THE FUTURE OF REGULATION IN HYDRAULIC FRACTURING · The primary program regulating water quality...

$Page 1: THE FUTURE OF REGULATION IN HYDRAULIC FRACTURING · The primary program regulating water quality effects of hydraulic fracturing is the Safe Drinking Water Act, which regulates the$
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.

http://www.oilandgaslayerblog.com/


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

i

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


ii

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


1

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).


2

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).


3

$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).


4

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).


5

―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.


6

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.


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.


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.


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.


10

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.


11

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).


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).

http://www.epa.gov/hydraulicfracture/oil_and_gas_research_mou.pdf

http://yosemite.epa.gov/opa/admpress.nsf/bd4379a92ceceeac8525735900400c27/91e7fadb4b114c4a8525792f00542001!OpenDocument

http://yosemite.epa.gov/opa/admpress.nsf/bd4379a92ceceeac8525735900400c27/91e7fadb4b114c4a8525792f00542001!OpenDocument

http://water.epa.gov/scitech/wastetech/guide/shale.cfm


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).


14

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).

http://www.epa.gov/region8/superfund/wy/pavillion/index.html

http://www.epa.gov/aboutepa/states/pa.html


15

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).


16

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.


17

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.

http://www.denverpost.com/breakingnews/ci_18601083

http://cogcc.state.co.us/


18

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.


19

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.


20

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)


21

(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.


22

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.


23

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).


24

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.


25

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.


26

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).

http://www.rrc.state.tx.us/commissioners/jones/press/112311.php

http://esd.lbl.gov/research/projects/induced_seismicity/oil&gas/

http://esd.lbl.gov/research/projects/induced_seismicity/


27

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.

http://blogs.ei.columbia.edu/2012/01/06/seismologists-link-ohio-earthquakes-to-waste-disposal-wells/


28

(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.


29

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).

http://www.epa.gov/airquality/oilandgas/actions.html


30

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.


31

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.


32

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.



249 76 Fed. Reg. at 52780.


251 Second 90-Day Report, p. 5.


33

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).


34

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).


35

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).


36

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).


37

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).


38

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).

http://www.tceq.texas.gov/assets/public/permitting/air/Announcements/oilgas-sp.pdf


39

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).




40

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)


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.


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.



311 TEX. WATER CODE ANN. § 7.177(b) (West 2008).

312 TEX. WATER CODE ANN. § 7.177(c) (West 2008).






41

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.

http://www.fortworthgov.org/gaswells/default.aspx?id=79548


42

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.


43

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.


44

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


47

APPENDIX 2


48

APPENDIX 3


49

APPENDIX 4

Date post:	23-Sep-2020
Category:	Documents
Upload:	others
View:	0 times
Download:	0 times

THE FUTURE OF REGULATION IN HYDRAULIC FRACTURING · The primary program regulating water quality...

Documents