission of Texas, which is charged with regulating the oil and gas industry,
administers the portion of the federal UIC program related to underground injection for the purposes of oil
and gas exploration and development.115
No separate permit for fracturing. As discussed above, the RRC does not require a separate
permit to complete a well using hydraulic fracturing.
105
http://www.reuters.com/article/2012/05/11/usa-fracking-dimock-idUSL1E8GBVGN20120511
106 See National Environmental Policy Act, 42 U.S.C. § 4321; Holly A. Vandrovec, Litigation Trends Involving Environmental
Concerns Over Hydraulic Fracturing, Second Conference on the Law of Shale Plays 7 (2011).
107 § 4321.
108 Vandrovec, at 7.
109 Id. (citing Vermont Yankee Nuclear Power Corp. v. Natural Resources Defense Council, 435 U.S. 519, 558 (1978)).
110 NEPA does not expressly provide for judicial review, so plaintiffs must sue for NEPA violations under the Administrative
Procedures Act. Vandrovec, supra note 1.
111 77 Fed. Reg. 27691 (May 11, 2012).
112 http://www.api.org/News-and-Media/News/NewsItems/2012/May-2012/Excellence-in-state-oversight-of-
hydraulic-fracturing-makes-BLM-proposed-rule-unnecessary.aspx
113 77 Fed. Reg. 38024 (June 26, 2012).
114 http://www.epa.gov/hydraulicfracture/oil_and_gas_research_mou.pdf
115 47 Fed. Reg. 17488 (April 23, 1982).
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Must meet all general construction and casing standards. Hydraulic fracturing is simply a
particular type of well completion. So, even though the process of hydraulic fracturing is not separately
permitted, the drilling of the well that is later perforated and fractured is subject to the same rigorous
construction and casing standards as are all other types of wells.116
Disposal of hydraulic fracturing fluids. The RRC permits class 2 wells for the disposal of oil and
gas waste, including hydraulic fracturing flowback water and produced water.117
The RRC also authorizes
the various water recycling efforts, discussed in section IV.C, below.
Disclosure of hydraulic fracturing fluids. In the 2011 legislative session, Texas became one of
the first states to pass legislation requiring hydraulic fracturing operators to disclose to the public the
chemicals used in their operations. The bill, signed by Governor Perry on July 17, 2011, was codified at
section 91.851 of the Natural Resources Code.118
The bill required the RRC to promulgate rules to require
operators to complete forms detailing:
(1) the total amount of water used in the fracturing operation and
(2) each chemical ingredient used in the operation that is listed on the OSHA-required material
safety data sheet (―MSDS‖).119
Those forms must then be posted on a publicly available Internet website.120
The operator must
additionally provide to the RRC a list of all other chemical ingredients that were used for the purpose of
fracturing the well. Those additional ingredients will also be made available on a publicly-available
website. However, the bill prevented the RRC from requiring that the ingredients be identified based on
the additive in which they are found or that the operator provide the concentration of such ingredients.
The bill also required the RRC to prescribe a process by which operators ―may withhold and declare
certain information as a trade secret.‖121
Persons desiring to challenge a claim of entitlement to trade secret
protection must file a challenge within two years of the operator‘s filing a completion report with regards to
the relevant well.122
The class of people entitled to challenge a claim of trade secret status is limited to the
landowner on whose property the well is located, an adjacent landowner, and a department or agency of the
state with jurisdiction over a matter to which the claimed trade secret is relevant.123
The RRC published its proposed rules to implement the hydraulic fracturing disclosure bill on
September 9, 2011124
and adopted its final rule on December 13, 2010.125
The final rule became effective
on January 2, 2012.126
Many aspects of the process were set in the detailed legislation. However, some
aspects are addressed by rule. One rule-based requirement is the procedure by which to claim trade secret
status. The proposed procedure differs from ordinary trade secret litigation at the agency level in that the
operator need not submit the information to the RRC until the Attorney General or a court has declared that
the information is not trade secret. Another rule-based provision defines the class of persons entitled to
challenge trade secret status, as the person on whose property the well-head is located, the adjacent
property owner, and any relevant state agency
116
16 TEX. ADMIN. CODE §§ 3.7-3.8; 3.13; 316-319 (2012).
117 16 TEX. ADMIN. CODE § 3.9 (2012).
118 Act of May 29, 2011, 82
nd Leg., R.S., H.B. 3328 (to be codified at TEX. NAT. RES. CODE ANN. § 91.851).
119 Id.
120 Id.
121 Id.
122 Id.
123 Id.
124 36 Tex. Reg. 5765 (Sept. 9, 2011).
125 36 Tex. Reg. 9307 (Dec. 30, 2011).
126 Id.
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Other states have already promulgated laws requiring the disclosure of fracturing fluids: Montana
passed regulations that were effective on August 26, 2011,127
and Colorado passed its regulations on
December 13, 2011.128
Enforcement. The Railroad Commission enforces Chapter 91 of the Natural Resources Code, and
any rule, order, or permit adopted under that chapter. The RRC is authorized to seek and obtain civil
penalties,129
injunctive relief,130
and administrative penalties131
in certain situations.
Section 91.101 gives the Railroad Commission the power and duty to prevent pollution of state
waters.132
The Railroad Commission may also impose criminal penalties on a person who willfully or with
criminal negligence violates Section 91.101 or a rule, order, or permit issued under that section. Any such
violation is punishable by a fine of up to $10,000 a day for each day a violation is committed.133
2. The Texas Commission on Environmental Quality.
The TCEQ has no regulatory authority over water affected by oil and gas activity, so therefore no
regulatory authority over any water quality aspects of hydraulic fracturing. Instead, as discussed in section
VI.B below, the TCEQ regulates air quality, including air affected by oil and gas operations.
3. The University of Texas’s Energy Institute Report.
On February 15, 2012, UT‘s Energy Institute released its 414 page, comprehensive report (the
―Report‖) on hydraulic fracturing. The Report is based on a scientific investigation of alleged groundwater
contamination caused by hydraulic fracturing.134
The Report‘s key findings related to groundwater
contamination include:
The researchers of the Report ―found no evidence of aquifer contamination from hydraulic
fracturing chemicals in the subsurface by fracturing operations, and observed no leakage
from hydraulic fracturing at depth.‖ 135
Reports of groundwater contamination are often found with other conventional oil and gas
wells, due to failure of well-bore casing and cementing, and are not unique to hydraulic
fracturing.136
Methane found in water wells is most likely the result to natural sources, and was likely
present before hydraulic fracturing operations.137
Surface spills of hydraulic fracturing fluids poses a greater risk to groundwater
contamination than the actual hydraulic fracturing.138
127
http://dnrc.mt.gov/News/Releases/2011/September1.asp
128 http://www.denverpost.com/breakingnews/ci_18601083; http://cogcc.state.co.us/ (visited January 16, 2012).
129 See TEX. NAT. RES. CODE ANN. § 91.003(a) (West 2011). See also TEX. NAT. RES. CODE § 81.0531 - 81.0534 (West 2011).
130 See TEX. NAT. RES. CODE ANN. § 81.054 (West 2011).
131 See TEX. NAT. RES. CODE ANN. § 85.3855 (West 2011).
132 TEX. NAT. RES. CODE ANN. § 91.002(a) (West 2011).
133 TEX. NAT. RES. CODE ANN. § 91.002(b) (West 2011).
134 Charles G. Groat and Thomas W. Grimshaw, The University of Texas at Austin Energy Institute (UTEI), Fact-Based
Regulation for Environmental Protection in Shale Gas Development (Feb. 2012),
http://energy.utexas.edu/images/ei_shale_gas_regulation120215.pdf. Additionally, a summary of the Report‘s findings can be
found at, http://energy.utexas.edu/images/ei_shale_gas_reg_summary1202.pdf.
135 UTEI, Seperating Fact from Fiction in Shale Gas Development 4 (Feb. 2012),
http://energy.utexas.edu/images/ei_shale_gas_reg_booklet1202.pdf (summarizing the key findings in their own Report).
136 Id.
137 Id.
138 Id.
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UT‘s Energy Institute plans two related projects:
The Institute will evaluate claims of groundwater contamination within the Barnett Shale in
North Texas, in particular. The research will examine various aspects of shale gas
development, including site preparation, drilling, production, and the handling and disposal
of flow-back water.139
The Institute will conduct a detailed field and laboratory investigation of whether
hydrological connectivity exists between shallow groundwater aquifers and fractures created
by hydraulic fracturing during shale gas development.140
C. Local water quality regulation.
1. Municipalities.
In the face of growing public concern over oil and gas drilling practices, cities are passing stricter
regulations on the industry. Some cities in the Marcellus Shale area have even gone so far as to ban certain
drilling techniques all together.141
As cities become more active, their power to regulate oil and gas drilling
activities has become an issue. In Texas, home rule cities generally have broad authority to adopt
ordinances ―for the good government, peace or order of the municipality or for the trade and commerce of
the municipality.‖142
An ordinance of a home rule city is presumed valid. However, a court will overturn
an ordinance that is so unreasonable and arbitrary that it is a clear abuse of discretion.143
Further, general
law cities – Types A, B, or C – must have explicit statutory authority to act.144
Finally, specific statutory
provisions, or total preemption, can limit the authority of a Texas city to pass particular ordinances.145
A number of Texas cities and towns, including Arlington, Bartonville, Bedford, Clebourne,
Decatur, Denton, DISH, Flower Mound, Fort Worth, Hurst, and Weatherford, have recently drafted
ordinances that impose varying requirements, of varying stringencies, on oil and gas drilling in general, and
fracturing in particular. Below, we consider ordinances of two cities, the City of Fort Worth and the City
of Hurst.
a. City of Fort Worth.
The Fort Worth Municipal Code (―Code‖) requires an operator to obtain a city permit for the
construction of fresh water fracture ponds, and to meet requirements regulating the pond liner, enclosure
fencing, maintenance procedures, and the existence of oil or gas waste-products.146
The Code also
prohibits the drilling of a well within 200 feet of an existing freshwater well without first obtaining a
139
Id.
140 Id.
141 See, e.g., Associated Press, Industry Pushes Back on W. Va. City Drilling Bans, WALL ST. J., Aug. 8, 2011,
http://online.wsj.com/article/APb11d765f1c3b4b17bb3a4a8b0873777b.html.
142 TEX. LOCAL GOV‘T CODE ANN. § 51.001 (West 2008).
143 See City of Brookside Village v. Comeau, 633 S.W.2d 790, 796 (Tex. 1982); Barnett v. City of Plainview, 848 S.W.2d 334,
338 (Tex. App.—Amarillo 1993, no writ). See also Laura Mueller et al., Texas Municipal League, Alphabet Soup: Types of
Texas Cities, available at
http://www.texascityattorneys.org/2011speakerpapers/rileyfletcher/typescities-update2009-CDAdams.pdf
144 Mayhew v. Town of Sunnyvale, 774 S.W.2d 284, 294 (Tex App.–Dallas 1989, writ denied); Hope v. City of Laguna Vista,
721 S.W.2d 463, 463–64 (Tex. Civ. App.—Corpus Christi 1986, writ ref'd n.r.e.); Municipal Gas Co. v. City of Sherman, 89
S.W.2d 436, 439 (Tex. Civ. App.–Dallas 1935), aff‘d 89 S.W.2d 436 (Tex. 1939).
145 Dallas Merch's and Concessionaire's Ass'n v. City of Dallas, 852 S.W.2d 489, 491 (Tex. 1993). See also City of Houston v.
Bates, No. 14-10-00542-CV, 2011 WL 3585612, 7 (Tex. App.–Houston [14th Dist.] Aug. 16, 2011, pet. filed) (holding
ordinance preempted by state law); Seber v. Union Pacific R. Co., 350 S.W.3d 640 (Tex. App.–Houston [14th
Dist.] 2011, no
pet.) (holding ordinance preempted by federal law).
146 § 15-42(A)17.
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waiver from the water well‘s property owner.147
A reclamation plan, required of all operators submitting a
gas well permit application, must include measures to ensure the protection ―of the quantity and quality of
surface and groundwater system . . . [and] the cleaning up of polluted surface and ground water.‖148
On April 10, 2012, the City of Fort Worth permanently banned all saltwater disposal wells inside
the city limits.
b. City of Hurst.
The City of Hurst passed a new ordinance, No. 2161, on February 22, 2011, in response to the
―dramatic increase in gas well drilling‖ in the city. Ordinance No. 2161 requires any gas well to obtain a
specific use permit. Among other things, Ordinance No. 2161 requires that:
The operator use non-radioactive tagging additives in fracturing fluids.149
The operator allow the City to take an on-site sample of fracture fluid.150
Only ―environmentally benign, chemically inert, water-based‖ (i.e. ―green‖) drilling fluids be used,
and that only ―non-toxic substances‖ be used in any hydraulic fracturing.
Water quality be tested (1) before fracturing, (2) after fracturing, and (3) annually.
The operator must provide a pre-drilling and post-drilling soil report.
The operator must submit a plan for controlling all soil contamination.
2. Other local governments, including groundwater conservation districts.
Local governments other than cities may also regulate water quality. Under Chapter 36 of the
Texas Water Code, a groundwater conservation district (―GCD‖) is authorized to make and enforce rules to
provide for ―conserving, preserving, protecting, and recharging of the groundwater or of a groundwater
reservoir or its subdivisions in order to . . . prevent degradation of water quality. . . .‖ Groundwater
conservation districts have the authority to enforce Chapter 36 and its rules ―by injunction, mandatory
injunction, or other appropriate remedy in a court of competent jurisdiction.‖151
In addition, GCDs by rule
may ―set reasonable civil penalties against any person for breach of any rule of the district.‖152
Penalties
are authorized at an amount of up to $10,000 per day per violation, and each day of a continuing violation
is a separate violation.153
Practice Note: Regulation of Groundwater
Currently, there are 96 confirmed and 3 unconfirmed groundwater conservation
districts (―GCDs‖) in 176 Texas counties, covering approximately 69.4% of the
state. The GCD is charged with protecting both groundwater quality and
groundwater supply.
A typical provision for a smaller groundwater conservation district might be:
147
§ 15-42(A)18.
148 § 15-45(D).
149 Ordinance No. 2161, § 12-376(e)(5).
150 Id.
151 TEX. WATER CODE ANN. § 36.102(a) (West 2008).
152 Id. § 36.102(b).
153 Id.
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No person shall pollute or harmfully alter the character of the groundwater within the
District by causing or allowing the introduction of pollutants or other deleterious matter
from another stratum, from the surface, or from the operation of a well.154
Rules for larger groundwater control districts, such as the Edwards Aquifer Authority, are
considerably more complex, and may impose spill reporting requirements, hazardous substances
registration and requirements, and conditions and limitations on aboveground and underground storage
tanks.155
The GCD‘s power to regulate, though, is restricted by section 36.117(l) of the Texas Water Code,
which states (in part) that chapter 36 – the chapter that authorizes GCDs to regulate – does not apply to
―production or injection wells drilled for oil, gas . . . or for injection of gas, saltwater, or other fluids, under
permits issued Railroad Commission . . . .‖156
GCDs also have the power to regulate and restrict the use of groundwater, a power that is discussed
in detail below.
III. PROTECTING PUBLIC HEALTH AND THE ENVIRONMENT: TSCA
The Toxic Substances Control Act of 1976 (―TSCA‖) authorizes EPA to require reporting, record-
keeping and testing requirements, and to impose restrictions relating to chemical substances or mixtures.157
On November 23, 2011, EPA partially granted a petition under Section 8(a) and 8(d) of the TSCA, stating
that ―there is value in initiating a proposed rulemaking process using TSCA authorities to obtain data on
chemical substances and mixtures used in hydraulic fracturing.‖ 158
To do so, EPA will convene
stakeholder groups to develop an approach to minimize reporting burdens and costs. EPA denied the
petitioner‘s request that EPA use TSCA to collect information on chemicals used in other aspects of the
exploration and production sector.
IV. PRESERVING WATER RESOURCES.
A. Water supply.
Hydraulic fracturing is heavily water-intensive. It takes an estimated 3.3 to 3.5 million gallons to
fracture a well in the Barnett Shale.159
Different sources have estimated the water needed to fracture a well
in the Eagle Ford as anywhere from 6.1 to 13 million gallons.160
Barnett Shale. In January 2007, the Texas Water Development Board (―TWDB‖) published a
study of water usage in a 19-county area in North Texas that includes the Barnett Shale development area
154
Rules of the Kinney County Groundwater Conservation District, Rule. 4.01B (rules approved October 29, 2009).
155 See, e.g., Edwards Aquifer Authority Rules (rev. May 13, 2011).
156 TEX. WATER CODE ANN. § 36.117(l) (West 2008).
157 See, e.g., 15 U.S.C. 2601 et set.
158 November 23, 2011 Letter from Stephen A. Owens of EPA to Deborah Goldberg of Earthjustice. See also 16 U.S.C.A. §
1681 to 1687.
http://www.epa.gov/oppt/chemtest/pubs/EPA_Letter_to_Earthjustice_on_TSCA_Petition.pdf
159 See Scott W. Tinker, Director, Jackson School of Geosciences, Current And Projected Water Use in the Texas Mining and Oil
and Gas Industry, Prepared for the Texas Water Development Board, (June 2011), at page 169; Jay Ewing, Taking a Proactive
Approach to Water Recycling in the Barnett Shale, Fort Worth Business Press Barnett Shale Symposium, February 29, 2008,
available online at
http://www.barnettshalenews.com/documents/EwingPres.pdf
160 Compare Fact Sheet, Water Use in Eagle Ford Deep Shale Exploration, Chesapeake Energy, with Joe Carroll, Worst Drought
in More Than a Century Strikes Texas Oil Boom, June 13, 2011 (http://www.bloomberg.com/news/2011-06-13/worst-drought-
in-more-than-a-century-threatens-texas-oil-natural-gas-boom.html)
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(the ―2007 TWDB Report‖). This report can be found at
http://rio.twdb.state.tx.us/RWPG/rpgm_rpts/0604830613_BarnetShale.pdf. 161
The 2007 TWDB Report states that approximately 89% of the total water supply for the region for
all purposes is provided by surface water sources and 11% by groundwater. The TWDB report estimates
that, out of the total water used in 2005 for Barnett Shale development, approximately 60 percent was
groundwater from the Trinity and Woodbine Aquifers. The report estimated that groundwater used for
Barnett Shale development accounted for approximately 3 percent of all groundwater used in the entire
study area in 2005. However, the ratio of groundwater to surface water used in specific areas varies
greatly. In general, groundwater provides for a greater percent of total supply in rural counties and a
smaller proportion of total use in more urban counties. Therefore, increased groundwater use for any
purpose will have a greater impact on rural areas, such as the Eagle Ford.
Eagle Ford Shale. Water has always been a precious resource in the Eagle Ford Shale. The 2011
drought has had a tremendous impact. The Railroad Commission, at the direction of Commissioner Porter,
has established the Eagle Ford Task Force.162
The 24-member task force has stated that its main purpose is
to serve as a forum for dialogue, so that task force members can bring issues and concerns from their
constituents to the table and work toward solutions. The group also agreed to meet monthly and to provide
recommendations on the top issues facing the region, including water supply and usage. However, neither
the Task Force, nor the Railroad Commission, regulate water usage or supply, so the recommendations will
be non-binding.
B. Water usage.
As water-intensive as hydraulic fracturing is, it is a relatively small percentage of total water
usage.163
The 2007 TWDB Report estimated that in 2005, Barnett Shale usage was approximately 0.5% of
all other uses, and predicted that during peak Barnett Shale activity between 2010-2015, usage would rise
to 2% of all uses.164
A 2009 report commissioned by the Barnett Shale Education Council estimates that
water usage will be even lower, due to the downturn in drilling. 165
Similarly, a 2011 TWDB estimated that
hydraulic fracturing and mining combined use less than 1% of water statewide, although there could be
local variations.166
Regardless, water used for fracturing must still compete with other uses.
1. Regulation of surface water rights.
Under Texas law, all surface water is held in trust by the state and is managed by TCEQ for the
public good.167
An oil and gas operator can obtain a temporary water rights permit in order to meet its
needs.168
It may also purchase water directly, usually from a municipality.169
161
―Northern Trinity/Woodbine Aquifer Groundwater Availability Model, Assessment of Groundwater Use in the Northern
Trinity Aquifer Due to Urban Growth and Barnett Shale Development,‖
162 http://www.rrc.state.tx.us/commissioners/porter/press/082511.php
163 http://www.rrc.state.tx.us/barnettshale/wateruse_barnettshale.php; see also R.W. Harden & Associates, Inc., prepared for the
Texas Water Development Board, Northern Trinity/Woodbine GAM Assessment of Groundwater Use in the Northern Trinity
Aquifer Due to Urban Growth and Barnett Shale Development (January 2007).
164 L. Peter Galusky, Jr., Texerra, Fort Worth Basin/Barnett Shale Natural Gas Play: An Assessment of Present and Projected
Fresh Water Use 4 (2007), http://www.texerra.com/Barnetthydro.pdf.
165 Id.
166 2012 State Water Plan, Texas Water Development Board, § 3.2.4; Scott W. Tinker, Director, Jackson School of Geosciences,
Current And Projected Water Use in the Texas Mining and Oil and Gas Industry, Prepared for the Texas Water Development
Board, June 2011.
167 TEX. WATER CODE § 11.0235 (West 2008).
168 TEX. WATER CODE ANN. § 11.138 (West 2008).
169 Galusky at 11.
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2. Regulation of groundwater rights.
a. Ownership of groundwater rights.
In Texas, the degree of private ownership of groundwater was unclear until recently. Despite the
assumption of many landowners that they own the water beneath their property in place, that was disputed.
The Texas Supreme Court, Edwards Aquifer Authority v. Day,170
settled the dispute by holding that of
groundwater is a vested property right to the water in place.171
Because of that, a landowner may have a
cause of action for a regulatory taking under the factors of Penn Central Transport Co. v. New York City.172
The Day decision is likely to affect many contracts under which surface owners have sold or leased the
groundwater under their property to third parties – and could affect the way shale gas producers obtain
water for fracturing activities.
Regardless of ownership, groundwater – like oil and gas – is subject to the ―rule of capture.‖173
In
the absence of regulation, landowners may pump as much water as they choose, without liability to
surrounding landowners who might claim that the pumping is depleting their wells.174
However, as with oil
and gas, a landowner may not waste groundwater.175
In addition, the Texas legislature clarified groundwater ownership in the last legislative session.
S.B. 332, effective September 1, 2011, amended section 36.002 of the Texas Water Code to provide:
(a) The legislature recognizes that a landowner owns the groundwater below the surface of
the landowner’s land as real property.
(b) The groundwater ownership and rights described by this section:
1. entitle the landowner, including a landowner‘s lessees, heirs, or assigns, to drill for
and produce the groundwater below the surface of real property, subject to
Subsection (d), without causing waste or malicious drainage of other property or
negligently causing subsidence, but does not entitle a landowner, including a
landowner‘s lessees, heirs, or assigns, to the right to capture a specific amount of
groundwater below the surface of that landowner‘s land; and
2. do not affect the existence of common law defenses or other defenses to liability
under the rule of capture.
(c) Nothing in this code shall be construed as granting the authority to deprive or divest a
landowner, including a landowner‘s lessees, heirs, or assigns, of the groundwater
ownership and rights described by this section.176
S.B. 332 also amended section 362.101 to provide that in adopting its rules, a groundwater conservation
district shall, among other things, consider the groundwater ownership and rights described by section
36.002.
b. Regulation of groundwater usage: the groundwater conservation district.
Regardless of ownership, groundwater rights are subject to regulation and control by the state.177
Various types of groundwater control districts have existed since the mid-1900s. More recently, the Texas
170
___ S.W.3d ___, No. 08-0964, 2012 WL 592729 (Tex. Feb. 24, 2012).
171 Kelly Hart & Hallman LLP filed an amicus brief on behalf of a client in support of Day/McDaniel.
172 438 U.S. 104 (1978).
173 Houston & Texas Cent. R.R. Co. v. East, 81 S.W. 279, 280 (Tex. 1904).
174 Id.
175 Sipriano v. Great Spring Waters of America, Inc., 1 S.W.3d 75, 76 (Tex. 1999).
176 TEX. WATER CODE ANN. § 36.002 (West Supp. 2011) (emphasis added).
177 See generally TEX. WATER CODE Chapter 36.
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Legislature declared that groundwater conservation districts were the State's preferred method of
groundwater management.178
Three levels of law apply in groundwater control districts:
(i) chapter 36 of the Texas Water Code, which applies generally to all groundwater -districts
(unless otherwise specified in legislation particular to district),
(ii) any special legislation that was promulgated for the particular district, which usually
prevails over the general provisions of chapter 36, and
(iii) any rules the GCD promulgates under its statutory authority.
Under Chapter 36 of the Texas Water Code, GCDs are authorized and required to conserve,
preserve, protect, recharge, and prevent waste of groundwater resources within their boundaries.179
As
discussed above, GCDs may promulgate rules to achieve their purposes and may enforce their rules by fine,
injunction, or other remedy.180
As discussed above, Chapter 36 does not apply to production or injection wells drilled for oil, gas,
sulphur, uranium, or brine, or for core tests, or for injection of gas, saltwater, or other fluids, under permits
issued by the Railroad Commission. 181
However, chapter 36 does apply to water wells used in oil and gas
production, including injection water source wells.
Section 36.117 exempts several classes of wells from permitting requirements. Section 36.117(b)
provides that a district may not require any permit for:
the drilling of a water well,
used solely to supply water for a rig that is actively engaged in drilling or exploration
operations for an oil or gas well permitted by the Railroad Commission of Texas,
provided that the person holding the permit is responsible for drilling and operating the
water well and the well is located on the same lease or field associated with the drilling
rig.182
The Railroad Commission refers to this as an exemption for ―temporary rig supply wells.‖183
The
Railroad Commission interprets the phrase ―a rig that is actively engaged in drilling or exploration
operations for an oil or gas well permitted by the commission‖ to mean a ―drilling rig‖ or a ―workover rig‖
and interprets ―exploration operations‖ to include well completion and workover, including hydraulic
fracturing operations.184
However, a rig supply water well is still subject to a number of GCD regulations.
The rig supply well must be registered in accordance with GCD rules.185
The rig supply well must be equipped and maintained to conform to the GCD‘s rules
requiring installation of casing, pipe, and fittings to prevent the escape of ground water from
178
TEX. WATER CODE ANN. § 36.0015 (West 2008).
179 TEX. WATER CODE ANN. § 36.101 (West Supp. 2011); see also http://www.tgpc.state.tx.us/GWManagement.htm
180 TEX. WATER CODE ANN. § 36.101 (West Supp. 2011).
181 TEX. WATER CODE ANN. § 36.117(l) (West Supp. 2011).
182 TEX. WATER CODE ANN. § 36.117(b)(2) (West Supp. 2011).
183 www.rrc.state.tx.us/barnettshale/wateruse.php
184 Id.
185 TEX. WATER CODE ANN. § 36.117(h)(1) (West Supp. 2011).
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a groundwater reservoir to any reservoir not containing ground water and to prevent the
pollution or harmful alteration of the character of the water in any groundwater reservoir. 186
The driller of a rig supply well must file the drilling log with the GCD.187
The district may require the owner or operator of the well to keep records and to report the
production and use of groundwater.188
In addition, Section 36.117(g) provides that a district may not deny an application for a permit to
drill and produce water for hydrocarbon production activities if the application meets all applicable district
rules.189
Section 36.117(g), in the Railroad Commission‘s view, applies to injection supply wells used for
secondary recovery operations.190
In summary, in the absence of special provisions in its enabling legislation, a GCD can require that
the operator of a permit-exempt well, such as a temporary rig supply well:191
Register the well.
Comply with any technical requirements for the installation of casing, pipe, and fittings to
prevent the escape of groundwater.
Comply with spacing requirements.
Report groundwater withdrawals.
Obtain a permit when no longer used solely for drilling or exploration.
C. Water recycling.
1. In general.
The water used for hydraulic fracturing is generally fresh water, either surface or groundwater.192
After injection into a formation, the fresh water becomes unusable due to its high salt content. Produced
water – the water that exists in a formation before fracturing occurs – is unusable for the same reason.
However, the Railroad Commission has reported that flow-back water and produced water from the Barnett
Shale and the Eagle Ford do not contain radionuclides in excess of regulatory levels.193
The RRC has approved several recycling projects in the Barnett Shale to reduce the amount of fresh
water used in development activities.194
According to the RRC‘s website, the following authorizations
have been issued by the Commission and are currently active:195
In October 2006, the RRC authorized Fountain Quail Water Management to operate a
commercial mobile recycling unit that allows the reuse of approximately 80 percent of the
flow-back fluids processed through its unit. This recycling process involves on-site
distillation units that apply heat to separate out the brine. The process results in a small
186
Act of April 27, 2011, 82nd
Leg., R.S., S.B. 692 (to be codified at TEX. WATER CODE ANN. § 36.117(h)).
187 TEX. WATER CODE ANN. § 36.117(i) (West Supp. 2011).
188 TEX. WATER CODE ANN. §36.111 (West 2008).
189 TEX. WATER CODE ANN. § 36.117(g) (West Supp. 2011).
190 www.rrc.state.tx.us/barnettshale/wateruse.php.
191 This paper takes no position on the GCD‘s ability to regulate production, a much-debated issue.
192 Id.
193http://www.texastribune.org/texas-energy/energy/does-gas-drilling-put-radiation-in-texas-water/ (visited on September 16,
2011).
194 See, e.g. http://www.rrc.state.tx.us/barnettshale/wateruse_barnettshale.php (visited on September 10, 2011).
195 Id.
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volume of concentrated brine that is disposed of in a disposal well, and a large volume of
distilled water that can be reused to fracture additional wells.196
In November 2009, the RRC authorized Fountain Quail Water Management to build and
operate a commercial stationary recycling facility in Parker County. The stationary facility
will use the same technology as Fountain Quail‘s mobile water recycling process. Like
Fountain Quail‘s mobile recycling units, the stationary facility will allow for reuse of
approximately 80 percent of the fluids it processes. Fountain Quail‘s plans indicated that the
stationary facility would initially be able to process 7,000 barrels per day of flow-back fluid,
and an additional 7,000 barrels per day of produced water. The stationary facility would
ultimately be able to process 15,000 barrels per day of flow-back fluid, and an additional
15,000 barrels of produced water.197
In June 2011, Fountain Quail issued a press release announcing that it had recycled more than 14
million barrels of oil and gas wastewater.198
A very large percentage of that has been on behalf of
Devon Energy Corp.199
Fountain Quail also announced that it will be expanding into the Eagle Ford
Shale play.200
In March 2007, the RRC authorized the Barnett Shale Water Conservation Company to
dispose of produced water and drilling fluids in the City of Fort Worth‘s wastewater system,
provided that the Texas Commission on Environmental Quality and the City of Fort Worth
also approved the disposal.
In July 2009, the RRC authorized Brazos Bend Energy Services to dispose of produced
water and drilling fluids in the City of Fort Worth‘s wastewater system, provided that the
TCEQ and the City of Fort Worth also approved the disposal.
Treating produced water and drilling fluids in a municipal water treatment system rather than disposing of
these fluids in a disposal well allows the water to remain in the hydrologic cycle.
A recent study prepared by UT‘s Bureau of Economic Geology for the Texas Water Development
Board (―BEG Report‖) concluded that approximately 6% of the water in the Barnett Shale has been
recycled.201
By contrast, almost none of the Haynesville water is recycled because there is little of it and it
is of poor quality.202
Ultimately, the BEG report concludes that 20% of the water used for hydraulic
fracturing will be used again. The report also predicts that water used for hydraulic fracturing will increase
from the current 37,000 AF in total to a peak of 120,0000 AF in total by 2020-2030.203
Appendix 1, part of
the BEG Report, summarizes projected water use in the Barnett, Haynesville, Eagle Ford, Bossier,
Haynesville West, and Pearsall shales.204
The amounts are 853, 426, 1516, 191, 36, 223 and 270 thousand
acre/feet, respectively. Ironically, the greatest predicted water usage is projected in the Eagle Ford, which
has less water to spare.
196
Id.
197 Id.
198 http://www.fountainquail.com/assets/Aqua-Pure_Expands_Eagle_Ford.pdf
199 http://www.fountainquail.com/about/partners/partners.html.
200 Id.
201 Scott W. Tinker, Director, Jackson School of Geosciences, Current And Projected Water Use in the Texas Mining and Oil
and Gas Industry, Prepared for the Texas Water Development Board, June 2011, at page 186.
202 Id.
203 Id. at 187.
204 Id., Table 50.
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2. Regulation of stationary and mobile recycling units.
The RRC regulates commercial recycling. Its regulatory program, in chapter 4 of Title 16 of the
Texas Administrative Code, applies to both mobile and stationary commercial recycling facilities. A
commercial recycling facility is one in which the owner or operator
(1) receives compensation form others for the storage, handling, treatment and recycling of oil
and gas wastes, and
(2) the primary business purpose of the facility is to provide these services for compensation.205
A person seeking to operate a commercial recycling facility must obtain a permit.206
In addition to
basic operational information, the applicant may be required to furnish engineering, geological or other
information to show that the issuance of the permit will not result in the waste of oil, gas or geothermal
resources, the pollution of surface or subsurface water, or a threat to the public health or safety. The
application for a stationary commercial recycling facility must include siting information,207
real property
information,208
design and construction information,209
operating information,210
monitoring information,211
and closure information.212
3. Use of reused or reclaimed water for fracturing.
Under 30 TAC Chapter 210, reclaimed water from municipal or industrial sources may be used for
other purposes, theoretically even for hydraulic fracturing. After use, the water would be oil and gas waste,
which is generally disposed of by deep well injection under RRC rule 3.9.
4. Future developments.
On November 21, 2010, Commissioner Jones directed Railroad Commission staff to begin
analyzing the Commission‘s rules on water recycling.213
It is anticipated that the RRC may add special
rules for the recycling of flowback water from hydraulic fracturing. Also, the new frack fluid disclosure
rule, 16 Texas Administrative Code § 3.29, requires that the operator disclose the total volume of water
used in the hydraulic fracturing treatment of the well, or the type and total volume of other base fluid
used.214
This will enable the state, for the first time, to keep track of the volumes of water used in hydraulic
fracturing.
V. PRESERVING PROPERTY – INDUCED SEISMICITY.
Seismic activity has been associated with both hydraulic fracturing and the disposal of water from
hydraulic fracturing.215
It has similarly been associated with oil and gas production and geothermal and
carbon sequestration.216
The activity is often described as microseismic and creates very small movements
that are rarely felt.
205
16 TEX. ADMIN. CODE § 4.204(3) (2012).
206 16 TEX. ADMIN. CODE § 4.203(a) (2012).
207 Id. at 4.207.
208 Id. at 4.03(a).
209 Id. at 4.209.
210 Id. at 4.210.
211 Id. at 4.211.
212 Id. at 4.212.
213 http://www.rrc.state.tx.us/commissioners/jones/press/112311.php (visited on Jan. 15, 2010)
214 16 TEX. ADMIN. CODE 3.29(c)(2)(A)(viii) (2012).
215 http://esd.lbl.gov/research/projects/induced_seismicity/oil&gas/ (visited on Jan. 30, 2012).
216 http://esd.lbl.gov/research/projects/induced_seismicity/ (visited on Jan. 30, 2012).
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The processes involved in hydraulic fracturing itself are distinct from those involved in disposal by
injection. Any earthquakes caused by hydraulic fracturing are generally imperceptible because the process
takes place in relatively weak, shallow shales that crack before building up much strain.217
Although it is
very rare, waste injection wells can cause quakes that are potentially more powerful because more fluid is
pumped underground for longer periods.218
A. Quakes in Youngstown, Ohio.
In March 2012, the State of Ohio‘s Department of Natural Resources issued a preliminary report
concluding that a series of 12 earthquakes, culminating in a 4.0 magnitude earthquake that occurred in
Youngstown, Ohio on December 31, 2011, was caused by the injection of wastewater from oil and gas
production.219
The earthquake did not cause any damage. At that point, though, the state of Ohio asked
the operator to cease disposal and put a moratorium on injection wells within five miles of the well until it
had time to study the issue.
ODNR‘s preliminary report concluded the earthquakes were almost certainly cased by the
injection.220
The earthquakes did not begin until injection started; the quakes were cloistered around the
well bore; and a new fault was discovered in the bedrock where the wastewater was being injected. The
state promulgated new regulations, including the following:
prohibiting any new wells into the Precambrian basement rock formation;
requiring operators to submit extensive geological data before drilling;
implementing state-of-the-art pressure and volume monitoring devices with automatic shut-
off switches and electronic data recorders;
require that brine haulers install electronic transponders to ensure ―cradle to grave‖
monitoring of shipments.
B. USGS study.
In April 2012, USGS scientists released the abstract of a study describing a rash of earthquakes in
the middle of the country that they linked to the underground injection of waste brine from oil and gas
production.221
The study stated there had been a six-fold increase in earthquakes per year beginning in
2001. As of the date of this writing, the full paper has not been released.222
C. National Academy of Sciences study of induced seismicity.
On June 15, 2012, a National Academy of Sciences (―NAS‖) panel released a prepublication
version of its study of induced seismicity, Induced Seismicity Potential in Energy Technologies (―Induced
Seismicity Report‖).223
The study focused on areas of interest related to carbon capture and sequestration
(―CCS‖), enhanced geothermal systems, enhanced oil recovery, as well as production from gas shales. The
Induced Seismicity Report concluded that:
217
http://blogs.ei.columbia.edu/2012/01/06/seismologists-link-ohio-earthquakes-to-waste-disposal-wells/ (visited on January 18,
2012).
218 Id.
219 Preliminary Report on the Northstar 1 Class II Injection Well and the Seismic Events in the Youngstown, Ohio, Area, Ohio
Department of Natural Resources, March 2012 (hereinafter ―Preliminary Youngstown Report‖).
220 Preliminary Youngstown Report at 17.
221 W.L. Ellsworth, S.H. Hickman, A.L. Lleons, A. McGarr, A.J. Michael, J.L. Rubinstein, Are Seismicity Rate Changes in the
Midcontinent Natural or Manmade?, Seismological Society of America.
222 June 19, 2012 email from William L. Ellsworth to Amy Yawn.
223 Induced Seismicity Potential in Energy Technologies, National Research Council, The National Academies Press, 2012.
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(1) the process of hydraulic fracturing a well as presently implemented for shale gas recovery
does not pose a high risk for inducing felt seismic events;
(2) injection for disposal of waste water derived from energy technologies into the subsurface
does pose some risk for induced seismicity, but very few events have been documented over
the past several decades relative to the large number of disposal wells in operation; and
(3) CCS, due to the large net volumes of injected fluids, may have potential for inducing larger
seismic events.
Among others, the Induced Seismicity Report proposed the following improvements:
1. Reduce data gaps.
Collect, categorize and evaluate data.
Research ways to measure in situ stress non-destructively.
2. Improve risk assessment.
A detailed methodology should be developed for quantitative, probabilistic hazard
assessments of induced seismicity risk. The goal in developing this methodology would be
to:
o make assessments before operations begin in areas with a known history of felt
seismicity;
o update assessments in response to observed induced seismicity.
Data related to fluid injection (well location coordinates, injection depths, injection volumes
and pressures, time frames) should be collected by state and federal regulatory authorities in
a common format and made publicly accessible (through a coordinating body such as the
USGS).
In areas of high-density of structures and population, regulatory agencies should consider
requiring that data to facilitate fault identification for hazard and risk analysis be collected
and analyzed before energy operations are initiated.
2. Institute best practices.
Protocols for best practice should be developed for each of the energy technologies
(secondary recovery and EOR for conventional oil and gas production, shale gas production,
CCS) by experts in each field, in coordination with permitting agencies.
The protocols should be applied to:
o the permitting of operations where state agencies have identified areas of high
potential for induced seismicity; or
o an existing operation that is suspected to have caused an induced seismic event of
significant concern to public health and safety.
3. Coordinate and fund appropriate agencies. Relevant agencies – including EPA, USGS, and land
management agencies, and possibly DOE, and state agencies with authority and relevant expertise – should
develop coordinated mechanisms to address induced seismic events. Also, funds would have to be
appropriated to fund that activity.
VI. PRESERVING AIR QUALITY.
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A. Federal air quality regulation.
1. Current regulations.
EPA‘s existing New Source Performing Standards (―NSPS‖) for Volatile Organic Compounds
(―VOCs‖) were issued in 1985. The existing standards address only VOC leak detection and repair at new
and modified natural gas process processing plants.
2. Proposed and final regulations.
a. Overview of proposal.
In August 2011, EPA proposed a suite of what it believes to be ―highly cost effective‖ regulations
that it said will reduce emissions from the oil and natural gas industry, while allowing continued,
responsible growth in U.S. oil and natural gas production.224
The proposed rules would rely on
technologies and best practices that are in use today to reduce emissions of smog-forming volatile organic
compounds (―VOCs‖).225
The proposal included the first federal air standards for wells that are hydraulically fractured, along
with requirements for several other sources of pollution in the oil and gas industry that currently are not
regulated at the federal level.
The proposal included the review of four rules for the oil and natural gas industry:
(1) a new source performance standard for VOCs;
(2) a new source performance standard for sulfur dioxide;
(3) an air toxics standard for oil and natural gas production; and
(4) an air toxics standard for natural gas transmission and storage.
EPA estimated the following combined annual emission reductions when the proposed amendments
are fully implemented:226
o VOCs – 540,000 tons, an industry-wide reduction of 25 percent;
o Methane – 3.4 million tons, which is equal to 65 million metric tons of carbon dioxide
equivalent (CO2e), a reduction of about 26 percent;227
o Air Toxics –38,000 tons, a reduction of nearly 30 percent.
The proposed standards would apply to any facility that commences construction, reconstruction or
modification after August 23, 2011. An operator must be in compliance by the date of publication of the
final rule in the Federal Register, or upon startup, whichever is later.
EPA ―issued‖ the 588-page final rule on April 17, 2012 (the ―Final Rule‖).228
However, as of this
writing, the Final Rule has yet to be published in the Federal Register. The ―Final Rule‖ (which could
theoretically change when it is published) incorporated changes made in response to voluminous comments
received.
224
http://www.epa.gov/airquality/oilandgas/
225 See, e.g., 76 Fed. Reg. 52738 (Aug. 23, 2011).
226 Id. at 52790.
227 Id. at 52745. Industry has disputed the accuracy of EPA‘s emission calculations. In particular, a recent study by API disputes
EPA‘s estimates of methane emissions. See, e.g. Terri Shires and Miriam Lev-On, Characterizing Pivotal Sources of Methane
Emissions from Unconventional Natural Gas Production, Summary and Analysis of API and ANGA Survey Responses (June 1,
2012).
228 http://www.epa.gov/airquality/oilandgas/actions.html (visited on June 16, 2012).
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b. New source performance standard for volatile organic compounds (“VOCs”).
EPA states that the oil and gas industry – including oil and gas production – is a ―significant‖
source of VOCs, which contribute to the formation of ground-level ozone, commonly known as smog.229
As discussed above, EPA‘s existing standards address only VOC leak detection and repair at new and
modified natural gas process processing plants, meaning other sources of VOC emissions in the oil and gas
industry are not currently subject to nationwide regulation.
The Final Rule requires VOC reductions from:
(1) Completions of new hydraulically fractured natural gas wells and re-completions of existing
natural gas wells that are fractured or refractured.
EPA estimates that gas well completions involving hydraulic fracturing vent 200 times more VOC
than completions not involving hydraulic fracturing.230
The emissions result from the backflow of the
fracture fluids and reservoir gas at the volume and velocity necessary to lift excess proppant and fluids to
the surface. EPA‘s final rule adopts two methods by which to limit VOC emissions at wells in developed
fields: green completions and flaring.
Green completions. ―Green completions‖ are also called ―reduced emissions completions
(―REC‖).‖ In a green completion, special equipment separates gas and liquid hydrocarbons from the
flowback that comes from the well as it is being prepared for production. The gas and hydrocarbons can
then be treated and sold.
Some states, such as Wyoming and Colorado, already require green completions, and a number of
companies are voluntarily using this process through EPA‘s Natural Gas STAR program.231
In addition,
green completions have been identified as an option for thousands of new gas wells in the Uintah Basin in
Utah to address concerns about air quality impacts associated with natural gas development in the region.
In Texas, Devon – although not required by law – uses green completions as often as possible.232
However,
Devon emphasizes that a green completion is possible only if the gathering system is in place.233
The green completion requirements do not apply to exploratory wells or delineation wells (those
used to define the borders of a natural gas reservoir), because they are not near a gathering line.234
The
Final Rule also excluded low pressure wells, primarily those in coal bed methane formations.235
Those
wells must use flaring to burn off their emissions, unless flaring is a safety hazard.
The Final Rule introduced a transition period – until January 1, 2015 – to ensure that green
completion equipment is broadly available. During the transition period, fractured wells must reduce their
emissions through flaring.236
Flaring. When gas cannot be collected, VOCs would be reduced through flaring.237
(2) Compressors
Compression is necessary to move natural gas along a pipeline. The Final Rule reduces VOC
emissions from two types of compressors: centrifugal compressors and reciprocating compressors.238
229
Id. at 52745.
230 Id. at 52757; see also Final Rule at p. 115.
231 Id. at 52757.
232 http://www.dvn.com/CorpResp/initiatives/Pages/GreenCompletions.aspx#terms?disclaimer=yes
233 Id.
234 Final Rule at p. 146.
235 Id.
236 Id. See also http://www.epa.gov/airquality/oilandgas/pdfs/20120417summarywellsites.pdf
237 Final Rule at P. 156.
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Compressors located at the wellhead or in the transmission, storage and distribution segments are not
covered by the Final Rule.239
(3) Pneumatic controllers
Pneumatic controllers are automated instruments used for maintaining a condition such as liquid
level, pressure, and temperature at wells, gas processing plants, compressor stations, among other locations.
These controllers often are powered by high-pressure natural gas. These gas-driven pneumatic controllers
may release natural gas (including VOCs and methane) with every valve movement, or continuously in
some cases. The Final Rule applies to a continuous bleed, natural gas-driven pneumatic controller with a
natural gas bleed rate greater than 6 schf for which construction commenced after August 23, 2011, located
(1) in the oil production segment between the wellhead and the point of custody transfer to an oil pipeline,
or (2) in the natural gas production segment, excluding natural gas processing plants, between the wellhead
and the point at which the gas enters the transmission and storage segment.240
(4) Condensate and crude oil storage tanks
Tanks with VOC emissions of 6 tpy or greater must reduce VOC emissions by 95 percent.241
(5) Natural gas processing plants
EPA‘s Final Rule amended the existing NSPS for natural gas processing plants to strengthen the
leak detection and repair requirements that apply to these plants to reduce VOC emissions.242
c. New Source Performance Standards for Sulfur Dioxide.
The new source performance standards for sulfur dioxide (SO2) emissions from natural gas
processing plants were issued in 1985. The Final rule requires affected facilities to reduce SO2 emissions
by recovering sulfur. The rule also increased the SO2 emission reduction standard from 99.8 percent to
99.9 percent for units with sulfur production orate of at least 5 long tons per day.243
d. Air Toxic Standards.
Air toxics are pollutants known to, or suspected of, causing cancer and other serious health effects.
The existing standards for air toxic for oil and natural gas production, and for natural gas transmission and
storage, were issued in 1999. The Clean Air Act requires EPA to conduct two types of reviews of air toxics
standards for major sources:
o A residual risk assessment: This assessment must be conducted one time, eight years after a standard is
issued, to determine what risks remain, and whether more protective standards are necessary to protect
public health.
238
Id. at p. 44.
239 Id.
240 Id.
241 Id.
242 Id. at 64.
243 Final Rule at 49.
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o A technology review: This review must be conducted every eight years after an air toxics standard is
issued to determine if better emission control practices, processes or technologies have become cost-
effective or available that would warrant revising the standard.244
i. Air toxics – oil and natural gas production.
EPA‘s residual risk review found that the current maximum individual cancer risk from oil and
natural gas production – is 40 in 1 million, which falls within a range EPA considers acceptable.245
However, the initial review also found that the level of emissions allowed under the existing air
toxics standard could drive that risk significantly higher – as high as 400 in 1 million, which EPA does not
consider acceptable.
To address this perceived risk, EPA proposed to remove the 1 ton per year benzene compliance
option for large glycol dehydrators which are used to remove excess water vapor from natural gas. Under
the proposed rule, all large dehydrators would have to reduce air toxics their emissions by 95 percent.246
However, after publication of its proposed rule, EPA discovered a number of mistakes in its calculations.
As a result, the Final Rule does not change the requirements for large glycol dehydrators.247
The Final Rule did establish MACT standards for small glycol dehydrators. A dehydrator would be
considered small if it has an annual average natural gas flow rate less than 85,000 standard cubic meters per
day, or actual annual average benzene emissions of less than 1 ton per year.248
ii. Air toxics – natural gas transmission and storage. EPA‘s technology review of the air toxic rules for natural gas transmission and storage did not
identify controls that warranted changes to the current standards. The EPA‘s residual risk review of these
standards estimates the current maximum individual cancer risk from air toxics emissions from natural gas
transmission and storage is 90 in 1 million, a risk level that EPA considers acceptable. Regardless, to
protect public health with an ―ample margin of safety,‖ EPA proposed changes to this standard that would
reduce the maximum risk level to 20 in 1 million.249
In the Final Rule for major sources, EPA established
MACT standards for small glycol dehydrators at major sources. Covered glycol dehydrators are those with
an actual annual average natural gas flow rate less than 283,000 scmd or actual average benzene emission
less than .9 Mg/yr. The units must meet unit-specific BTEX emission limits.250
3. The DOE’s criticisms of EPA’s rules.
The DOE‘s Second 90-Day Report, discussed above, addresses air emissions as well as water
quality issues. The Second 90-Day Report criticizes EPA‘s proposed rules because they do not directly
control methane emissions and because the NSPS rules do not cover existing shale gas sources except for
fractured or re-fractured existing gas wells. The Second 90-Day Report further complained that EPA has
compromised its ability to get accurate emissions data from the oil and gas sector under the Greenhouse
Gas Reporting Rule.251
The Final Rule does not address those criticisms.
B. State air quality regulation.
1. In general.
244
76 Fed. Reg. at 52740.
245 76 Fed. Reg. at 52788.
246 Proposed Subpart 0000.
247 Final Rule at 221.
248 Final Rule at 18.
249 76 Fed. Reg. at 52780.
250 Final Rule at 18.
251 Second 90-Day Report, p. 5.
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The Texas Commission on Environmental Quality (―TCEQ‖) regulates activities that affect air
quality, including oil and gas operations.252
Until recently, upstream facilities were lightly regulated,
relative to downstream facilities. That has changed.
Owners and operators of facilities must obtain authorization for air emissions from the facilities.253
Smaller facilities may qualify for a permit by rule (―PBR‖), but larger facilities must obtain a standard
permit or a new source review (―NSR‖) permit. Major sources of air emissions are also subject to Title V of
the federal Clean Air Act and must meet operating-permit requirements.
Only particular facilities may be included in a registration under either the new PBR or the non-rule
Air Quality Standard Permit. Those include:254
Fugitive components;
Separators;
Treatment and processing equipment;
Cooling towers and associated heat exchangers;
Gas recovery units;
Combustion units;
Storage tanks for crude oil, condensate, produced water fuels, treatment chemicals, slop and
sump oils and pressure tanks with liquefied petroleum gases;
Surface facilities associated with underground storage of gas or liquids;
Truck loading equipment;
Control equipment; and
Temporary facilities used for planned maintenance and temporary control devices for planned
start-ups and shutdowns.
The following are not authorized under either the new PBR or the non-rule Air Quality Standard
Permit:255
Sour water strippers or sulfur recovery units;
Carbon dioxide hot carbonates processing units;
Water injection facilities;
Liquefied petroleum gases, crude oil, or condensate transfer or loading into or from railcars,
ships, or barges;
Incinerators for solid waste destruction;
Remediation of petroleum contaminated water and soil; and
Cooling towers and heat exchangers with direct contact with gaseous or liquid process streams
containing VOC, H2S, halogens or halogen compounds, cyanide compounds, inorganic acids, or
acid gases.256
2. The new PBR.
The TCEQ adopted extensive new PBR requirements on January 26, 2011.257
The TCEQ‘s
response to comments, and the adopted rule, was published on February 18, 2011. Those requirements
have rewritten the previous PBR, section 106.352, by adding subsections (a)-(k), and renumbering the
252
See generally Chapter 382 of the Texas Health and Safety Code.
253 30 TEX. ADMIN CODE § 116.12 (2012).
254 Non-rule Standard Permit, § (d); 30 TEX. ADMIN. CODE § 103.352(d) (2012).
255 Id.
256 Id. § (d)(2).
257 See e.g. 35 Tex. Reg. 6937 (Aug. 13, 2011) (proposed rule); 36 Tex. Reg. 1145 (Feb. 18, 2011) (adopted rule published).
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previous PBR as section 106.352(l).258
The TCEQ proposed revisions to the new rules on September 2,
2011, for the stated purpose of restoring previous, inadvertently-omitted restrictions on sour gas.259
The TCEQ limited application of the newly promulgated subsections (a) - (k) to the Barnett Shale
region of north central Texas which was defined as the following counties: Archer, Bosque, Clay,
Comanche, Cooke, Coryell, Dallas, Denton, Eastland, Ellis, Erath, Hill, Hood, Jack, Johnson, Montague,
Palo Pinto, Parker, Shackelford, Stephens, Somervell, Tarrant, and Wise. Budget rider HB 1, passed in the
2011 legislative session, does not authorize the expenditure of any funds to expand the permit by rule to the
rest of the state until after August 31, 2013. In the meantime, the TCEQ must study and report to the
legislature its analysis of 18 months of data from the Barnett Shale. It must also assess the technical
feasibility and economic reasonableness of extending Barnett Shale requirements to the rest of the state.
PROPOSED RULE
The TCEQ has just published provisions revisions to the Barnett Shale PBR. The
revision would remove Archer, Bosque, Clayton Comanche, Coryell, Eastland,
Shackelford and Stephens counties from the applicability of the PBR. New
facilities in those counties must continue to be authorized by another version of
the standard permit or a permit by rule. The proposed revisions would also allow
compliance with a local ordinance requiring at least a 50-foot separation between
an oil and gas facility and residences, buildings, and other areas used by the
public to meet all state separation requirements. Finally, the TCEQ proposes to
extend the deadline for owners and operators of existing facilities in the Barnett
Shale Region to notify the TCEQ of their location and method of authorization
from January 1, 2013 to January 5, 2015. Comments on the proposed rule must
be submitted by July 16, 2012.260
Subsection (l) of the newly adopted PBR, which consists of the language and conditions that existed
in § 106.352 prior to the January 26, 2011 adoption, applies to oil and gas facilities in those counties
outside the Barnett Shale region.
a. Applicability.
Oil and gas sites in the Barnett Shale became subject to the new PBR on April 1, 2011.261
All other
counties state-wide should use subsection (l) for all registrations (at least until the TCEQ reviews the
applicability of the new PBR).
b. Types of authorizations.
There is an increasingly stringent array of permitting authorizations, depending on the level of
changes to existing emissions:
Level 0: existing facilities that are grandfathered in, for the most part.
Level 1 notification.
Level 2 notification.
Standard non-rule permit.
Facilities that do not qualify for a PBR or a standard permit must be authorized with a new source
review (―NSR‖) permit.262
258
36 Tex. Reg. 1145.
259 See, e.g., 36 Tex. Reg. 5630 (Sept. 2, 2011).
260 37 Tex. Reg. 4842 (June 15, 2012).
261 36 Tex. Reg. 1145 (Feb. 18, 2011).
262 30 TEX. ADMIN CODE 116, Subchapter B (2012).
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c. Additional authorizations that may be required.
A new source review (―NSR‖) permit can authorize facilities that do not qualify for a PBR
or a standard permit.263
Major sources of air emissions are also subject to Title V of the Federal Clean Air Act and
must meet operating permit requirements.264
A facility with more than 3,000 horsepower at
a site from aggregate engines may meet the threshold for ―major source.‖
A facility that meets the following criteria must comply with emission inventory reporting
rules:
o It has the potential to emit 100 tpy of any regulated pollutant;265
o It is a major facility or stationary source as defined in 30 TAC 116.12;266
o It operates in a nonattainment area and emits 10 tpy or more of VOCs or 25 tpy or
more of Nox;267
or
o It emits or has the potential to emit 10 tpy of any single hazardous air pollutant
(HAP) or 25 tpy of aggregate HAPs.268
Facilities that have an emission event must satisfy 30 TAC 101.201.
d. Elements of new permit by rule (“PBR”).
The new PBR – as republished on February 18, 2011 – has the following general elements:
Provide core data. Regardless of authorization, all facilities must provide indentifying
information through E-Permits no later than January 1, 2013.269
Maintenance, startup and shutdown requirements. Regardless of authorization, all
facilities must comply with the MSS requirements by January 5, 2014.270
Limitations on all registrations. Regardless of authorization, all registrations under the
PBR must:271
o Collectively emit less than or equal to 250 tons per year (tpy) of nitrogen oxides (NO
X ) or carbon monoxide (CO); 15 tpy of particulate matter with less than 10 microns
(PM 10 ); 10 tpy of particulate matter less than 2.5 microns (PM 2.5 ); and 25 tpy of
volatile organic compounds (VOC), sulfur dioxide (SO 2 ), hydrogen sulfide (H 2 S),
or any other air contaminant except carbon dioxide, water, nitrogen, methane,
ethane, hydrogen, and oxygen.
263
30 TEX. ADMIN CODE 116, Subchapter B (2012).
264 36 Tex. Reg. 1144 (Feb. 18, 2011).
265 30 Tex. Admin. Code § 101.10(a)(1) (2012).
266 Id.
267 Id.
268 30 TEX. ADMIN CODE § 101.10(a)(3) (2012).
269 30 TEX. ADMIN CODE § 106.352(b)(7) (2012). As discussed above, TCEQ proposes to change the deadline to January 5,
2015.
270 Under 30 TEX. ADMIN CODE § 106.352(b)(7)(A) (2012); 30 TEX. ADMIN. CODE 106.352(l) (2012), the regulated community
must have complied with MSS requirements by January 5, 2012. Tex. SB 1134, 82nd
R.S. (2011), codified at TEX. HEALTH &
SAFETY CODE ANN. § 382.051962, extended the authorization to January 5, 2014.
271 30 TEX. ADMIN CODE § 106.352(c)(2) (2012).
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o Not exceed thresholds for major source or major modification.
o Comply with all application provisions of federal rules for New Source Performance
Stands (NSPS), National Emission Standards for Hazardous Air Pollutants
(NESHAP) and Maximum Achievable Control Technology (MACT),
o Comply with all applicable requirements of Texas rules relating to control of air
pollution from visible emission and particulate matter, control of air pollution from
sulfur compounds, performance standards for hazardous air pollutants, control of air
pollution from volatile organic compounds, and control of air pollution from
nitrogen compounds.
Best management practices. Any new project that increases the potential to emit, or
increase emissions over previously certified representations, must meet best management
practices. A summary follows:272
o All facilities with the potential to emit must be maintained in good working order
and operated properly during facility operations. Each OGS must prepare and
maintain a program to replace, repair, and maintain facilities.
o Any facility must be operated at least 50 feet from the property line or receptor,
whichever is closer (with certain exceptions).
o Engines and turbines must meet emission and performance standards.
Liquid fuel engines must use fuel with no more than .05% sulfur and must operate
them less than 876 hours per rolling 12-month period. Sour gas is not allowed unless
the engine is lean burn and rated under 500 hp.
Engines and turbines that are used for more than 876 hours per rolling 12-month
period are authorized if no electric grid is available and section prescribed efficiency
standards are met. Otherwise, electric generators must meet the technical
requirements of the Air Quality Standard Permit for Electric Generating Unit.273
o Open topped tanks or ponds containing VOCs or H2S are allowed up to a PTE equal
to 1 tpy of VOC and .1tpy of H2S.274
o Fugitive emissions must be controlled by particular fugitive components.275
All components should be physically inspected quarterly.
All leaking components shall be repaired within 30 days at manned sites and
60 days at unmanned sites.
Tank hatches that are not designed to be completely sealed shall remain
closed except for sample or planned maintenance activities.
To the extent good engineering practice permits, new and reworked valves
and piping connections shall be located so that they can be check for leaks –
i.e. not underground.
o Particular standards apply when the operator chooses leak detection and repair
fugitive monitoring. Also all components shall be physically inspected at least
weekly by operating personnel walk-through.
272
30 TEX. ADMIN CODE § 106.352(e) (2012).
273 30 TEX. ADMIN CODE § 106.352(e)(3)(B) (2012).
274 30 TEX. ADMIN CODE § 106.352(e)(4) (2012).
275 30 TEX. ADMIN CODE § 106.352(e)(5) (2012).
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o Tanks and vessels must be painted to reduce solar hearing, unless certain exemptions
apply.
o All emission estimation methods must be used with monitoring data where
monitoring is required.
o Various types of equipment are assumed to meet certain control and destruction
efficiencies, in the absence of more accurate information.
e. Level 0: existing authorized OGS.
Sites that are already authorized under appropriate law only have to comply with additional
requirements when they add or change existing facilities in way that increases actual emissions, or the
potential to emit, over previously certified levels.276
If they do, they must register and comply with new
regulations. If the facility does not change the character or quantity of emissions, then the facility must
only notify and implement its maintenance, start up and shut down activities in compliance with the new
PBR.277
Changes that do not require registration include:
Addition of any piping, fugitive components, any other new facilities, that increase actual emissions
less than or equal to 1.0 tpy VOC, 5.0 tpy NOX, .01 tpy benzene, and .05 tpy H2S over a rolling 12-
month period,278
Changes to any existing facility that increases certified emissions less than or equal to 1.0 tpy VOC,
5.0 typ NOx, .01 typ benzene, and .05 tpy H2S over a rolling 12-month period,
Total increases over a rolling 60-month period of time that are less than or equal to 5.0 tpy VOC or
NOX, .05 tpy benzene, or .1 tpy H2S,
Addition of any new engine rated less than 100 hp, or
Replacement of any facility if the new facility does not increase the previous actual or certified
emissions.
Even so, the above changes must comply with (i) best management practices, (ii) planned maintenance,
start-up and shutdown requirements, and (iii) recordkeeping requirements.
f. Level 1 registration.
Changes that qualify as Level 1 can be implemented and then registered within 180 days after the
start of operation or of the date of the change.279
To qualify, total maximum estimated emissions must
meet the most stringent of the following:280
The applicable limits for a major stationary source or major modification for prevention of
significant deterioration (PSD) or nonattainment new source review.
The limitations derived from an impacts evaluation.
o Evaluation not required if no receptors within ¼ mile.281
The maximum emission rates for a Level 1 registration (after operator controls) are in Appendix 2.
g. Level 2 registration.
If Level 1 registration requirements cannot be met, then the operator can attempt to qualify for a
Level 2 registration. Changes that qualify for Level 2 can be implemented and then registered within 90
276
30 TEX. ADMIN CODE § 106.352(c)(1)(B) (2012).
277 30 TEX. ADMIN CODE § 106.352(b)(7) (2012).
278 30 TEX. ADMIN CODE § 106.352(b)(1)(B) (2012).
279 30 TEX. ADMIN CODE § 106.352(f)(5) (2012)
280 30 TEX. ADMIN CODE § 106.352(g) (2012).
281 30 TEX. ADMIN CODE § 106.352(k)(3) (2012).
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days after the start of operation or of the date of the change.282
Under a Level 2 registration, the total
maximum estimated annual emissions of any air contaminant shall not exceed the most stringent of the
following:283
The applicable limits for a major stationary source or major modification for PSD and NNSR.
Limitations derived from impacts evaluation.
o Evaluation not required if no receptor within ½ mile.284
The maximum emission rates for a Level 2 registration (after operator controls) are in Appendix 3.
3. The new non-rule standard permit.
On January 26, 2011, TCEQ adopted a new non-rule Air Quality Standard Permit for Oil and Gas
Handling and Production Facilities (the "non-rule Air Quality Standard Permit").285
The new non-rule Air
Quality Standard Permit applicable to oil and gas entities in the Barnett Shale can be found on the TCEQ‘s
website – but not in the Texas Register.286
A 56-page document sets the conditions for qualifying for the
standard permit.
a. Application.
Sections (a) – (k) of the non-rule Air Quality Standard Permit will apply to facilities or groups of
facilities constructed or modified on or after April 1, 2011 at a site within the Barnett Shale287
which handle
gases and liquids associated with the production, conditioning, processing, and pipeline transfer of fluids or
gases found in geologic formations on or beneath the earth‘s surface including, but not limited to, crude oil,
natural gas, condensate, and produced water.288
The requirements in the former rule-based standard permit,
located at 30 TAC §116.620, apply to existing unchanged facilities and new projects and dependent
facilities in Texas counties outside of the Barnett Shale.289
Operators may voluntarily register under the
new requirements of the non-rule Air Quality Standard Permit.
Proposed Rule Change
The TCEQ proposes to change the applicability of the standard permit for
oil and gas activities, in the same way it proposes to change the applicability
of the permit by rule, discussed above.
With regard to all previous claims under the standard permit (or any previous version of the
standard permit), existing facilities are not required to meet the non-rule Air Quality Standard Permit‘s
requirements, with the exception of planned Maintenance, Start-ups and Shutdowns (―MSS‖), until a
282
30 TEX. ADMIN CODE § 106.352(f)(6) (2012).
283 30 TEX. ADMIN CODE § 106.352(h) (2012).
284 30 TEX. ADMIN CODE § 106.352(k)(3) (2012).
285[Air Quality Standard Permit for Oil and Gas Handling and Production Facilities, available at
http://www.tceq.texas.gov/assets/public/permitting/air/Announcements/oilgas-sp.pdf.
286 http://www.tceq.texas.gov/assets/public/permitting/air/Announcements/oilgas-sp.pdf. See also TEX. HEALTH & SAFETY CODE
ANN. § 382.05195 (West 2010).
287 The Barnett Shale Counties include Archer, Bosque, Clay, Comanche, Cooke, Coryell, Dallas, Denton, Eastland, Ellis, Erath,
Hill, Hood, Jack, Johnson, Montague, Palo Pinto, Parker, Shackelford, Stephens, Somervell, Tarrant, and Wise.
288 Air Quality Standard Permit for Oil and Gas Handling and Production Facilities, § (a), available at
http://www.tceq.texas.gov/assets/public/permitting/air/Announcements/oilgas-sp.pdf.
289 Id. § (l).
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renewal under the standard permit is submitted after December 31, 2015.290
Existing authorized facilities
that have not registered planned MSS activity emissions before April 1, 2011 must register such MSS
activities, and emissions from these events must be considered in determining compliance with applicable
limits of the non-rule Air Quality Standard Permit no later than January 5, 2012.291
Maximum emission rates for the new standard permit (after operator controls) are in Appendix 4.
b. Registration.
The operator must notify the TCEQ before commencing construction or implementing changes for
any project which meets the non-rule Air Quality Standard Permit.292
Construction may begin any time
after the executive director has received written notification, and operations may continue after receipt of
registration if there are no objections, or 45 days after the executive director receives the registration,
whichever occurs first.293
In addition, within 90 days after commencing operations or implementing
changes, the operator must register the new facilities.294
The Air Quality Standard Permit also provides that only one Air Quality Standard Permit may be
registered for an oil and gas site (―OGS‖) covering a combination of dependent facilities.295
c. Best Management Practices and Best Available Control Technology.
Importantly, the non-rule Air Quality Standard Permit requires Best Management Practices
(―BMP‖) and Best Available Control Technology (―BACT‖) for new and modified facilities.296
These
requirements will apply to existing, unchanging facilities authorized under a standard permit after
any renewal submitted after December 31, 2015.297
The BMP and BACT requirements include siting
constraints and emission and performance standards.298
4. TCEQ enforcement of its air program.
The TCEQ has general enforcement authority over programs within its jurisdiction, including the
Clean Air Act.299
As discussed below, TCEQ has several enforcement options, and the remedies discussed
are cumulative of all other remedies.300
Injunction. The executive director may seek injunctive relief to restrain a violation or threat of
violation of a statute within TCEQ‘s jurisdiction, such as the CAA, or a rule adopted or an order or a
permit issued under such a statute.301
Administrative Penalties TCEQ may also assess an administrative penalty against a person who
violates the CAA, or a rule adopted, or permit or order issued by the commission under the CAA, so long
as no county, political subdivision, or municipality has instituted a lawsuit and is diligently prosecuting that
290
Id. § (f)(1).
291 Id. § (b)(7); (i).
292 Id. § (f)(4).
293 Id. § (f)(5)(D).
294 Id. § (f)(5)(A).
295Id. § (a)(2). The Air Quality Standard Permit defines an OGS as ―all facilities which meet the following: (A) Located on
contiguous or adjacent properties; (B) Under common control of the same person (or persons under common control); and (C)
Designated under same 2-digit standard industrial classification (SIC) codes.‖ Id. § (b)(3).
296 Id. § (e).
297 Id. (The BMP and BACT requirements ―are not applicable to existing, unchanging facilities until any renewal submitted after
December 31, 2015‖).
298 Id.
299 See TEX. WATER CODE ANN. §§ 5.013 (1) and 7.002 (West 2008 and Supp. 2011).
300 TEX. WATER CODE ANN. § 7.004 (West 2008).
301 TEX. WATER CODE ANN. § 7.032 (West 2008).
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lawsuit for the same violation.302
Penalties for most violations are authorized up to $25,000 per day for
each violation.303
TCEQ has great discretion in determining the amount of the penalty to be set, as various
factors are considered in determining the penalty amount, including any factors that justice may require.304
TCEQ has developed a penalty policy to aid it in computing and assessing administrative penalties.305
This
policy directs TCEQ to consider many factors in setting the administrative penalty, including whether the
harm was ―major,‖ ―moderate,‖ or ―minor,‖ and whether the person is a repeat violator.306
Civil Penalties. In addition to administrative penalties, TCEQ may assess civil penalties if a person
causes, suffers, allows, or permits a violation of the CAA or of a rule adopted or an order or permit issued
the CAA.307
Most violations are punishable by a civil penalty not less than $50 nor greater than $25,000
for each day of each violation as the court or jury considers proper.308
However, if a defendant was
previously assessed a civil penalty for a violation of a statute within the commission's jurisdiction or a rule
adopted or an order or a permit issued under the CAA within the year before the date on which the
violation being tried occurred, the defendant will be assessed a civil penalty not less than $100 nor greater
than $25,000 for each subsequent day and for each subsequent violation.309
Criminal Penalties. Certain violations of the CAA are subject to criminal penalties. A person
commits an offense if the person intentionally or knowingly, with respect to the person's conduct, violates
several different CAA provisions.310
A violation by an individual of any of the above-mentioned
provisions is punishable by a fine of not less than $1,000 or more than $50,000, confinement for a period
not to exceed 180 days, or both.311
A violation by a person other than an individual is punishable by a fine
of not less than $1,000 or more than $100,000.312
In addition, a person may face criminal penalties for violating the CAA by intentionally or
knowingly failing to pay fees,313
intentionally or knowingly making or causing to be made a false material
statement, representation, or certification, or omitting material information from, or knowingly altering,
concealing, or not filing or maintaining a notice, application, record, report, plan, or other document
required to be filed or maintained,314
or intentionally or knowingly failing to notify or report to the
commission as required.315
Permit Revocation and Suspension. TCEQ may suspend or revoke a permit or exemption issued
under the CAA, after notice and hearing, on specified grounds.316
302
TEX. WATER CODE ANN. § 7.051 (West 2008).
303 TEX. WATER CODE ANN. § 7.052(c) (West Supp. 2011)
304 TEX. WATER CODE ANN. § 7.053 (West 2008).
305 See Penalty Policy of the Texas Commission on Environmental Quality, September 2002, available at
http://www.tceq.texas.gov/publications/rg/rg-253/penpol_pdf.html.
306 Id.
307 TEX. WATER CODE ANN. § 7.102 (West 2008).
308 TEX. WATER CODE ANN. § 7.102 (West 2008). However, A person who violates of Subchapter G, Chapter 382, of the Health
and Safety Code (Tex. Health & Safety Code § 382.201 et seq.) relating to vehicle emissions, will be assessed a civil penalty not
less than $50 nor greater than $5,000 for each day of each violation as the court or jury considers proper. Id.
309 TEX. WATER CODE ANN. § 7.103 (West 2008).
310 TEX. WATER CODE ANN. § 7.177 (West 2008).
311 TEX. WATER CODE ANN. § 7.177(b) (West 2008).
312 TEX. WATER CODE ANN. § 7.177(c) (West 2008).
313 TEX. WATER CODE ANN. § 7.178 (West 2008).
314 TEX. WATER CODE ANN. § 7.179 (West 2008).
315 TEX. WATER CODE ANN. § 7.180 (West 2008).
316 TEX. WATER CODE ANN. § 7.302 (West 2008).
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C. Local air quality regulation.
Local governments can regulate air quality as well as water quality within their jurisdiction, with
similar limitations.
1. The City of Fort Worth.
As discussed above, the City of Fort Worth regulates drilling within the city. Its city code addresses
air quality, as well as water quality.
City Code. To prevent the escape of obnoxious gasses, carbon, or soot, the Code requires all
internal combustion engines or compressors used in connection with production equipment or the drilling
of a well to be equipped with a muffler.317
Operators are further required to employ reduced emission
completion techniques to minimize natural gas and other vapor releases into the environment.318
However,
operators may obtain a variance where such techniques are not feasible or dangerous to employees or the
public.319
Reduced emission completion techniques are not required of wells without a sales line and that
were either: (1) permitted prior to July 1, 2009; or (2) the first permitted well on the pad site.320
The Code
requires vapor recovery equipment with a 95% recovery efficiency for all storage tank batteries that emit
twenty-five tons or more volatile organic hydrocarbons per well head annually.321
FW Study. The City of Fort Worth funded an independent study to further examine how local
natural gas production and exploration activity affects air quality. Fort Worth selected Eastern Research
Group, Inc. (―ERG‖) to conduct the new study, called the Fort Worth Natural Gas Air Quality Study (―FW
Study‖).322
The FW Study was designed to help City officials answer the following questions:
How much air pollution is being released by natural gas exploration in Fort Worth?
Do sites comply with environmental regulation?
How do releases from these sites affect off-site air pollution levels?
Are the City's required setbacks for these sites adequate to protect public health?
The FW Study did not reveal any significant health threats beyond setback distances.323
Regardless,
ERG made a number of recommendations to further reduce any potential for harm, given the residential
settings in the metropolitan area. Tanks and line compressor engines accounted for the greatest portion of
the risks observed for the pollutants selected for further evaluation. The ERG recommended the
installation and operation of the following air pollution control equipment:
Vapor recovery units on storage tanks – Storage tanks are the highest source of benzene emissions,
and ERG estimates that vapor recovery units could reduce these emissions by 90% or more. This
would be most beneficial at wet gas sites with higher condensate production.
3-way catalysts and/or catalytic oxidizers on compressor station compressor engines –Large
compressor engines located at compressor stations are the main source of acrolein and
formaldehyde. 3-way catalysts are primarily NOx control technologies, but also reduce CO and
VOC emissions. Catalytic oxidizers are used to control CO and VOC emissions.
317
§ 15-42(A)25.
318 § 15-42(A)28.
319 Id.
320 Id.
321 § 15-42(A)36.
322 http://www.fortworthgov.org/gaswells/default.aspx?id=79548 (visited on Sept. 11, 2011).
323 Fort Worth Natural Gas Air Quality Study Final Report July 13, 2011.
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Electric compressor engines – Access to the electric grid provides an opportunity to eliminate
emissions from compressor engines completely through the use of electric motors.
Low bleed or no bleed pneumatic valve controllers – Pneumatic valve controllers were the most
frequent fugitive emission source identified during the point source testing task. The use of low
bleed valve controllers and electric valve controllers has proven effective in reducing VOC and
methane emissions from natural gas operations.
In addition to these air pollution control equipment recommendations, ERG concluded that enhanced
inspection and maintenance of equipment at natural gas sites can help ensure that preventable emissions are
greatly reduced or eliminated. At a small subset of sites, ERG had noted signs of malfunctioning equipment
that likely caused increased emissions. For example, some hatches atop tanks were ajar, and the roof of at
least one tank had been corroded.
ERG discussed options available to confirm its assumptions and findings with regards to acrolein
and formaldehyde:
Contact compressor station owners and operators to establish the frequency at which their engines
have installed controls, and to obtain any existing stack testing results.
Analyze the findings of TCEQ‘s Phase II Barnett Shale Area Special Inventory efforts to establish
the frequency at which compressor engines have installed controls.
Conduct point source stack testing at the exhaust of compressor engines to characterize acrolein and
formaldehyde emissions.
Conduct focused ambient air monitoring of acrolein and formaldehyde emissions in close proximity
to the larger compressor stations.
Finally, ERG recommended continued ambient air monitoring in and around the city of Fort Worth
in order to confirm the key findings of this report. In particular, ERG recommended that the results of
TCEQ‘s ongoing monitoring efforts in the Barnett Shale should be monitored for any changes in air quality
in Fort Worth, in case worsening air quality require additional controls or site maintenance requirements.
2. The City of Hurst.
The City of Hurst also addresses air quality in its Ordinance No. 2161, discussed above. With
respect to air quality, the City‘s ordinance requires that:
The operator perform a predrilling ambient air study.
The applicant submit a plan for control all airborne emissions and contaminants. The plan should
include:
o A site plan showing location of each emission source,
o A detailed description of measures taken and equipment used to reduce emissions listed.
Emissions be reduced.
o When feasible, the operator must recycle VOC emissions from tanks, batteries, and
separators.
o The operator must use the latest emission-reduction technologies for all fossil fuel-
powered engines used on site.
The City sample air on an annual and as-needed basis; the operator must fund any air studies.
The operator provide City with predrilling and post-drilling air analysis.
D. Various studies of public health impacts.
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A number of studies of public health impacts of hydraulic fracturing, especially in close quarters,
have been undertaken. Some of the studies have considered health impacts in general, while others have
looked at predicted health effects from either air or water impacts.
DISH, Texas study. The Texas State Department of Health Services conducted a study in DISH,
Texas to discover whether ―people living in the DISH area have unusually high levels of VOCs in their
bodies resulting from natural gas extraction as compared to the general U.S. population.‖ The study
concluded that the VOCs in the blood of DISH resident were no different from those in other parts of the
U.S. Although some VOCs were found in some people, the pattern of these findings was not consistent
with community-wide exposures. The study concluded that based on the pattern of the exposures and the
participants‘ responses to the exposure survey, many of the exposures were most likely due to other factors
such as smoking or exposure to disinfectant by-products in the drinking water or in home maintenance
products. In fact, the only residents with elevated levels of benzene in their blood were smokers.
Fort Worth study. Fort Worth‘s city-commissioned air study, discussed in Section VI.C., did not
find any significant health threats beyond setback distances. 324
324
Fort Worth Natural Gas Air Quality Study Final Report July 13, 2011.
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VII. EFFECTIVE DATES AND DEADLINES.
A summary of effective dates and deadlines follows:
April 1, 2011 Date that OGS in the Barnett Shale became subject to the new PBR
and to the new non-rule standard permit.
August 23, 2011 EPA’s proposed NSPS and air toxic standards would apply to any
facility that commences construction, reconstruction or modification
after this date.
January 2, 2012 Effective date for the RRC’s final rule requiring the disclosure of
hydraulic fracturing fluids.
June 2012 Date by which EPA intends to publish its final NSPS and air
standard. The “final rule” was issued and signed on April 17. 2012.
Operator must comply by date final rule is published, or date of
startup, whichever is later.
Sometime in 2012 EPA is expected to issue an advanced notice of rulemaking to require
producers to submit to EPA information regarding chemicals used in
drilling and fracturing, pursuant to TSCA.
Sometime in 2012 The Railroad Commission is reviewing its rules on water recycling
and may amend them.
July 9, 2012 Deadline by which to comment on EPA’s permitting guidance on the
use of diesel fuel in hydraulic fracturing fluid.
July 16, 2012 Deadline by which to submit comments on the TCEQ’s proposed
revision of the Barnett Shale PBR and standard permit.
September 10, 2012 Deadline by which to comment on BLM’s proposed hydraulic
fracturing rules.
October 2012 Deadline by which to comment on the Draft Pavillion Report.
End of 2012 Date by which EPA expects to issue its initial report on hydraulic
fracturing.
January 1, 2013 Deadline by which existing authorized facilities must submit basic
identifying information to the TCEQ via the E-permits system for
the PBR. (May be extended to January 5, 2015 by proposed rule
change.)
January 5, 2014 New deadline by which to implement MSS program under 30 TAC
101.222, for both the new PBR and the new standard permit.
Sometime in 2014 Date by which EPA expects to issue its final report on hydraulic
fracturing.
Also, date by which EPA plans to propose new standards for public
comment for the disposal of wastewater into POTWs.
December 31, 2015 After this date, existing facilities in the Barnett Shale must comply
with the non-rule Air Quality Standard Permit’s requirements when
they renew their standard permit.
January 1, 2015 After this date, operators must capture gas at fractured completions
and make it available for use or sale, which they can do through the
use of green completions.
Th
e F
utu
re O
f R
egu
lati
on
In
Hy
dra
uli
c F
ract
uri
ng
C
ha
pte
r 2
3
46
AP
PE
ND
IX 1
Tab
le 5
0.
Sum
mar
y d
escr
ipti
on
of
par
amet
ers
use
d i
n w
ater
-use
pro
ject
ions
(shal
e-gas
pla
ys)
Ba
rne
tt
Ha
yn
es
vil
le
Ea
gle
Fo
rd
Bo
ss
ier
Ha
yn
es
. W
es
t P
ea
rsa
ll
Wo
od
ford
/Ba
rne
tt
De
law
are
Ba
sin
Re
so
urc
e-b
ase
d A
pp
roa
ch
Co
un
ty C
ove
rag
e
80
%
80
%
80
%
80
%
80
%
60
%
80
%
La
tera
l S
pa
cin
g (
ft)
10
00
/ 5
00
1
00
0
10
00
/ 5
00
1
00
0
10
00
1
00
0
10
00
Inte
nsit
y-M
ga
1/1
00
0ft
H
.: 1
.0
H.:
1.1
H
.: 1
.25
H
.: 1
.1
H.:
1
.1
H.:
1.0
H
.: 1
.0
Un
co
rre
cte
d t
ota
l
wa
ter
use
(T
h.
AF
)
1,0
20
4
40
1
,51
3
22
5
37
3
58
4
34
Pro
du
cti
on
-ba
se
d A
pp
roa
ch
Pla
y E
UR
(T
cf
Eq
u.)
6
1
44
2
50
3
3
fro
m 2
01
0 t
o 2
06
0
52
2
8
16
1
21
2
.2
25
2
5
Pe
ak y
ea
r a
fte
r sta
rt
+8
+
11
+
11
+
10
+
15
+
15
+
15
E
nd
ye
ar
aft
er
sta
rt
(co
un
ty l
eve
l)
+3
0
+5
0
+7
0
+5
0
+4
5
+7
0
+7
0
Ove
rall p
ea
k y
ea
r 2
01
5
20
31
2
02
2
20
20
2
03
3
20
31
2
03
1
Ave
rag
e w
ell E
UR
H
.: 2
(co
re)
(BC
F)
H.:
1 (
no
n-c
.)
H.:
2
H.:
1.3
H
.: 1
.2
H.:
2
H.:
1.5
H
.: 1
.5
V
.: 0
.8
Ave
rag
e w
ate
r u
se
/we
ll (
Mg
al)
3.3
6
.1
6.2
3
.3
6.1
3
.3
3.3
Un
co
rre
cte
d t
ota
l
wa
ter
use
(T
h.
AF
)
45
7
27
8
18
97
3
56
2
3
19
3
19
3
Nu
mb
er
of
we
lls
esti
ma
te
59
,63
6
14
,71
2
99
,12
0
19
,01
3
1,2
55
1
9,0
40
1
9,0
40
Re
use
/ R
ecyclin
g
-1%
/ y
ea
r -0
.5%
/ y
ea
r -1
% /
ye
ar
-1%
/ y
ea
r -0
.5%
/ y
ea
r -1
% /
ye
ar
-1%
/ y
ea
r
<
20
%
<3
%
<2
0%
<
20
%
<3
%
<2
0%
<
20
%
To
tal
wa
ter
use
(fin
al re
su
lts in
Th
. A
F)
85
3
42
6
15
16
1
91
3
6
22
3
27
0
The Future Of Regulation In Hydraulic Fracturing Chapter 23
47
APPENDIX 2
The Future Of Regulation In Hydraulic Fracturing Chapter 23
48
APPENDIX 3
The Future Of Regulation In Hydraulic Fracturing Chapter 23
49
APPENDIX 4