32502 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

the thickness of the part and can be seen on 

both the inner diameter and outer diameter 

of the front forward fillet radius. 

(h) Credit for Previous Actions 

(1) If you performed an ECI of the secondstage HPT air seal before the effective date of 

this AD, using PW ASB No. PW4G–112– 

A72–330, Revision 1, dated February 14, 

2013, or earlier version, you have met the 

requirements of paragraph (e)(2)(i) of this AD. 

(2) If you performed an in-shop FPI of the 

second-stage HPT air seal before the effective 

date of this AD, you have met the 

requirements of paragraph (e)(2)(i) of this AD. 

(i) Alternative Methods of Compliance 

(AMOCs) 

The Manager, Engine Certification Office, 

FAA, may approve AMOCs for this AD. Use 

the procedures found in 14 CFR 39.19 to 

make your request. 

(j) Related Information 

(1) For more information about this AD, 

contact James Gray, Aerospace Engineer, 

Engine Certification Office, FAA, Engine & 

Propeller Directorate, 12 New England 

Executive Park, Burlington, MA 01803; 

phone: (781) 238–7742; fax: (781) 238–7199; 

email: james.e.gray@faa.gov. 

(2) For service information identified in 

this AD, contact Pratt & Whitney Division, 

400 Main St., East Hartford, CT 06108; 

phone: (860) 565–8770; fax: (860) 565–4503. 

(3) You may view this service information 

at the FAA, Engine & Propeller Directorate, 

12 New England Executive Park, Burlington, 

MA. For information on the availability of 

this material at the FAA, call (781) 238–7125. 

Issued in Burlington, Massachusetts, on 

May 28, 2014. 

Colleen M. D’Alessandro, 

Assistant Directorate Manager, Engine & 

Propeller Directorate, Aircraft Certification 

Service. 

[FR Doc. 2014–13024 Filed 6–4–14; 8:45 am] 

BILLING CODE 4910–13–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 49 

[EPA–HQ–OAR–2011–0151; FRL–9910–71– 

OAR] 

RIN 2060–AS27 

Managing Emissions From Oil and 

Natural Gas Production in Indian 

Country 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Advance notice of proposed 

rulemaking. 

SUMMARY: The purpose of this Advance 

Notice of Proposed Rulemaking (ANPR) 

is to solicit broad feedback on the most 

effective and efficient means of 

implementing the Environmental 

Protection Agency’s (EPA) Indian 

Country Minor New Source Review 

program for sources in the oil and 

natural gas production segment of the 

oil and natural gas sector. In particular, 

this ANPR discusses potential new 

source permitting approaches to address 

emissions from proposed new and 

modified oil and natural gas production 

activities. One approach is a general 

permit, which could serve as a 

streamlined permitting approach for 

addressing emissions from new and 

modified minor sources and minor 

modifications at major sources under 

the Indian Country Minor NSR rule. 

Another approach is a Federal 

Implementation Plan, which could 

address emissions from new and 

modified minor sources and minor 

modifications at major sources. Other 

possible approaches include a permit by 

rule, which is another streamlined 

permitting approach. The EPA is 

requesting comments on all available 

new source permitting approaches and 

will take this feedback into 

consideration in developing a notice of 

proposed rulemaking for this sector 

under the Indian Country Minor NSR 

program. 

In addition, while the focus of this 

ANPR is on permitting approaches for 

proposed new oil and natural gas 

production activities, the EPA believes 

that managing emissions from existing 

oil and natural gas sources in Indian 

country would result in greater 

consistency with surrounding state 

requirements. Addressing existing 

sources may be particularly important 

given the significant activity associated 

with the sector in Indian country and 

the resultant need to protect public 

health, balanced with tribes’ inherent 

sovereignty and interest in promoting 

economic development. If the EPA 

decides to address existing oil and 

natural gas production sources, then we 

will be interested in considering 

comments regarding whether a FIP 

should be the mechanism used to 

establish permitting requirements for 

new and existing sources, especially in 

areas where surrounding states regulate 

existing sources. 

DATES: Comments must be received on 

or before July 21, 2014. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2011–0151, by one of the 

following methods: 

• www.regulations.gov: Follow the 

on-line instructions for submitting 

comments. 

• Email: a-and-r-docket@epa.gov. 

Include Docket ID No. EPA–HQ–OAR– 

2011–0151 in the subject line of the 

message. 

Fax: (202) 566–9744, attention Docket 

ID No. EPA–HQ–OAR–2011–0151. 

Mail: Attention Docket ID No. EPA– 

HQ–OAR–2011–0151, EPA, Mailcode: 

6102T, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460. Please include a 

total of two copies. 

Hand Delivery: The EPA Docket 

Center, Public Reading Room, EPA 

West, Room 3334, 1301 Constitution 

Ave. NW., Washington, DC 20460, 

Attention Docket ID No. EPA–HQ– 

OAR–2011–0151. Such deliveries are 

only accepted during the Docket’s 

normal hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2011– 

0151. The EPA’s policy is that all 

comments received will be included in 

the public docket without change and 

may be made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or email. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means the EPA will not know 

your identity or contact information 

unless you provide it in the body of 

your comment. If you send an email 

comment directly to the EPA without 

going through www.regulations.gov, 

your email address will be 

automatically captured and included as 

part of the comment that is placed in the 

public docket and made available on the 

internet. If you submit an electronic 

comment, the EPA recommends that 

you include your name and other 

contact information in the body of your 

comment and with any disk or CD–ROM 

you submit. If the EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

the EPA may not be able to consider 

your comment. Electronic files should 

avoid the use of special characters, any 

form of encryption, and be free of any 

defects or viruses. For additional 

instructions on submitting comments, 

go to Section I.C of the SUPPLEMENTARY

INFORMATION section of this document. 

Docket: The EPA has established a 

docket for this action under Docket ID 

Number EPA–HQ–OAR–2011–0151. All 

documents in the docket are listed in 

the www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32503 

1EPA has proposed to extend this deadline with 

respect to true minor sources in the oil and natural 

gas sector. 79 FR 2546, Jan. 14, 2014. 

e.g., CBI or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in 

www.regulations.gov or under Docket ID 

Number EPA–HQ–OAR–2011–0151, 

EPA/DC, EPA West, Room 3334, 1301 

Constitution Ave. NW., Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the Air 

Docket is (202) 564–1742. 

FOR FURTHER INFORMATION CONTACT: 

Christopher Stoneman, Outreach and 

Information Division, Office of Air 

Quality Planning and Standards, (C304– 

01), Environmental Protection Agency, 

Research Triangle Park, North Carolina, 

27711, telephone number (919) 541– 

0823, facsimile number (919) 541–0072, 

email address: stoneman.chris@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document, ‘‘reviewing 

authority,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer 

to the EPA. 

I. General Information 

A. Does this action apply to me? 

Entities potentially affected by this 

proposed action include owners and 

operators of facilities located or 

planning to locate in Indian country as 

defined in 18 U.S.C. 1151 and as 

provided in the Indian Country Minor 

NSR rule if the facilities are from oil and 

natural gas source categories such as the 

following: 

TABLE 1—EXAMPLE OIL AND NATURAL

GAS PRODUCTION SOURCE CATEGORIES

Industry category 

North American Industry Classification 

System 

Crude Petroleum and 

Natural Gas (SIC 

1311).

211111—Crude Petroleum and Natural 

Gas Extraction 

Natural Gas Liquids 

(SIC 1321).

211112—Natural Gas 

Liquid Extraction 

Drilling Oil and Gas 

Wells (SIC 1381).

213111—Drilling Oil 

and Gas Wells 

Oil and Gas Field 

Services (SIC 

1389).

213112—Support Activities for Oil and 

Gas Operations 

This list is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

potentially affected by this action. If you 

have any questions regarding the 

applicability of this action to a 

particular entity, contact the person 

listed in the preceding section. 

B. What should I consider as I prepare 

my comments to the EPA? 

1. Submitting CBI 

Do not submit CBI information to the 

EPA through www.regulations.gov or 

email. Clearly mark the part or all of the 

information that you claim to be CBI. 

For CBI information in a disk or CD– 

ROM that you mail to the EPA, mark the 

outside of the disk or CD–ROM as CBI 

and then identify electronically within 

the disk or CD–ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, a copy of the comment 

that does not contain the information 

claimed as CBI must be submitted for 

inclusion in the public docket. 

Information so marked will not be 

disclosed except in accordance with 

procedures set forth in 40 Code of 

Federal Regulations (CFR) Part 2. 

Send or deliver information identified 

as CBI only to the following address: 

Roberto Morales, OAQPS Document 

Control Officer (C404–02), Office of Air 

Quality Planning and Standards, EPA, 

Research Triangle Park, North Carolina 

27711, Attention Docket ID No. EPA– 

HQ–OAR–2011–0151. 

2. Tips for preparing comments 

When submitting comments, 

remember to: 

• Identify the action by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

• Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

CFR part or section number. 

• Explain why you agree or disagree, 

suggest alternatives, and substitute 

language for your requested changes. 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

C. Where can I get a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, an electronic copy of this ANPR 

will also be available on the World 

Wide Web. Following signature by the 

EPA Administrator, a copy of this notice 

will be posted in the regulations and 

standards section of our NSR home page 

located at http://www.epa.gov/nsr and 

on the tribal NSR page at http://

www.epa.gov/air/tribal/tribalnsr.html. 

II. Purpose of This Advance Notice of 

Proposed Rulemaking 

The primary purpose of this ANPR is 

to solicit broad feedback on the most 

effective and efficient means of 

implementing the EPA’s Indian Country 

Minor NSR program for proposed new 

and modified sources in the oil and 

natural gas production segment of the 

oil and natural gas sector in Indian 

country. The ANPR seeks input on 

approaches that may be used to manage 

emissions from oil and natural gas 

production in Indian country and 

solicits comment on a variety of issues, 

including: (1) Whether the approach 

should address emissions from new and 

modified units only or (as discussed 

below) existing source emissions as 

well; (2) the advantages and 

disadvantages of available approaches to 

manage emissions impacts from the oil 

and natural gas sector in Indian country; 

(3) the activities and pollutants that 

warrant regulation; (4) the coordination 

of compliance between any approach 

selected and the Indian Country Minor 

NSR program; and (5) appropriate 

emission control requirements. We are 

considering the following new source 

permitting approaches for managing oil 

and natural gas emissions from 

proposed new and modified sources in 

Indian country: (1) A CAA minor NSR 

general permit; (2) a FIP; and (3) other 

available approaches such as a permit 

by rule. The EPA seeks feedback on all 

aspects of available approaches and will 

take the comments into consideration in 

developing a notice of proposed 

rulemaking for this sector under the 

Indian country Minor NSR program. 

In July 2011, the EPA finalized a rule 

that includes, among other things, a 

minor NSR permitting program that 

applies in Indian country and, 

beginning on September 2, 2014,1 that 

requires new minor sources, and minor 

and major sources that undertake a 

minor modification to obtain a preconstruction permit. We call this 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32504 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

regulation the ‘‘Federal Minor New 

Source Review Program in Indian 

Country.’’ 76 FR 38748, July 1, 2011. We 

call a permit issued under this program 

a minor NSR permit. Minor NSR 

permits address emissions from new 

and modified units at permitted sources. 

In an effort to streamline minor source 

permitting under this program, the EPA 

plans to issue general permits for new 

true minor sources for certain source 

categories. A general permit is a type of 

permit that contains standardized 

requirements that can apply to one or 

more sources in a given source category. 

One of the categories for which the EPA 

is considering issuing a general permit 

is the oil and natural gas production 

segment of the oil and natural gas 

sector. Specifically, the oil and natural 

gas production segment includes natural 

gas production that occurs prior to the 

natural gas entering natural gas 

processing plants or prior to the natural 

gas entering the transmission and 

storage segment when there is no 

natural gas processing plant, and crude 

oil production operations that generally 

occur prior to the oil entering crude oil 

storage and transmission terminals 

where the oil is loaded for transport to 

refineries. The EPA believes that the 

creation and issuance of a general 

permit may be appropriate because it 

simplifies the permit issuance process 

for minor sources so that reviewing 

authorities and others (interested 

public, regulated source) can ensure 

environmental protection without 

expending resources unnecessarily by 

developing numerous site specific 

permits that include substantially 

similar permit requirements. The 

general permit approach was proposed 

recently for a number of source 

categories as part of the Indian Country 

Minor NSR program. 79 FR 2546, Jan. 

14, 2014. 

While we believe that a general 

permit is a possible streamlining 

mechanism for issuing permits to new 

and modified oil and natural gas 

production facilities, we are also 

exploring the possibility of alternate 

mechanisms to regulate emissions from 

this segment. One approach is a FIP, 

which could be used to establish 

regulatory requirements for emissions 

from new and modified minor sources 

and minor modifications at major 

sources within the oil and natural gas 

production segment. This ANPR is the 

first instance in which the EPA is 

raising the possibility of promulgating a 

FIP to implement its minor NSR 

program with respect to oil and natural 

gas production activities in Indian 

country. A FIP was promulgated in 2013 

for oil and natural gas sources located 

in the Fort Berthold Indian Reservation 

(located in North Dakota, within the 

Williston Basin), and the approach has 

largely been viewed as successful in that 

instance. One difference between a FIP 

and a general permit is that a FIP would 

not require the submission of 

applications by sources and the review 

and approval of these applications by a 

reviewing authority prior to 

construction. Instead, the requirements 

would directly apply to sources subject 

to the regulation. A FIP could obviate 

the need for new or modified individual 

minor sources to obtain permits because 

the FIP could directly establish 

regulatory requirements like those 

established under a permit (or general 

permit) for those sources and would be 

federally enforceable. 

Other new source permitting 

approaches may be available as well, 

including the possibility of a permit by 

rule approach for true minor oil and 

natural gas sources. The permit by rule 

approach would address emissions from 

new and modified units at the permitted 

source. A permit by rule is a standard 

set of requirements that can apply to 

multiple sources with similar emissions 

and other characteristics. It is very 

similar to a general permit. Unlike a 

general permit, however, permit by rule 

requirements are promulgated using a 

rulemaking process (i.e., the 

requirements are included in the Code 

of Federal Regulations), rather than 

establishing the requirements through a 

general permit document that undergoes 

notice and comment (i.e., the 

requirements are included in the general 

permit document). The permit by rule 

mechanism is simpler than a sitespecific permit or a general permit 

because it further reduces the time 

permitting authorities must devote to 

reviewing permit applications and 

issuing permits for source categories or 

emissions generating activities that pose 

a lower environmental concern. Sitespecific permit applications and permit 

applications under a general permit 

must be reviewed and approved by a 

reviewing authority prior to 

construction or modification. Under a 

permit by rule, a reviewing authority 

would receive notification from an 

individual source that it meets all 

eligibility criteria for coverage by the 

permit, but would not need to approve 

the source’s notice prior to the source 

beginning to construct or modify. This 

approach simplifies the permitting 

process but would not allow the public 

the opportunity (as would be available 

under a site-specific or a general permit) 

to object, except by judicial challenge, 

to a particular source receiving coverage 

under the permit by rule. Further 

discussion of the proposed permit by 

rule approach is available in the recent 

action entitled ‘‘General Permits and 

Permits by Rule for the Federal Minor 

New Source Review Program in Indian 

Country,’’ 79 FR 2546 at 2566–67, Jan. 

14, 2014. 

While the focus of this ANPR is on 

permitting approaches for new oil and 

natural gas sources, the EPA believes 

that managing emissions from existing 

oil and natural gas sources also may be 

important given the significant activity 

associated with the sector in Indian 

country and the resultant need to 

protect public health and the 

environment, balanced with tribes’ 

inherent sovereignty and interest in 

promoting economic development. 

Although NSR general permits and 

permits by rule are not approaches that 

can be used to address existing sources, 

a FIP could extend to existing sources; 

this is a key distinction between general 

permits and permits by rule versus a 

FIP. Addressing existing sources 

through a FIP could be especially useful 

in areas for which surrounding state 

requirements apply to existing oil and 

natural gas sources located on lands that 

are within a state’s jurisdiction. 

Concerns related to the air quality 

impacts from existing oil and natural 

gas sources in Indian country are 

discussed further in Section IV. of this 

notice. Given these concerns, the EPA is 

requesting comments on whether a FIP, 

if that is determined to be an 

appropriate approach for new source 

permitting for oil and natural gas 

sources, should also be used to establish 

requirements for existing oil and natural 

gas sources. A FIP would effectively 

function as a permit by rule, however 

unlike the permit by rule and general 

permit approaches which are limited to 

addressing new and modified sources in 

the NSR context, a FIP could also 

address existing sources. 

Although the Indian Country Minor 

NSR rule does not include greenhouse 

gases, actions taken to reduce volatile 

organic compound (VOC) emissions— 

whether through a general permit, a FIP, 

or other approaches—also likely will 

reduce methane as a co-benefit. 

Methane, the primary constituent of 

natural gas, is a potent greenhouse gas— 

more than 20 times as potent as carbon 

dioxide when emitted directly to the 

atmosphere. In 2012, 28 percent of 

methane emissions nationwide were 

attributed to sources in the oil and 

natural gas sector. On March 28, 2014, 

the Obama Administration released a 

key element called for in the President’s 

Climate Action Plan: A Strategy to 

Reduce Methane Emissions. The 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32505 

strategy summarizes the sources of 

methane emissions, commits to new 

steps to cut emissions of this potent 

greenhouse gas, and outlines the 

Administration’s efforts to improve the 

measurement of these emissions. The 

strategy builds on progress to date and 

takes steps to further cut methane 

emissions from several sectors, 

including the oil and natural gas sector. 

III. Background on the Oil and Natural 

Gas Sector 

A. What is the oil and natural gas 

sector? 

The oil and natural gas sector 

includes operations involved in the 

extraction and production of oil and 

natural gas, as well as the processing, 

transmission and distribution of natural 

gas. Specifically for oil, the sector 

includes all operations from the well to 

the point of custody transfer at a 

petroleum refinery. For natural gas, the 

sector includes all operations from the 

well to the final end user. The oil and 

natural gas sector can generally be 

separated into four segments: (1) Oil and 

natural gas production; (2) natural gas 

processing; (3) natural gas transmission 

and storage; and (4) natural gas 

distribution. Each of these segments is 

briefly discussed below. 

This ANPR is focused on the first 

segment (oil and natural gas 

production), because this is the segment 

we believe would constitute the 

majority of the minor sources that 

would need a minor source permit in 

Indian Country. If, following the review 

of comments received via this ANPR, 

we decide that the general permit 

approach is preferable to a FIP, then we 

anticipate that the bulk of the oil and 

natural gas sources that we would 

permit would be from the production 

segment (generally, sources in other 

segments tend to be larger, potentially 

major sources such as gas processing 

plants). Because the FIP would be 

intended to replace the minor source 

program for oil and natural gas sources, 

we believe that it makes the most sense 

to focus on the production segment for 

both the general permit approach and 

the FIP approach. We welcome 

comment on this rationale. 

The oil and natural gas production 

segment includes the wells and all 

related processes used in the extraction, 

production, recovery, lifting, 

stabilization, and separation or 

treatment of oil and/or natural gas 

(including condensate). Production 

components may include, but are not 

limited to, wells and related casing 

head, tubing head and ‘‘Christmas tree’’ 

piping, as well as pumps, compressors, 

heater treaters, separators, storage 

vessels, pneumatic devices and 

dehydrators. Production operations also 

include the well drilling, completion 

and workover processes and include all 

the portable non-self-propelled 

apparatus associated with those 

operations. Production sites include not 

only the sites where the wells 

themselves are located, but also include 

stand-alone ‘‘pads’’ where oil, 

condensate, produced water, and 

natural gas from several wells may be 

separated, stored, and treated. The 

production segment also includes the 

low to medium pressure, smaller 

diameter, gathering pipelines and 

related components that collect and 

transport the oil, natural gas and other 

materials and wastes from the wells or 

well pads. 

The natural gas production segment 

ends where the natural gas enters a 

processing plant. In situations where 

there is no processing plant, the natural 

gas production segment ends at the 

point where the natural gas enters the 

transmission segment for long-line 

transport. The crude oil production 

segment ends at the storage and load-out 

terminal which is used for transport of 

the crude oil to a petroleum refinery via 

trucks or railcars. The petroleum 

refinery is not considered a part of the 

oil and natural gas sector. Thus, with 

respect to crude oil, the oil and natural 

gas sector ends where crude oil enters 

the petroleum refinery. 

The second segment, natural gas 

processing, consists of separating 

certain hydrocarbons and fluids from 

the natural gas to produce ‘‘pipeline 

quality’’ dry natural gas. While some of 

the processing can be accomplished in 

the production segment, the complete 

processing of natural gas takes place in 

the natural gas processing segment. 

Natural gas processing operations 

separate and recover natural gas liquids 

(NGL) or other non-methane gases and 

liquids from a stream of produced 

natural gas through components 

performing one or more of the following 

processes: Oil and condensate 

separation, water removal, separation of 

NGL, sulfur and carbon dioxide 

removal, fractionation of natural gas 

liquid and other processes, such as the 

capture of carbon dioxide separated 

from natural gas streams for delivery 

outside the facility. 

The pipeline quality natural gas 

leaves the natural gas processing 

segment and enters the third segment, 

natural gas transmission and storage. 

Pipelines in the natural gas transmission 

and storage segment can be interstate 

pipelines that carry natural gas across 

state boundaries or intrastate pipelines, 

which transport the natural gas within 

a single state. While interstate pipelines 

may be of a larger diameter and 

operated at a higher pressure, the basic 

components are the same. To ensure 

that the natural gas flowing through any 

pipeline remains pressurized, 

compression of the natural gas is 

required periodically along the pipeline. 

This is accomplished by compressor 

stations usually placed at between 40- 

and 100-mile intervals along the 

pipeline. At a compressor station, the 

natural gas enters the station, where it 

is compressed by reciprocating or 

centrifugal compressors. In addition to 

the pipelines and compressor stations, 

the natural gas transmission and storage 

segment includes underground storage 

facilities. 

The fourth segment, natural gas 

distribution, is the final step in 

delivering natural gas to customers. The 

natural gas enters the distribution 

segment from delivery points located on 

interstate and intrastate transmission 

pipelines to business and household 

customers. The delivery point where the 

natural gas leaves the transmission and 

storage segment and enters the 

distribution segment is often called the 

‘‘city gate.’’ Typically, natural gas 

supply companies take ownership of the 

natural gas at the city gate. 

Natural gas distribution systems 

consist of thousands of miles of piping, 

including mains and service pipelines 

to the customers. Distribution systems 

sometimes include compressor stations, 

although they are considerably smaller 

than transmission compressor stations. 

Distribution systems include metering 

stations, which allow distribution 

companies to monitor the natural gas in 

the system. Essentially, these metering 

stations measure flow rates and allow 

distribution companies to track natural 

gas as it flows through the system. 

Emissions can occur from a variety of 

processes and points throughout the oil 

and natural gas production segment. In 

Section III.B., we explain these 

processes and pollutant emissions 

points in more detail. In sum, emission 

sources include, but are not necessarily 

limited to, drilling and completion with 

the associated flowback activities; 

extraction operations; and road, 

pipeline and well pad construction. 

Also, significant emissions can be 

released from the operation of 

reciprocating internal combustion 

engines and combustion turbines that 

power compressors or provide 

electricity throughout the oil and 

natural gas production segment. 

Pollutants emitted from these activities 

that we regulate through the Indian 

Country Minor NSR permitting program 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32506 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

2Sour gas is natural gas with more than 5.7 

milligrams of hydrogen sulfide per normal cubic 

meters (0.25 grains/100 standard cubic feet), see 

AP–42 Compilation of Air Pollutant Emission 

Factors, Chapter 5.0 Introduction to Petroleum 

Industry, Section 5.3 Natural Gas Processing, 

available at http://www.epa.gov/ttnchie1/ap42/

ch05/final/c05s03.pdf. 

3E. Quinlan, R. van Kuilenberg, T. Williams, and 

G. Thonhauser, ‘‘The Impact of Rig Design and 

Drilling Methods on the Environmental Impact of 

Drilling Operations,’’ Conference of American Assn. 

of Drilling Engineers, April 12–14, 2011, available 

at www.aade.org/app/download/6858447204/

AADE-11-NTCE-61.pdf. 

4See, e.g., Anadarko Petroleum Corp. and the 

Domestic Petroleum Council, ‘‘Natural Gas 

Dehydration: Lessons Learned from the Natural Gas 

STAR Program,’’ Producers Technology Transfer 

Workshop, College Station, TX, May 17, 2007, 

available at http://epa.gov/gasstar/documents/

workshops/college-station-2007/8-dehydrations.pdf. 

(regulated NSR pollutants) include 

VOC, NOX, sulfur dioxide (SO2), 

particulate matter (PM, PM10, PM2.5), 

hydrogen sulfide, carbon monoxide 

(CO) and various sulfur compounds. 

Hydrogen sulfide and SO2 are emitted 

from production and processing 

operations that handle and treat sour 

gas.2 In Section VII. we request 

comment on the pollutant-emitting 

activities and the pollutants that might 

warrant regulation through a general 

permit, FIP, or other approach. 

B. What equipment is used for 

exploration and production and what 

emissions are associated with the use of 

this equipment? 

1. Drill Rig Emissions 

Air pollution from oil and natural gas 

drilling rigs originates from the 

combustion of diesel fuel in diesel 

engines used to drive electrical 

generators that power the drilling 

equipment. Diesel engines emit NOX, 

SO2, CO, and PM. The amount of 

emissions generated from an engine can 

vary greatly depending on factors such 

as the age of the engine, the drilling 

cycle, and the amount of energy 

required to penetrate a rock formation 

while drilling. The engine may be run 

through different activity modes 

including standby, drilling, tripping, 

back reaming, casing running, and 

cementing. The drilling and back 

reaming modes are the most power 

intensive operational modes.3

2. Natural gas Wellhead and Field 

Gathering Compressor Engines 

In production operations, 

compressors assist in increasing the 

pressure and moving the natural gas 

from the well site downstream to a 

gathering facility and beyond for further 

processing. Two types of compressor 

designs are commonly used: 

Reciprocating and centrifugal. 

In a reciprocating compressor, natural 

gas enters a suction manifold, and then 

flows into a compression cylinder. The 

natural gas is compressed in the 

cylinder by a crankshaft that runs a 

reciprocal motion piston and is powered 

by an internal combustion engine. 

Reciprocating compressors are designed 

with a rod packing seal system. The 

compressor rod packing system consists 

of a series of flexible rings that create a 

seal around the piston rod to prevent 

natural gas from escaping between the 

rod and the inboard cylinder head. All 

such packing systems vent natural gas 

under normal conditions, but the 

leakage rate will increase over time as 

the rings become worn. When this 

occurs, the packing system will need to 

be replaced to prevent excessive leaking 

from the compression cylinder. 

Centrifugal compressors use a rotating 

disk or impeller to increase the velocity 

of the natural gas which is directed to 

a divergent duct section that converts 

the velocity energy to pressure energy. 

Centrifugal compressors require seals 

around the rotating shaft to prevent 

gases from escaping where the shaft 

exits the compressor casing. Although 

dry seals are used in most new 

centrifugal compressors, some 

compressors use high-pressure wet seals 

(comprised of oil) as a barrier against 

escaping natural gas. The circulated oil 

entrains and absorbs some compressed 

natural gas. VOC emissions occur when 

the oil is stripped of natural gas that it 

absorbed at the high-pressure seal face. 

This process is known as degassing and 

is a normal function of the seal oil 

recirculation process. 

3. Liquids Unloading 

As a well ages, the reservoir’s 

pressure declines and the velocity of 

fluid through the tubing that conveys 

the natural gas to the surface also 

decreases. As velocity decreases, liquids 

can accumulate on the walls of the 

tubing. Eventually, the natural gas 

velocity in the tubing may not be 

sufficient to lift liquids to the surface. 

When liquids accumulate in the bottom 

of the well tube, natural gas flow is 

restricted or stops. 

A common approach operators use to 

restore the flow of the well is to perform 

a ‘‘blowdown.’’ To perform a 

blowdown, the operator shuts in the 

well temporarily to allow the bottom 

hole pressure to increase as natural gas 

migrates from the formation to the well. 

When the pressure has increased 

sufficiently, the operator releases the 

pressure in the well rapidly by venting 

it to the atmosphere until it reaches 

atmospheric pressure. The pressure 

drop blows the liquid out of the well. 

Releases of VOC occur as the well is 

vented to the atmosphere. This process 

does not provide a permanent solution, 

and operators will likely need to repeat 

the process over various intervals of 

time as fluids re-accumulate in the well 

tubing. These intervals vary from well to 

well and generally decrease as the well 

continues to age and requires more 

frequent unloading. Each time, the 

process releases additional VOC to the 

air. 

4. Glycol Dehydration 

Natural gas is often produced with a 

mixture of water and other 

hydrocarbons. A glycol dehydrator is 

used to remove the water vapor from the 

natural gas stream. In the first stage, the 

natural gas mixture is passed through an 

absorber where water vapor is absorbed. 

Most dehydration units use triethylene 

glycol as the absorbent. Following the 

preliminary dehydration stage, the 

glycol mixture either first moves to a 

flash tank where some gases are 

removed by reducing the pressure, or 

moves directly to a regenerator, where 

the triethylene glycol is heated to 

remove absorbed water from the glycol 

fluid. During this process, VOC, carbon 

dioxide, nitrogen, and hydrogen sulfide 

are boiled off and vented to the 

atmosphere along with the water vapor 

being removed.4

5. Oil, Condensate, and Produced Water 

Storage Tanks 

Storage tanks or vessels are used at 

well production sites to store crude oil, 

produced water, and condensate 

(hydrocarbon liquids) extracted from the 

well. Storage tanks are typically 

installed as a group of similar or 

identical vessels known as a tank 

battery. 

VOC emissions are released from a 

storage tank due to flashing losses, 

working losses, or breathing losses. 

Flashing losses occur when liquids from 

a higher pressure wellhead or separator 

are introduced into a lower pressure 

storage tank, usually operating at 

atmospheric pressure. In this situation, 

the pressure of the liquid drops, causing 

the entrained gas or some of the liquid 

to vaporize (flash). If the gas is not 

captured, it is released to the air. 

Typically, the larger the pressure drop 

(i.e. the higher the separator pressure 

compared to the storage tank pressure), 

the more flash emissions will occur in 

the storage tank. The temperature of the 

liquid may also influence the amount of 

flash emissions. Working losses occur 

when vapors in the headspace of a fixed 

roof tank are displaced to the air when 

the operator fills or empties the tank. 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32507 

5EC/R, Inc., prepared for U.S. EPA, Office of Air 

Quality Planning and Standards, Sector Policies 

and Programs Division, ‘‘Background Technical 

Support Document for Proposed Standards—Oil 

and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, 

Transmission and Distribution,’’ July 2011, EPA– 

453/R–11–002 at 5–2, available at http://

www.epa.gov/airquality/oilandgas/pdfs/

20110728tsd.pdf. 

6 Id. 

Breathing losses occur due to normal 

evaporation of liquid in the tank in 

response to temperature changes or 

other equilibrium effects. In the oil and 

natural gas production sector, flash 

emissions are much greater than the 

working and breathing losses. 

The volume of emissions from a 

storage tank depends on many factors. 

Lighter crude oils flash more 

hydrocarbons than heavier crude oils. In 

storage tanks where the oil is frequently 

cycled and the overall throughput is 

high, working losses are higher. 

Additionally, the operating temperature 

and pressure of oil as it moves from a 

separator to a storage tank affects the 

volume of flashed gases coming out of 

the oil. VOCs are the predominant 

emissions from storage tanks. 

6. Truck Loadout 

Oil and natural gas condensate are 

transported from production operations 

to natural gas processing plants and/or 

crude oil transport terminals. VOC 

emissions from the storage tanks occur 

during the load out (withdrawal) 

process. Loading losses occur as 

hydrocarbon vapors in ‘‘empty’’ cargo 

tanks are displaced to the atmosphere 

by the liquid being loaded into the 

tanks. These vapors are a composite of 

(1) vapors formed in the empty tank by 

evaporation of residual product from 

previous loads, (2) vapors transferred to 

the tank in vapor balance systems as 

product is being unloaded, and (3) 

vapors generated in the tank as the new 

product is being loaded. 

7. Pneumatic Devices 

The oil and natural gas production 

segment uses a variety of process 

control devices to moderate 

temperature, pressure, flow rate, and 

fluid volume. These devices operate 

pneumatically, electrically, or 

mechanically. Electrical and mechanical 

devices do not generate emissions. Most 

devices in the industry are pneumatic 

controllers. 

Pneumatic controllers are automated 

instruments that use differences in the 

pneumatic pressure of a gas to transmit 

a process signal or adjust position. In 

the vast majority of applications, the oil 

and natural gas production segment 

uses pneumatic controllers that make 

use of readily available high-pressure 

natural gas to provide the required 

energy and control signals. 

Pneumatic devices can release a 

significant amount of VOC emissions 

during normal operations. In these ‘‘gasdriven’’ pneumatic controllers, natural 

gas may be released with every valve 

movement, and/or continuously from 

the valve control pilot. The rate at 

which the continuous release occurs is 

referred to as the bleed rate. Bleed rates 

are dependent on the design and 

operating characteristics of the device. 

Similar designs will have similar 

steady-state rates when operated under 

similar conditions. There are three basic 

designs with emissions varying from 

each: (1) Continuous bleed devices are 

used to modulate flow, liquid level, or 

pressure, and gas is vented continuously 

at a rate that may vary over time; (2) 

snap-acting devices release gas only 

when they open or close a valve or as 

they throttle the gas flow; and (3) selfcontained devices release gas to a 

downstream pipeline instead of to the 

atmosphere.5

Continuous bleed pneumatic 

controllers can be classified into two 

types based on their emissions rates: (1) 

High-bleed controllers; and (2) lowbleed controllers. A high-bleed 

controller has a bleed rate in excess of 

6 standard cubic feet per hour (scfh), 

while low-bleed devices bleed at a rate 

less than or equal to 6 scfh.6

8. Phase Separation 

Underground crude oil and natural 

gas can contain many lighter 

hydrocarbons in solution. When the 

hydrocarbon product is brought to the 

surface and processed, many of the 

dissolved lighter hydrocarbons (as well 

as water) are removed through a series 

of high-pressure and low-pressure 

separators. Crude oil and natural gas 

under high pressure conditions are 

passed through either a two phase 

separator (where the associated gas is 

removed and any oil and water remain 

together) or a three phase separator 

(where the associated gas is removed 

and the oil and water are also 

separated). At the separator, low 

pressure gas is physically separated 

from the high pressure oil. The 

remaining low pressure oil is then 

injected into a gathering pipeline or 

directed to a storage vessel where it is 

stored for a period of time before being 

shipped off-site. The remaining 

hydrocarbons in the oil may be released 

from the oil as vapors in the storage 

vessels. 

A heater-treater is a device used to 

break up emulsions and facilitate 

removal of unwanted hydrocarbons, 

contaminants and water from the well 

stream before oil and natural gas are 

sent to the gathering pipeline or tank 

battery. A heater-treater warms the well 

stream and prevents the formation of ice 

and natural gas hydrates that may slow 

or stop production. 

During phase separation, a blend of 

hydrocarbon gases, including methane 

gas, may be produced as a by-product. 

The optimal way to manage by-product 

gas is for the operator to capture the gas, 

process it into a commercially sellable 

product, and then direct it to a pipeline 

where it can be distributed for sale. 

When the sale of the by-product gas is 

not viable, then an operator will (1) vent 

the gas emissions directly to the 

atmosphere; (2) re-inject the gas back 

into the reservoir; or (3) combust the gas 

to destroy it. Combustion devices 

predominantly used to control VOC 

emissions from low pressure gas streams 

in oil and natural gas production 

operations are ‘‘enclosed combustors.’’ 

‘‘Candlestick flares’’ are typically used 

to control higher pressure waste gas 

streams. 

9. Leaks 

As produced natural gas moves 

through equipment and pipes under 

elevated pressure within an oil or 

natural gas production facility, leaks can 

occur at various locations. Fluctuations 

in pressure, temperature and 

mechanical stresses increase the number 

of opportunities for leaks from various 

components. Sources of fugitive leaks 

include pumps, threaded and flanged 

connections, pressure relief valves, 

open-ended lines such as vents and 

drains, blowdown lines, and sampling 

points. Leaks can also occur due to 

malfunctions and pipeline ruptures. 

VOC is the main criteria pollutant 

released during equipment leaks. 

10. Compressor Engines 

Reciprocating internal combustion 

engines are typically used to run 

reciprocating compressors, whereas 

combustion turbines generally power 

centrifugal compressors. In some 

instances, an electric motor is used. The 

size and horsepower of engines used at 

a well site vary extensively based on the 

size of the field and characteristics of 

the natural gas. The compressor engines 

typically run at full capacity for 24 

hours, 7 days a week, and can emit CO, 

NOX, SO2, PM and VOCs. Electric 

motors are not a direct source of 

emissions, but other motors are. 

11. External Combustion Units 

External combustion units are used to 

generate industrial power and produce 

industrial process steam and heat. 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32508 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

7Conventional oil and natural gas resources occur 

in permeable sandstone and carbonate deposits, 

while unconventional resources exist in shale and 

sedimentary rock formations. Unconventional 

resources are also referred to as ‘‘tight formations’’ 

because their lack of permeability make them 

resistant to hydrocarbon flow unless the formation 

is fractured. M. Ratner and M. Tiemann, 

Congressional Research Service, ‘‘An Overview of 

Unconventional Oil and Natural Gas: Resources and 

Federal Actions,’’ July 15 2013, available at http:// 

www.fas.org/sgp/crs/misc/R43148.pdf. 

8A. Bar-Ilan, J. Grant, R. Parikh, A. Pollack, and 

R. Morris, ENVIRON International Corp., D. 

Henderer, Buys & Assocs., Inc., and K. Sgamma, 

Western Energy Alliance, ‘‘A Comprehensive 

Emissions Inventory of Upstream Oil and Gas 

Activities in the Rocky Mountain States,’’ prepared 

for the Western Regional Air Partnership, July 2013, 

available at http://www.epa.gov/ttnchie1/

conference/ei19/session8/barilan.pdf. 

9 D. Helmig, C. Thompson, J. Evans, P. Boylan, J. 

Hueber, and J.-H. Park, Institute of Arctic and 

Alpine Research (INSTAAR), University of 

Colorado, Boulder, ‘‘Highly Elevated Atmospheric 

Levels of Volatile Organic Compounds in the 

Uintah Basin, Utah,’’ Environ. Sci. Technol. 

(accepted for publication), March 13, 2014, 

available at http://pubs.acs.org/doi/pdf/10.1021/

es405046r. 

10 ‘‘Approval and Promulgation of Federal 

Implementation Plan for Oil and Natural Gas Well 

Production Facilities: Fort Berthold Indian 

Reservation (Mandan, Hidatsa, and Arikara Nation), 

North Dakota,’’ 78 FR 17836, March 22, 2013. The 

Technical Support Document for the Fort Berthold 

FIP includes a more detailed explanation of the rule 

development; this document is available in the 

docket for the FIP, i.e., Docket ID: EPA–R08–OAR– 

2012–0479, see www.regulations.gov. 

11See, e.g., U.S. Dept. of the Interior, Bureau of 

Land Management, ‘‘Record of Decision for the 

Gasco Energy Inc. Uinta Basin Natural Gas 

Development Project,’’ June 18, 2012, available at 

http://www.blm.gov/ut/st/en/fo/vernal/planning/

nepa_.html; U.S. Dept. of the Interior, Bureau of 

Land Management, ‘‘Greater Natural Buttes Record 

of Decision,’’ May 8, 2012, available at http://

www.blm.gov/ut/st/en/fo/vernal/planning/nepa_

html. 

12The EPA has proposed to extend this deadline 

to a date within a range between September 2, 2015 

to March 2, 2016 for oil and natural gas production 

sources. 79 FR 2546, Jan. 14, 2014. 

Examples of external combustion units 

in the oil and natural gas production 

segment include storage tank heaters, 

line heaters, and glycol reboilers. These 

units are typically fueled by natural gas 

from the field, but they can use other 

gaseous and oil-based fuels, such as 

propane and fuel oil #2. Primary 

combustion emissions are CO and NOX, 

and the size and power of such units 

varies widely based on the size of the 

field and the characteristics of the oil 

and/or natural gas being produced. 

Electric heaters are sometimes used 

when they are solar powered or when 

there is access to a power grid, but they 

are not a direct source of emissions. 

IV. Oil and Natural Gas Sector in 

Indian Country 

A. Why are we concerned about air 

quality impacts from oil and natural gas 

production in Indian country? 

In the past few years, technological 

advances in oil and natural gas 

extraction methods have made 

extraction of oil and/or natural gas from 

shale, coal-bed methane and tight 

sandstone resources more 

technologically and economically 

feasible than before. While conventional 

oil and natural gas extraction is ongoing 

in some areas of Indian country, there 

has been a sizeable increase in recent 

years in production volume in these 

areas from unconventional oil and 

natural gas extraction methods.7 Many 

areas of Indian country are located in 

shale basins with potentially 

recoverable reserves including, but not 

limited to, areas in North Dakota, 

Montana, South Dakota, Nebraska, 

Kansas, Oklahoma, Texas, New York, 

Michigan and Wisconsin. Areas of 

Indian country in western North Dakota, 

eastern Montana, Oklahoma and Texas 

lie within tight sandstone basins with 

recoverable resources, and coal bed 

methane reserves may exist under 

Indian country located in the 

Northeastern and Southwestern United 

States. 

Indian country comprises much of the 

Uinta and North San Juan Basins (in 

Utah and the Four Corners region, 

respectively). According to a Western 

Regional Air Partnership (WRAP) 

emissions inventory report focusing on 

a region spanning New Mexico, 

Colorado, Utah, Wyoming, Montana, 

and North Dakota, oil and natural gas 

production sources contribute the 

majority of the emissions of NOX and a 

large portion of the VOC emissions in 

both the Uinta Basin and Northern San 

Juan Basin.8 9 A significant number of 

oil and natural gas production sources 

also exist in the South San Juan, Wind 

River, and Williston Basins, all of which 

encompass areas of Indian country. 

Although the WRAP report included 

limited areas of Indian country within 

the United States, we believe that the 

level of activity in these areas could 

represent the kind of emissions we can 

expect in Indian country in other areas 

across the United States. Furthermore, 

as discussed in Section IV.B, Indian 

country lands that contain commercially 

viable oil and natural gas reserves are 

currently experiencing widespread 

growth in the oil and natural gas 

production segment, which could lead 

to increased emissions of air pollutants 

and adverse air quality. 

For example, during the development 

of the FIP for oil and natural gas 

production sources located on the Fort 

Berthold Indian Reservation (located in 

North Dakota, within the Williston 

Basin), the EPA determined that 

hundreds of oil and natural gas 

production facilities had been operating 

on the Reservation since 2007 and 

estimated that up to an additional 2,000 

wells could result from future 

development (see further description of 

this FIP in Section V.B.).10 Another area 

of increasing oil and natural gas 

development in Indian country is the 

Uintah and Ouray Indian Reservation in 

northeast Utah, within the Uinta Basin. 

According to recent National 

Environmental Policy Act (NEPA) 

documents for oil and natural gas 

development in the Uinta Basin, the 

Bureau of Land Management (BLM) has 

approved the construction of more than 

5,000 new wells, and even more projects 

are anticipated for future NEPA 

review.11 This increase in development 

has the potential to adversely impact air 

quality and will result in an increased 

permitting burden for sources and 

reviewing authorities under the Indian 

Country Minor NSR rule that is 

scheduled to take effect on September 2, 

2014.12

Although rapid increases in oil and 

natural gas production have occurred in 

some areas of Indian country in recent 

years, uncertainties about the extent of 

environmental impacts from this 

production in Indian country persist 

despite developing policy initiatives, 

programs, and industry practices to 

address the environmental implications 

of the emissions associated with this 

growth. These uncertainties are due in 

part to the scarcity of ambient air 

monitoring in some areas of Indian 

country, as discussed below. 

Additionally, there is incomplete 

emissions information for this sector in 

Indian country and improvements in 

emissions methodologies are still 

evolving. See Section IV.B. for further 

discussion of these issues. 

At the same time, the EPA remains 

committed to supporting tribes’ right to 

self-governance and protecting their 

inherent sovereignty. Uncertainties 

surrounding the regulation of oil and 

natural gas production sources in Indian 

country have resulted in an ‘‘uneven 

playing field’’ in some areas between 

Indian country and surrounding states 

(i.e., sources in areas with similar air 

quality are not subject to the same 

requirements). The EPA continues to 

actively reach out to oil and natural gas 

organizations and other stakeholders to 

improve our understanding of the 

potential environmental implications of 

oil and natural gas production 

operations, and we strive to provide 

greater regulatory certainty and 

consistency in the regulation of these 

operations through enhanced data 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32509 

13 In the Indian Country Minor NSR rule, EPA 

established a registration program that required 

owners and operators of existing true minor sources 

to file a one-time registration with the appropriate 

reviewing authority by March 1, 2013. EPA’s Region 

8 Office has received more than 6,400 registrations 

from true minor sources in the oil and natural gas 

sector. This far exceeded the amount received from 

sources in any other category. 

14 ‘‘Energy Development in Indian Country,’’ 

Testimony Before the Senate Committee on Indian 

Affairs, J. Gillette, Deputy Asst. Secretary Indian 

Affairs, U.S. Dept. of the Interior, Feb. 16 2012, 

available at http://www.doi.gov/ocl/hearings/112/

IndianCountryEnergyDevelopment_021612.cfm. 

15 Id. 

16 Id. 

17For more information, see: http://www.bia.gov/ 

WhoWeAre/AS-IA/IEED/DEMD/oilgas/index.htm. 

18 J. Kemp, Reuters Daily Online Publications, 

‘‘Tribes call for faster drilling on Indian lands,’’ Feb. 

5, 2013, available at http://www.reuters.com/article/ 

2013/02/05/column-kemp-oilgas-indian-landsidUSL5N0B5A9W20130205. 

19U.S. EIA, ‘‘Sales of Fossil Fuels Produced from 

Federal and Indian Lands, FY 2003 through FY 

2012,’’ May 30, 2013, available at http://

www.eia.gov/analysis/requests/federallands/. 

20U.S. EIA, ‘‘Drilling Productivity Report for Key 

Tight Oil and Shale Gas Regions,’’ March 2014, 

available at http://www.eia.gov/petroleum/drilling/

pdf/dpr-full.pdf. 

collection and analysis, improved 

information sharing and partnerships, 

and focused compliance assistance and 

enforcement. The EPA must address 

these considerations while also meeting 

our trust responsibilities regarding 

protection of air quality and public 

health in Indian country. We believe 

that it is appropriate to explore 

measures that reduce the administrative 

burden associated with regulating new 

minor sources and minor modifications 

of existing stationary sources in a way 

that: (1) Ensures the timely 

implementation of environmental 

protections; (2) maximizes the efficient 

use of resources; (3) minimizes 

preventable delays in economic 

development; and (4) proactively 

mitigates potential adverse air-qualityrelated environmental and public health 

impacts that could result from the rapid 

growth in emissions from oil and 

natural gas production operations. 

The Indian Country Minor NSR rule 

allows us to manage minor source 

emissions increases in Indian country 

and ensure that new emissions do not 

cause or contribute to a National 

Ambient Air Quality Standard (NAAQS) 

or Prevention of Significant 

Deterioration (PSD) increment violation. 

However, industry and tribal 

governments have expressed concerns 

that EPA Regional Office reviewing 

authorities may not be able to keep pace 

with the volume of oil and natural gasrelated permit applications the offices 

may receive, and a lag in permit 

issuance rates could place sources in 

Indian country at a competitive 

disadvantage compared to similar 

sources located in the surrounding statemanaged lands. We are cognizant of this 

concern, especially in light of the 

approximately 6,400 existing minor 

source registrations received in the EPA 

Region 8 Office for facilities in the oil 

and natural gas production segment.13

A general permit, a permit by rule 

(more rapid permit issuance than a 

general permit), and a FIP (essentially a 

permit by rule, but with the potential to 

additionally address existing sources) 

would each allow more expeditious 

implementation of the minor NSR 

program compared to requiring sitespecific permits. Establishing 

requirements for appropriate mitigation 

measures for a general permit or permit 

by rule in areas where emissions from 

existing oil and natural gas production 

activities are an issue could be 

challenging, given that these approaches 

would not address existing sources. 

Accordingly, today we seek comment 

on the appropriateness of any available 

permitting or other approaches as a 

means for managing emissions impacts 

from the growth of oil and natural gas 

production emissions in Indian country 

through either regulation of the 

construction and modification of 

proposed new minor sources and minor 

modifications at major sources within 

the oil and natural gas production 

segment (the permitting approach) or 

direct regulation of proposed oil and 

natural gas sources (the FIP approach). 

We also seek comment on whether and 

how a potential FIP should regulate 

emissions from existing sources in the 

oil and natural gas industry to balance 

economic growth with appropriate 

environmental protections. 

B. What information do we have 

regarding emissions and air quality 

associated with oil and natural gas 

production in Indian country? 

Federal and state government 

agencies have accumulated substantial 

data characterizing oil and natural gas 

sector activity in Indian country. But 

there are still gaps in our knowledge 

regarding the extent of oil and natural 

gas activity in Indian country and its 

impacts. The EPA is making a concerted 

effort to improve our understanding of 

oil and natural gas emissions generally, 

as well as improving estimates of 

emissions from oil and natural gas 

production activity in Indian country. 

1. Federal and State Government 

Emissions and Other Data 

According to the Office of Indian 

Energy and Economic Development 

(IEED) at the Department of the Interior 

(DOI), significant oil and natural gas 

production in Indian country has 

already occurred and there is even 

greater potential for future development. 

As of 2012, more than 2 million acres 

of Indian lands accounting for about 10 

percent of the oil and natural gas 

production from federally regulated 

onshore acreage had been leased for oil 

and natural gas development.14 The DOI 

estimates that ‘‘since 2002, annual 

income from energy mineral production 

increased by more than 113 percent and 

this trend is expected to continue for the 

foreseeable future.’’ 15 As of April 2014, 

over 6,400 minor sources in the oil and 

natural gas production sector have 

registered with the EPA’s Region 8 

Office in response to the registration 

requirement in the Indian Country 

Minor NSR rule. 

By comparing maps of Indian country 

in the U.S. to maps of known 

conventional and unconventional oil 

and natural gas reserves, it is evident 

that many areas of Indian country are in 

regions that are rich in mineral 

resources. The IEED has been providing 

technical assistance to various tribes to 

identify numerous prospects for 

drilling, ‘‘by purchasing, reprocessing 

and interpreting thousands of miles of 

2D [two dimensional] seismic data as 

well as hundreds of square miles of 3D 

[three dimensional] data.’’ 16 The DOI’s 

Indian Affairs Office maintains an Atlas 

of Oil and Gas Plays on American 

Indian Lands as well as information 

sheets on the status of oil and natural 

gas reserves and drilling on a limited set 

of specific reservation lands.17

Growth in oil and natural gas 

production in Indian country is 

occurring or is expected in many areas. 

For example, the Jicarilla Apache 

Nation reports that it has almost 3,000 

active and plugged oil and natural gas 

wells, and 2,000 miles of natural gasgathering pipelines and roads, while the 

Ute Tribal Business Committee reports 

that the Ute reservation currently has 

7,000 wells, and plans to open up an 

additional 150,000 acres to mineral 

leases.18 The U.S. Energy Information 

Administration (EIA) reports that sales 

of crude oil produced on Indian lands 

located primarily in North Dakota and 

Utah increased 56 percent from 2003 to 

2012, which is the highest recorded 

level.19 Detailed drilling rig activity 

reported by EIA projects almost a 

doubling of new oil production from 

rigs at the Bakken formation, which 

underlies the Fort Berthold Indian 

Reservation, from December 2012 to 

December 2013.20 The Bakken oil field 

covers about 200,000 square miles of the 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32510 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

21Wyoming Dept. of Environmental Quality, 

‘‘State of Wyoming Technical Support Document I 

For Recommended 8-Hour Ozone Designation for 

the Upper Green River Basin, WY,’’ March 2009, 

available at http://www.epa.gov/groundlevelozone/

designations/2008standards/rec/letters/08_WY_

rec.pdf. 

22U.S. Energy Information Administration, 

‘‘Rankings: Crude Oil Production,’’ Dec. 2013, 

available at http://www.eia.gov/state/rankings/?sid=

US#/series/46. 

23U.S. Energy Information Administration, 

‘‘Rankings: Natural Gas Marketed Production,’’ 

2012, available at http://www.eia.gov/state/

rankings/?sid=US#/series/47. 

24See Utah Dept. of Environmental Quality, 

‘‘Rural Air Quality and Oil/Gas in Utah Fact Sheet,’’ 

June 2010, available at http://www.tricountyhealth.

com/June2010-%20Air%20Issues%20with%20Oil

%20and%20Gas.pdf. 

25See Utah Dept. of Environmental Quality, 

‘‘Ozone in the Uintah Basin,’’ Sept. 2013, available 

at http://www.deq.utah.gov/locations/uintahbasin/

docs/2013/09Sep/ozone2013.pdf. 

26Limitations of use: The EPA makes no claims 

regarding the accuracy or precision of data 

concerning Indian Country locations or boundaries 

on the EnviroFacts Web site (http://www.epa.gov/

enviro/). The EPA has simply attempted to collect 

certain readily available information relating to 

Indian Country locations. Questions concerning 

data should be referred to the originating program 

or Agency which can be identified in the 

EnviroFacts tribal query metadata files for tribal 

areas in the lower 48 states (https://edg.epa.gov/

metadata/rest/document?id=%7B8077CD55-74FB4107-8047-3DEC0D55966A%7D&xsl=metadata_to_

html_full), Alaska Reservations (https://edg.epa.

gov/metadata/rest/document?id=%7BE37B0B2- 

EB0B-436C-B993-C18D8895E522%7D&xsl=

metadata_to_html_full), Alaska Native Villages 

(https://edg.epa.gov/metadata/rest/document?id=

%7BE4341D1B-656F-4E76-86DB-9216E8A968EA

%7D&xsl=metadata_to_html_full), or Alaska Native 

Allotments (https://edg.epa.gov/metadata/rest/

document?id=%7B15FEB09B-752E-4B48-B01B

D9F2D360623A%7D&xsl=metadata_to_html_full). 

The Indian Country locations shown in these files 

are suitable only for general spatial reference and 

do not necessarily reflect the EPA’s position on any 

Indian Country locations or boundaries or the land 

status of any specific location. The inclusion of 

Indian Country information on the EnviroFacts Web 

site does not represent any final EPA action 

addressing Indian Country locations or boundaries. 

This information cannot be relied upon to create 

any rights, substantive or procedural, enforceable 

by any party in litigation with the United States or 

third parties. The EPA reserves the right to change 

information on EnviroFacts at any time without 

public notice. The EPA uses the U.S. Census Bureau 

2010 tribal boundary layer data when developing 

environmental data query responses for tribes in the 

lower 48 United States and information from the 

Bureau of Land Management Alaska State Office 

when developing environmental data query 

responses for tribes in Alaska. The tribal boundary 

locations identified are suitable only for general 

spatial reference and do not necessarily reflect the 

EPA’s position on any Indian Country locations or 

boundaries, or the land status of any specific 

location. The EPA seeks to use the best available 

national Federal data and may refine the tribal 

boundary layer in the future as more accurate 

national Federal data become available. 

27 Information for those NAAQS for which the 

EPA has designated nonattainment areas in Indian 

Country are available online at http://www.epa.gov/ 

air/tribal/tribalnsr.html and Docket ID No. EPA– 

HQ–OAR–2011–0151. NAAQS for which the EPA 

has designated nonattainment areas in Indian 

Country are: ozone (2008 NAAQS), PM10 (1987 

NAAQS), PM2.5 24-Hour (2006 NAAQS), and PM2.5

annual (1997 NAAQS). No tribal lands are currently 

designated nonattainment for SO2 (2010 NAAQS), 

NO2, lead (2008 NAAQS), or CO. 

28 Designations under the 2012 PM2.5 annual 

standard (12.0 mg/m3) have not yet occurred. 

subsurface of the Williston Basin that 

lies under parts of the States of 

Montana, South Dakota, North Dakota 

and Montana in the United States, and 

the provinces of Manitoba and 

Saskatchewan in Canada. 

Declines in air quality in states such 

as Wyoming and Utah have been 

attributed to oil and natural gas 

development. In a technical support 

document for its ozone nonattainment 

designation recommendation for the 

Upper Green River Basin, Wyoming 

indicated that oil and natural gas 

development was a ‘‘pertinent factor’’ in 

ozone concentrations found in Sublette 

County. In the Upper Green River Basin 

area, Wyoming attributed 94 percent of 

VOC emissions and 60 percent of the 

NOX emissions in that area to oil and 

natural gas sources, and indicated that 

speciated data from elevated ozone 

events carried a characteristic oil and 

natural gas signature.21

Utah, which was ranked 11th in the 

nation in crude oil production in 

December 2013 22 and 10th in the nation 

in natural gas marketed production in 

2012,23 has also experienced adverse air 

quality impacts from growth in oil and 

natural gas development. In June 2010, 

the Utah Department of Environmental 

Quality reported that 2009 winter-time 

ozone levels in the Uinta Basin reached 

a high-hour value of 0.137 ppm, a level 

that is well above the level of the 

current 8-hour ozone NAAQS of 0.075 

ppm. They also reported that values of 

PM2.5 in the winters of 2007, 2008, and 

2009 were at concentrations at or above 

the PM2.5 NAAQS.24 Beginning in the 

winter of 2012, Utah undertook a multiyear, comprehensive study of emissions 

in the Uinta Basin, including areas of 

the Uintah and Ouray Indian 

Reservation. Based on data collected 

during the study, Utah concluded that 

98–99 percent of VOC emissions and 

57–61 percent of NOX emissions in the 

area originated from oil and natural gas 

operations.25

In the United States, 418 counties are 

entirely or partly Indian country.26

Table 1 summarizes the current status 

(as of August 2013) of existing air 

quality designations and design values 

(DVs) (2010–2012) of counties that are 

entirely or partly Indian country.27 It 

includes information for the 8-hour 

2008 ozone NAAQS, the 1997 PM2.5

annual NAAQS,28 2006 PM2.5 24-hour 

NAAQS and the 1987 PM10 NAAQS. 

Although the total percentage of 

counties in Indian country which are 

known to be exceeding the NAAQS is 

not large, the potential exists for others 

to exceed the NAAQS as oil and natural 

gas production activities continue to 

grow. 

TABLE 1—THE CURRENT STATUS OF DESIGNATIONS AND DVS (2010–2012) OF COUNTIES THAT ARE ENTIRELY OR

PARTLY INDIAN COUNTRY

Designation 

Counties where 

Indian country 

exists 

Counties where 

Indian country and 

2010–12 DVs 

exist 

Counties where 

Indian country 

exists and that are 

exceeding NAAQS 

based on 2010–12 

DVs 

1997 PM2.5 Annual NAAQS: 

Unclassifiable/Attainment ................................................................................... 411 72 2 

Maintenance ....................................................................................................... 1 1 0 

Nonattainment .................................................................................................... 6 6 6 

Totals ........................................................................................................... 418 79 8 

2006 PM2.5 24 Hour NAAQS: 

Unclassifiable/Attainment ................................................................................... 400 63 0 

Maintenance ....................................................................................................... 1 1 0 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32511 

29A description of the tool, how it was 

developed, and its intended use is available at 

http://www.epa.gov/ttn/chief/net/2011

inventory.html under ‘‘2011 NEI Version 1 

Documentation,’’ see Nonpoint Emission Tools and 

Methods. 

30The draft analysis is available in the docket for 

this ANPR, EPA–HQ–OAR–2011–0151, 

www.regulations.gov. The analysis does not include 

an estimate of the emissions that may occur for 

tribal lands adjacent to Alaska because the 

underlying spatial allocation done for the countybased data is not readily available for Alaska. 

TABLE 1—THE CURRENT STATUS OF DESIGNATIONS AND DVS (2010–2012) OF COUNTIES THAT ARE ENTIRELY OR

PARTLY INDIAN COUNTRY—Continued 

Designation 

Counties where 

Indian country 

exists 

Counties where 

Indian country and 

2010–12 DVs 

exist 

Counties where 

Indian country 

exists and that are 

exceeding NAAQS 

based on 2010–12 

DVs 

Nonattainment .................................................................................................... 17 16 6 

Totals ........................................................................................................... 418 80 6 

2008 Ozone NAAQS: 

Unclassifiable/Attainment ................................................................................... 395 100 18 

Unclassifiable ...................................................................................................... 2 

Nonattainment .................................................................................................... 21 21 18 

Totals ........................................................................................................... 418 121 36 

1987 PM10 NAAQS: 

Unclassifiable/Attainment ................................................................................... 384 35 3 

Maintenance ....................................................................................................... 13 4 1 

Both Nonattainment and Maintenance Areas .................................................... 6 5 2 

Nonattainment .................................................................................................... 15 13 8 

Totals ........................................................................................................... 418 57 14 

A map displaying the areas of Indian 

country for which we have ozone and 

PM2.5 monitors is available in the docket 

for this ANPR (EPA–HQ–OAR–2011– 

0151), which is available at 

www.regulations.gov. As shown by the 

map, a number of areas of Indian 

country lack a robust monitoring 

network for these pollutants. 

Consequently, there are uncertainties 

about the extent of environmental 

impacts from oil and natural gas 

production in Indian country. Given the 

environmental impacts from oil and 

natural gas production in various states, 

as discussed above, air quality in Indian 

country may likewise be at risk of 

reaching unhealthy levels due to 

impacts from oil and natural gas 

production in Indian country. 

2. Efforts To Improve Oil and Natural 

Gas Production Emissions and Other 

Data 

The EPA is working to improve our 

understanding of emissions from oil and 

natural gas generating activity. We 

recently developed an Oil and Gas 

Emission Estimation Tool that uses a 

methodology designed to estimate 

county-level emissions for the oil and 

natural gas production sector.29 Tool 

development started in April 2012 and 

has been performed in collaboration 

with a national workgroup, which 

includes state and regional emissions 

inventory developers. The draft tool 

produces county-level emissions 

estimates for many of the processes 

associated with oil and natural gas 

exploration and production for calendar 

year 2011. For criteria pollutants and 

hazardous air pollutants (HAP), this 

methodology is being used by the EPA 

to estimate emissions for use in the 

National Emissions Inventory (NEI) for 

field exploration, production, and 

gathering activities. The tool allows for 

subtracting out point source emissions 

from the tool’s nonpoint source 

emission estimates to avoid double 

counted emissions. The tool estimates 

emissions from the following oil and 

natural gas production processes: 

Drill rigs; 

Workover rigs; 

Well completions (flaring/venting for 

both conventional and green 

completions); 

Well hydraulic fracturing and 

completion engines; 

Heaters (separator, line, tank, 

reboilers); 

Storage tanks (condensate, black oil, 

produced water); 

Mud degassing; 

Dehydration units; 

Pneumatics (pumps, all other 

devices); 

Well venting/blow downs (liquid 

unloading); 

Fugitives; 

Truck loading; 

Wellhead engines; 

Pipeline compressor engines; 

Flaring; 

Artificial lifts; and 

Gas actuated pumps. 

In addition, we recently completed a 

draft estimate of emissions from oil and 

natural gas production activity in Indian 

country (except for Alaska).30 The 

analysis uses outputs from the Oil and 

Natural Gas Emissions Estimation Tool, 

as well as point source data submitted 

by states and tribes to the 2011 NEI. 

Because tribes have only submitted 

limited oil and natural gas emissions 

data to the NEI, we have developed a 

methodology that relies heavily on statesubmitted data to develop draft 

emissions estimates for sources in 

Indian country. We welcome feedback 

on our analysis and its assumptions and 

how to continue to improve these 

estimates in the future. 

Also, the EPA’s Greenhouse Gas 

Reporting Program, which was required 

by Congress in the FY2008 Consolidated 

Appropriations Act, collects activity 

and emissions data annually from 

petroleum and natural gas systems 

facilities that are above the 25,000 

metric ton carbon dioxide equivalent 

reporting threshold. The data are 

reported by facilities located across the 

United States, including facilities that 

operate in areas of Indian Country. 

Further, due to the cooperative efforts 

of states, the oil and natural gas 

industry, multi-state organizations (e.g., 

Central States Air Resources Agencies 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32512 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

31U.S. EPA Region 8, ‘‘An Assessment of the 

Environmental Implications of Oil and Gas 

Production: A Regional Case Study,’’ Working Draft, 

Sept. 2008, available at http://www.epa.gov/sectors/ 

pdf/oil-gas-report.pdf. 

32M Pring, D. Hudson, J. Renzaglia, B. Smith and 

S. Treimel, Eastern Research Group, Inc., 

‘‘Characterization of Oil and Gas Production 

Equipment and Develop a Methodology to Estimate 

Statewide Emissions,’’ final report for Texas 

Commission on Environmental Quality, Air Quality 

Division, Nov. 24, 2010, available at http://

www.tceq.texas.gov/assets/public/implementation/

air/am/contracts/reports/ei/5820784003FY1026- 

20101124-ergi-oilGasEmissionsInventory.pdf. 

33 Id. 

34A. Bar-Ilan, ENVIRON International Corp. and 

T. Moore, WRAP/Western States Air Resources 

Council (WESTAR), ‘‘Upstream Oil and Gas 

Emission Inventories: Regulatory and Technical 

Considerations,’’ Oct. 21, 2013, available at http:// 

www.wrapair2.org/pdf/Moore_Barilan_OandG_

Inventories_10_20_13.pdf. 

35L. Gribovicz, WRAP, ‘‘Analysis of States’ and 

EPA Oil & Gas Air Emissions Control Requirements 

for Selected Basins in the Western United States 

(2013 Update), Nov. 8, 2013, available at http://

www.wrapair2.org/Analysis.aspx. 

36A. Bar-Ilan, J. Grant, R. Parikh, R. Morris, 

ENVIRON International Corp. and D. Henderer, 

Kleinfelder/Buys and Assos., ‘‘Oil and Gas Mobile 

Sources Pilot Study,’’ U.S. EPA work assignment 

report 4–08, July 2011, available at http://

www.wrapair2.org/pdf/2011-07_

P3%20Study%20Report%20(Final%20July2011).pdf. 

37ENVIRON and Eastern Research Group, Inc., 

prepared for CenSARA, ‘‘2011 Oil and Gas 

Emission Inventory Enhancement Project for 

CenSARA States,’’ Dec. 21, 2012, available at: 

www.censara.org/html/presentations.php? 

mode=download&id=200. 

38L. Gribovicz, WRAP, ‘‘Analysis of States’ and 

EPA Oil & Gas Air Emissions Control Requirements 

(CenSARA) and WRAP) and 

environmental organizations, 

improvements have been made in the 

development of emissions estimation 

methodologies and in the submission of 

data to the 2011 NEI. These efforts have 

substantially improved the quantity and 

quality of state emissions information in 

the inventory, and, to a lesser but still 

helpful extent, Indian country emissions 

information. This increase in 

information has improved our 

understanding of the emissions impacts 

of the oil and natural gas exploration 

and production sector. The following 

summary describes some of these 

efforts. 

EPA Region 8: In 2008, the EPA’s 

Region 8 Office (for Montana, North and 

South Dakota, Wyoming, Colorado, and 

Utah) assessed the environmental 

impacts of oil and natural gas 

production in that region, including 

areas of Indian country. The assessment 

concluded that VOC emissions from 

activities associated with oil and natural 

gas production comprised over 40 

percent of the total criteria pollutant 

emissions in the EPA Region 8 states in 

2002, while emissions of NOX, CO and 

SO2 contributed approximately 15 

percent, 9 percent and 4 percent of total 

criteria pollutant emissions in the 

Region, respectively. While the study 

found that PM emissions from oil and 

natural gas production activity 

constituted a comparatively small 

fraction of total regional criteria 

pollutant emissions, the study, 

nonetheless, expressed concern about 

the potential impacts of PM emissions 

from this sector in the future given 

expected industry growth rates.31

Texas: While there are limited areas 

of Indian country in Texas, information 

about the emissions from oil and natural 

gas production in the State may be 

indicative of the types of emissions in 

certain areas of Indian country. In 2010, 

Texas released a comprehensive report 

characterizing emissions from oil and 

natural gas production in the State. The 

report concluded that emissions from 

‘‘area source oil and gas production sites 

on a state-wide basis are significant with 

over 200,000 tons of NOX, 1,500,000 

tons of VOC, and 30,000 tons of HAP 

emitted in 2008.’’ 32 Even larger 

contributions of VOC emissions 

originated from storage tanks and 

pneumatic pumps. The report indicated 

that compressor engines and artificial 

lift engines were the main sources of 

NOX emissions.33

WRAP: The WRAP began efforts to 

improve emissions estimation 

methodologies and inventories in 2005. 

In Phase III and IV of its study, WRAP 

developed a comprehensive base year 

inventory for several basins in the 

Rocky Mountain area that encompass 

areas of Indian country. The Phase III 

inventory showed that VOC emissions 

varied widely between basins, with 

pneumatic devices, dehydrators, and 

tanks being significant sources of VOC 

in non-coal methane basins. The 

Williston Basin had significantly higher 

VOC emissions from oil and natural gas 

activity than any other basin at over 

350,000 tons/year. Three other basins 

had VOC emissions that neared 100,000 

tons/year. 

The WRAP emissions inventory effort 

also found that emissions of NOX per 

wellhead have remained relatively 

stable with differences explainable by 

the amount of centralized versus well 

pad compression used.34 Estimated 

emissions of SO2 were comparatively 

less significant, and the predominant 

source of SO2 emissions from oil and 

natural gas occurs downstream from oil 

and natural gas production in gas 

processing plants.35

In July 2011, the WRAP published the 

first emissions inventory report that 

attempts to quantify the contribution of 

oil and natural gas mobile source 

emissions to total emissions inventories. 

Results of this limited study showed 

that mobile sources did not contribute 

significantly to total VOC, CO, and NOX

emissions, but did comprise a 

significant proportion of total PM10

emissions due to vehicle traffic on 

unpaved roads.36

CenSARA: In 2012, CenSARA 

released an oil and natural gas 

emissions study that included such area 

source emission points as hydraulic 

fracturing pumps, casing gas venting, 

produced water storage tanks, gasactuated pneumatic pumps, fugitive 

emissions from compressor seals, mud 

degassing, and hydrocarbon liquids 

loading. Emissions estimates for these 

sources, however, contain some 

uncertainties due to data gaps on 

equipment usage and size, local gas 

compositions, usage of control methods, 

and venting rates for particular sources. 

The CenSARA study concluded that 

major sources of VOC emissions vary 

greatly by basin, and that pneumatic 

devices and storage tank emissions 

consistently remained significant 

sources of VOC emissions in all basins. 

For NOX emissions, the report identified 

wellhead compressor engines as the 

‘‘largest source of NOX emissions across 

the CenSARA domain, representing on 

average at least 50 percent of the total 

basin-level NOX emissions in some of 

the basins such as Permian, Western 

Gulf, Anadarko, Bend Arch Fort Worth 

and East Texas.’’ The report also 

identified heaters as a major source of 

NOX emissions, especially in oil 

producing basins. Notably, the report 

did not specifically highlight NOX

emissions from flaring, but instead 

included these emissions within its 

estimates for different source types such 

as well completions, condensate tanks, 

crude oil tanks, blow downs and 

dehydrators.37

Efforts to improve emission 

estimation and measurement 

methodologies and characterize air 

quality impacts from oil and natural gas 

production operations are ongoing. 

While the quantity and quality of our 

NOX and VOC inventories are getting 

better, we cannot combine prior and 

current information to form emission 

trends for oil and natural gas production 

because of the lack of quality data 

regarding these sources in earlier 

inventories. Also, non-ozone precursors 

and other criteria pollutants are not as 

well studied and characterized, 

although the WRAP emissions inventory 

project suggests that the primary source 

of SO2 emissions is natural gas 

processing plants.38


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32513 

for Selected Basins in the Western United States 

(2013 Update),’’ Nov. 8, 2013, available at http://

www.wrapair2.org/Analysis.aspx. 

39See, e.g., L. Gribovicz, WRAP, ‘‘Analysis of 

States’ and EPA Oil & Gas Air Emissions Control 

Requirements for Selected Basins in the Western 

United States (2013 Update),’’ Nov. 8, 2013, 

available at http://www.wrapair2.org/Analysis.aspx; 

NSPS 40 CFR Part 60, Subpart OOOO; and B. 

Finley, Denver Post, ‘‘Colorado takes up details in 

push to cut oil and gas air pollution,’’ Nov. 22, 

2013, available at http://www.denverpost.com/

environment/ci_24575958/colorado-takes-updetails-push-cut-oil-and. 

We also recognize that VOC emissions 

information from sources located within 

one geological formation may not be 

representative of the type of emissions 

expected from other formations. 

Different geological formations produce 

different types of fluids and gases which 

affect the pollutant concentrations in 

emissions from those gases and liquids. 

VOC emissions rates at a single well 

tend to decline after the time the well 

is drilled and becomes productive. 

These rates can also change due to 

operational variances resulting from 

declines in flow rates and temperature 

fluctuations. Pollutant concentrations 

from the same well site also change as 

production draws liquids and gas from 

deeper within the formation. 

3. Summary Conclusions on the State of 

Oil and Natural Gas Production 

Emissions and Associated Air Quality 

Information in Indian Country 

When the Agency reviews the 

information available to characterize the 

emissions impact of ongoing oil and 

natural gas production activity in Indian 

country, we reach two main 

conclusions. First, we recognize the 

need to continue improving our 

understanding of oil and natural gas 

production emissions and activity in 

Indian country. Second, despite the 

need for additional information and 

associated uncertainties, we believe 

enough information is available that it is 

appropriate to seek comment on the 

need to establish requirements for 

existing sources to protect air resources 

and public health in Indian country 

from the impacts of oil and natural gas 

production activity, especially in cases 

where adjoining state requirements 

address existing sources in those states. 

Available evidence indicates that 

cumulative emissions from existing 

sources in the oil and natural gas 

production industry are causing 

elevated ambient ozone levels in areas 

outside of Indian country. We believe 

that air quality in Indian country may be 

similarly at risk of reaching unhealthy 

levels from the cumulative impacts of 

oil and natural gas production sources. 

Although at this time, we cannot 

quantify the magnitude of that risk, we 

believe that there is the possibility that 

air quality levels may violate the 8-hour 

ozone NAAQS in some areas currently 

classified as unclassifiable/attainment, 

and also may cause increases in ozone 

concentrations in areas already violating 

the 8-hour ozone NAAQS. 

This second conclusion is based on 

best available information on oil and gas 

emissions and associated air quality, 

including: Data provided to EPA 

through efforts led by individual states 

or multi-state organizations to improve 

our understanding of oil and natural gas 

emissions and associated air quality 

information for areas with oil and 

natural gas production operations; state 

emissions inventories for, and studies 

of, the oil and natural gas production 

industry that provide us with 

information on the predominant sources 

of VOC and NOX emissions in the oil 

and natural gas sector; and state and 

EPA regulatory efforts 39 to control 

emissions from new and existing 

sources in the oil and natural gas 

industry that indicate that cost-effective 

emissions reductions are likely available 

to control emissions from these VOC 

and NOX emissions sources. Given these 

factors, we believe it is appropriate to 

seek comment on regulating existing oil 

and natural gas production emission 

sources, as well as new and modified 

minor sources and minor modifications 

at major sources located in Indian 

country through a FIP or other approach 

to ensure air quality resources are 

protected in Indian country. 

V. Federal Implementation Plan 

Approach 

A. What is a FIP? 

Under section 302(y) of the Act, the 

term ‘‘Federal implementation plan’’ 

means ‘‘. . . a plan (or portion thereof) 

promulgated by the Administrator to fill 

all or a portion of a gap or otherwise 

correct all or a portion of an inadequacy 

in a State implementation plan, and 

which includes enforceable emission 

limitations or other control measures, 

means or techniques (including 

economic incentives, such as 

marketable permits or auctions of 

emissions allowances), and provides for 

attainment of the relevant national 

ambient air quality standard.’’ 42 U.S.C. 

7602. 

While the definition refers only to an 

inadequacy in a state plan, we also use 

this term to describe actions we take to 

regulate emissions in Indian country 

pursuant to our authority under CAA 

section 301(d) which authorizes us to 

treat Indian tribes as states and, in 

appropriate circumstances, to issue 

regulations establishing applicable 

requirements. 42 U.S.C. 7601(d). 

The Indian country minor NSR rule is 

an example of a FIP. In that rule, we 

identified a regulatory gap that could 

have the effect of adversely impacting 

air quality due to the lack of approved 

minor NSR permit programs to regulate 

construction of new and modified minor 

sources and minor modifications of 

major sources in Indian country. The 

EPA promulgated the FIP to ensure that 

air resources in Indian county are 

protected by establishing a 

preconstruction permitting program to 

regulate emissions increases resulting 

from construction and modification 

activities that are not already regulated 

by the major NSR permitting programs. 

B. What is the EPA’s authority for 

issuing a FIP regulating sources in 

Indian country? 

Section 301(d) of the CAA, 42 U.S.C. 

7601(d), directs us to promulgate 

regulations specifying the provisions of 

the Act for which it is appropriate for 

us to treat Indian tribes in the same 

manner as states. Pursuant to this 

statutory directive, the EPA 

promulgated regulations entitled 

‘‘Indian Tribes: Air Quality Planning 

and Management’’ [Tribal Air Rule 

(TAR)] 63 FR 7254 (February 12, 1998). 

This regulation delineates the CAA 

provisions for which we will treat tribes 

in the same manner as states. See 40 

CFR 49.3, 49.4. In this regulation, we 

determined that we would not treat 

tribes as states with respect to CAA 

section 110(a)(1) (State Implementation 

Plan (SIP) submittal) and CAA section 

110(c)(1) (directing the EPA to 

promulgate a FIP ‘‘within 2 years’’ after 

we find that a state has failed to submit 

a required plan, or has submitted an 

incomplete plan, or within 2 years after 

we disapproved all or a portion of a 

plan), among other provisions. See 40 

CFR 49.4(a), (d); 63 FR at 7262–66 

(February 12, 1998). 

The TAR preamble clarified that by 

including CAA section 110(c)(1) on the 

§ 49.4 list, ‘‘EPA is not relieved of its 

general obligation under the CAA to 

ensure the protection of air quality 

throughout the nation, including 

throughout Indian country. In the 

absence of an express statutory 

requirement, EPA may act to protect air 

quality pursuant to its ‘gap-filling’ 

authority under the Act as a whole. See, 

e.g. CAA section 301(a).’’ 63 FR at 7265, 

Feb. 12, 1998. The preamble confirmed 

that ‘‘EPA will continue to be subject to 

the basic requirement to issue a FIP for 

affected tribal areas within some 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32514 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

40 40 CFR 49.11(a) states that the EPA ‘‘[s]hall 

promulgate without unreasonable delay such 

Federal implementation plan provisions as are 

necessary or appropriate to protect air quality, 

consistent with the provisions of sections 301(a) 

and 301(d)(4), if a tribe does not submit a tribal 

implementation plan meeting the completeness 

criteria of 40 CFR part 51, appendix V, or does not 

receive EPA approval of a submitted tribal 

implementation plan.’’ 

41The FIP defined existing sources as sources 

constructed or modified on or after August 12, 2007 

but before April 22, 2013 (April 22, 2013 is the 

effective date of the FIP). Sources constructed or 

modified on or after April 22, 2013 are new and 

modified under the FIP. 

reasonable time.’’ Id. (referencing 

§ 49.11(a) which provides that the 

Agency will promulgate a FIP as 

necessary or appropriate to protect tribal 

air quality within a reasonable time if 

tribal efforts do not result in adoption 

and approval of tribal plans or 

programs).40

The preamble to the TAR also set 

forth our view that, based on the 

‘‘general purpose and scope of the CAA, 

the requirements of which apply 

nationally, and on the specific language 

of sections 301(a) and 301(d)(4), 

Congress intended to give to the Agency 

broad authority to protect tribal air 

resources.’’ Id. at 7262. It further 

discussed the EPA’s intent to ‘‘use its 

authority under the CAA ‘to protect air 

quality throughout Indian Country’ by 

directly implementing the Act’s 

requirements in instances where tribes 

choose not to develop a program, fail to 

adopt an adequate program or fail to 

adequately implement an air program.’’ 

Id. 

In this action, we are soliciting 

comment on the concept of using a FIP 

to regulate new and modified emissions 

units at facilities in the oil and natural 

gas production segment that operate in 

Indian country. Additionally, we are 

soliciting comments on whether a FIP, 

if that is determined to be an 

appropriate permitting approach for 

new oil and natural gas production 

sources, should also be used to regulate 

existing sources. If we determine that it 

is ‘‘necessary or appropriate’’ to exercise 

our discretionary authority under 

sections 301(a) and 301(d)(4) of the CAA 

and 40 CFR 49.11(a) of our 

implementing regulations, we will 

publish a proposed rule that provides an 

opportunity for full public review and 

comment. 

The EPA has already promulgated a 

FIP regulating new, modified and 

existing oil and natural gas production 

operations 41 on the Fort Berthold 

Indian Reservation (78 FR 17836, March 

22, 2013). The FIP requires owners and 

operators of new, modified and existing 

oil and natural gas production facilities 

to reduce VOC emissions from certain 

equipment. The rule is aimed at 

addressing significant emissions of VOC 

that could potentially threaten public 

health and the environment, while 

minimizing the regulatory burden (i.e., 

under the FIP, there is no source-bysource review of permit applications) 

and disruption to economic 

development on the reservation. The 

rule also provides improved consistency 

between what oil and natural gas 

production sources located on the 

reservation must do to control emissions 

and the requirements applicable to oil 

and natural gas production sources 

located on neighboring lands within 

State jurisdiction in North Dakota. 

C. Would an oil and natural gas FIP 

apply in addition to the Indian Country 

Minor NSR permitting program and 

would compliance with the FIP be 

mandatory? 

We envision that a source that 

complies with appropriate requirements 

for construction and modification under 

the FIP would not cause or contribute to 

a NAAQS or increment violation. 

Accordingly, the oil and natural gas FIP 

would serve the purpose for which the 

EPA promulgated the Indian Country 

Minor NSR permitting program, and, 

thus, it would be unnecessary to require 

a facility complying with the 

requirements for modification and 

construction activities in the FIP to also 

comply with requirements in the Indian 

Country Minor NSR permitting program. 

The Indian Country Minor NSR 

permitting program established general 

requirements to regulate construction 

and modification of minor sources and 

minor modifications at major sources 

from all types of pollutant-emitting 

source categories. Because a FIP would 

establish requirements tailored only for 

facilities in the oil and natural gas 

production segment, the EPA could 

specify control technology requirements 

that ensure that emissions increases 

from construction or modification of a 

minor source or minor modifications of 

a major source would not cause or 

contribute to a NAAQS or increment 

violation. In Section VII.A., we request 

comment on how we might coordinate 

compliance between the two programs if 

we were to pursue a FIP approach. 

D. Could a FIP be used to satisfy major 

source NSR requirements? 

A FIP would not replace the 

requirement for major sources to obtain 

a preconstruction permit and comply 

with Best Available Control Technology 

(BACT) emission limitations (in 

attainment and unclassifiable areas) or 

Lowest Achievable Emission Rates 

(LAER) (in nonattainment areas) before 

beginning actual construction of a new 

major source, or undertaking a major 

modification. However, if the 

enforceable requirements of the FIP 

limited the potential to emit of a new 

major source or the emissions increase 

of a major source undergoing a 

modification to less than major source 

levels, those sources could avoid the 

requirements for new major sources or 

major modifications. Both sections 165 

and 172 of the CAA explicitly require 

major sources to obtain permits for the 

construction and operation of new or 

modified major stationary sources. 42 

U.S.C. 7475 and 7502. We have already 

promulgated FIPs to carry out the major 

source permitting requirements of the 

Act for these areas (40 CFR 49.166– 

49.173, 52.21, and 52.24). 

An oil and natural gas production FIP 

for minor sources, or minor 

modifications at major sources, could 

assist in providing a more streamlined 

major NSR permit issuance process in 

the event a new major source locates in 

Indian country, or an existing source 

undergoes a major modification. This 

likely could occur if the emissions 

controls required in the FIP were 

subsequently determined to constitute 

BACT or LAER controls, or because the 

emission reductions from the FIP help 

preserve the PSD increment in a given 

area. The development of the FIP will 

also provide interested parties the 

opportunity for full comment and 

review of the regulatory provisions. 

VI. General Permit Approach 

A. What is a general permit? 

Under a CAA general permit 

approach, the EPA would use its 

permitting authority, established 

pursuant to 40 CFR 49.156, to issue a 

permit document (i.e., a general permit) 

that contains emissions limitations, 

monitoring, recordkeeping, and 

reporting requirements for a particular 

category of sources. The general permit 

would address emissions from new and 

modified units at the permitted source. 

To obtain coverage under the general 

permit, a minor source would submit an 

application for coverage to the 

reviewing authority. The application 

would demonstrate that the source 

qualifies as part of the relevant source 

category and also contains information 

on the nature of the construction or 

modification activity, including the type 

of sources involved and the magnitude 

of the proposed emissions increase. The 

reviewing authority would review the 

application once it was complete to 

verify that the source qualifies for 

coverage under the general permit and 

that it can meet the requirements of the 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32515 

permit. Following this review period, 

which includes the opportunity for the 

public to comment on the 

appropriateness of a source receiving 

coverage under a general permit, the 

reviewing authority would issue a 

notice of approval or would deny the 

request for coverage. This process can 

take as long as 90 days. The public 

would have an opportunity to comment 

on the terms and conditions of the 

general permit itself that would apply to 

the sources gaining coverage under the 

permit only during the time the EPA is 

developing the permit and within that 

process. Once the EPA issues the 

permit, the public may only challenge 

whether a particular source qualifies for 

coverage under the established permit. 

B. How would a general permit compare 

to a FIP? 

As discussed previously, although 

NSR general permits cannot be used to 

address existing sources, a FIP could 

extend to existing sources; this is a key 

distinction between general permits 

versus a FIP. 

Another distinction between a general 

permit and a FIP relates to the ability of 

the public to comment on and appeal a 

source’s commencement of 

construction. To inform the public of 

the proposed construction project under 

a general permit or a FIP, we envision 

that the process could require the 

reviewing authority to make the source’s 

advance notice available to the public, 

probably by posting it on the internet. 

Unlike the procedures for issuing and 

appealing a general permit, however, 

there would be no process for a citizen 

to comment on or appeal the right of a 

source to begin construction under the 

authority of an oil and natural gas 

production FIP. Nonetheless, an oil and 

natural gas production FIP would 

require a source to meet emission 

control requirements intended to avoid 

an increase in emissions that could 

cause or contribute to a NAAQS or PSD 

increment violation. 

With respect to compliance and 

enforcement, the EPA (or a tribe with 

implementing authority) would be 

responsible for compliance and 

enforcement on a regular basis. In 

addition, any citizen could enforce the 

provisions of a general permit or a FIP, 

as it would the requirements of any 

other implementation plan or CAA 

requirement by commencing a civil 

action in the district court in the 

judicial district in which the source is 

located. Citizens retain the right under 

CAA section 304(a)(1) to commence a 

civil action ‘‘against any person . . . 

who is alleged to have violated . . . or 

to be in violation of (A) an emission 

standard or limitation under this 

[Act]. . . .’’ 42 U.S.C. 7604(a)(1). The 

Administrator also would retain the 

ability to enforce the requirements of a 

FIP under section 113(a)(1) of the Act, 

and in some cases, section 167 of the 

Act. 42 U.S.C. 7413 and 7477. 

Both a general permit and an oil and 

natural gas production FIP provide a 

more streamlined approach for 

authorizing construction and 

modification of a source compared to 

site-specific permitting. Because an oil 

and natural gas production FIP would 

not require a source to initiate advance 

review and approval of coverage from 

the reviewing authority (similar to a 

permit by rule approach), it would 

reduce the resource burden on 

reviewing authorities associated with 

processing the potentially large volume 

of requests from true minor sources in 

the oil and natural gas production 

segment for coverage under a general 

permit. However, a FIP would provide 

less upfront scrutiny of an individual 

construction or modification project, 

and, unlike under a general permit, a 

citizen would not have the ability to 

object to a permit or a specific project 

gaining coverage and proceeding with 

construction under a FIP. The FIP 

would rely on the overall strength of the 

emissions control requirements and the 

compliance monitoring and reporting 

provisions (including potentially 

regulating both new and existing 

emissions generating activities) in the 

FIP to ensure that a new or modified 

source does not cause or contribute to 

a NAAQS or PSD increment violation. 

Unlike a site-specific permit, both a 

general permit and a FIP would require 

a pre-defined, standardized level of 

control that would not provide 

flexibility to adapt applicable 

requirements to the specific needs of 

individual areas of Indian country. A 

FIP could, however, be designed to 

address such needs in a broad way by 

requiring differing levels of control in 

areas with differing air quality concerns. 

Under the Indian Country Minor NSR 

rule, a reviewing authority could deny 

a source’s request for coverage under the 

general permit and instead issue a sitespecific permit to address the unique 

needs of the area or source. This option 

can be available if we retain 

applicability of the Indian Country 

Minor NSR rule and use the FIP only as 

an optional, alternative mechanism. 

(See Section VII.A.) 

One potential advantage of not 

retaining an option for site-specific 

permitting along with the FIP (discussed 

in Section VII.F.) is that regulated 

sources operating throughout Indian 

country would be subject to a ‘‘level 

playing field,’’ (i.e., all sources, or at 

least those located in or planning to 

locate in areas with similar air quality, 

would be subject to the same 

requirements). This would ensure that 

all oil and natural gas production 

sources in areas of Indian country with 

similar air quality are subject to the 

same level of emissions control. Neither 

a FIP nor a general permit could 

guarantee a ‘‘level playing field’’ in 

relation to sources in surrounding areas 

where states may have more or less 

stringent requirements than those that 

apply under the FIP or general permit in 

Indian country. Another approach 

would be for the FIP itself to provide a 

source the ability to seek a site-specific 

limit through a site-specific permit or 

FIP. We request comment on whether 

the inclusion of such a provision would 

be advisable. 

The EPA seeks comment on the 

advantages and disadvantages 

associated with using a FIP approach 

versus a general permit approach or 

other potential approaches such as a 

permit by rule that could be taken to 

manage air quality impacts from oil and 

natural gas production sources located 

in Indian country. We note that a permit 

by rule approach and a FIP approach 

would function in much the same 

manner, however a FIP could be used to 

address existing sources whereas an 

NSR permit by rule would be limited to 

new and modified sources. 

VII. Areas Where the EPA Is Requesting 

Comment 

A. How would an oil and natural gas 

FIP or general permit relate to the 

Indian Country Minor NSR rule? 

We envision designing any proposed 

FIP or general permit such that the 

emissions from a source that complies 

with the requirements for construction 

and modification likely would be 

protective of the NAAQS. Accordingly, 

we believe it is unnecessary to require 

a source to comply with both programs 

(i.e., the FIP or general permit and the 

Indian Country Minor NSR rule). We 

request comment on this approach. 

In concert with promulgation of a FIP 

or issuance of a general permit, we 

could amend the Indian Country Minor 

NSR permitting program to provide a 

blanket exemption for all sources in the 

oil and natural gas production segment 

subject to the FIP or general permit. As 

a result, a minor source that constructs, 

or a minor or major source that 

undertakes a minor modification in 

Indian country, would need to comply 

only with the requirements in an oil and 

natural gas production FIP or general 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32516 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

42A major source may also have certain 

recordkeeping/reporting obligations under the 

reasonable possibility provisions of the major 

source program. 

43See, e.g., L. Gribovicz, WRAP, ‘‘Analysis of 

States’ and EPA Oil and Gas Air Emissions Control 

Requirements for Oil and Gas Emissions Control 

Requirements for Selected Basins in the Western 

United States (2013 Update),’’ Nov. 8, 2013, 

available at http://www.wrapair2.org/pdf/2013-11x_

O&G%20Analysis%20(master%20w%20State%20

Changes%2011-08).pdf. 

44See Colorado Dept. of Public Health and 

Environment, Air Quality Control Commission Web 

site at http://www.colorado.gov/cs/Satellite/CDPHEAQCC/CBON/1251647985820. 

45Colorado Dept. of Public Health and 

Environment, Air Quality Control Commission, 

‘‘Cost-Benefit Analysis Submitted Per § 24–4– 

103(2.5), C.R.S.,’’ February 19, 2014, available at 

ftp://ft.dphe.state.co.us/apc/aqcc/

COST%20BENEFIT%20ANALYSIS%20%26%20

EXHIBITS/CDPHE%20Cost-Benefit%20Analysis_

Final.pdf. 

46See ‘‘Lessons Learned from Natural Gas STAR 

Partners; Installing Vapor Recovery Units on 

Storage Tanks,’’ available at http://epa.gov/gasstar/ 

documents/ll_final_vap.pdf on the EPA’s Natural 

Gas Star Web site: http://epa.gov/gasstar/

index.html. 

permit.42 Alternatively, we could 

exempt from the Indian Country Minor 

NSR permitting program only those 

sources that choose to comply with the 

requirements of an oil and natural gas 

production FIP or general permit in lieu 

of going through the permitting process 

from the minor NSR permitting 

program. This would mean that a source 

would have an option of choosing 

which program to comply with: (1) The 

FIP or general permit or (2) a sitespecific alternative requirement. This 

may be appropriate if a particular source 

faces unique circumstances and it 

believes that permitting under a sitespecific permit would result in different 

control requirements than required 

under the FIP or general permit. The 

resources required for reviewing and 

processing site-specific permits could 

increase the resource burden on 

reviewing authorities and thereby 

reduce some of the benefits of a FIP or 

general permit, but would provide 

flexibility to the industry. It would also 

increase the burden on the reviewing 

authorities as they would need to do 

more checking on actual growth and 

changes in air quality because of lack of 

full coverage of the FIP or general 

permit. 

Under the first approach, all sources 

would be required to comply with the 

oil and natural gas production FIP or 

general permit, and would not be able 

to avail themselves of a site-specific 

permit. Non-compliance with the FIP or 

general permit provisions could result 

in an enforcement action. Under the 

second approach, a source would have 

to specifically request coverage under 

the Indian Country Minor NSR 

regulation, and failure to do so could 

result in an enforcement action. We 

request comment on the best means for 

coordinating compliance between a FIP 

or general permit and the Indian 

Country Minor NSR permitting program, 

and whether we should allow 

individual sources a choice as to the 

program with which they will comply. 

B. Should we regulate existing emission 

units at a source under a FIP? 

We are concerned that the rapid 

growth of the oil and natural gas 

production segment in combination 

with existing exploration and 

production activities could result, or in 

some cases already has resulted, in 

adverse air quality impacts. We also 

believe that a number of cost-effective 

emission reduction measures could be 

applied to existing emissions units to 

balance new growth by mitigating the 

potential for adverse air quality impacts 

from overall increases in emissions. A 

number of state air pollution control 

agencies already regulate some existing 

emissions from this segment.43 For 

example, in February 2014 Colorado 

adopted additional regulations for oil 

and natural gas production operations 

that include such requirements as 

expanding nonattainment area 

pneumatic control requirements 

statewide and reducing venting and 

flaring of gas streams at well sites, 

among other control strategies.44

Colorado’s proposed revisions indicate 

that operators could install flares and 

controls on existing, uncontrolled 

storage tank batteries with VOC 

emissions of 6 tons per year (tpy) or 

higher at an average cost effectiveness 

value of $716 per ton of VOC reduced, 

and could install flares on existing 

produced water storage tanks with VOC 

emissions of 6 tpy or higher at an 

average cost effectiveness value of $715 

per ton of VOC reduced.45 In addition, 

the regulations determined leak 

detection and repair monitoring to be 

cost effective at oil and natural gas 

production facilities. Some technologies 

may even provide the industry with cost 

savings due to recovered product. For 

example, the EPA’s Natural Gas Star 

program estimates that adding a vapor 

recovery unit to a storage tank could pay 

for itself in 3 to 37 months, and 

thereafter result in cost savings.46

In view of the availability of costeffective emission reductions, and the 

impact of these existing emission 

sources on air quality, we are requesting 

comment on whether to require 

emission controls for existing oil and 

natural gas production sources in Indian 

country to create a growth margin that 

will allow further development in the 

oil and natural gas production segment 

in a manner that is protective of the 

environment. We are concerned about 

the impact existing sources have already 

had on air quality in some areas of 

Indian country. The EPA seeks 

comment on whether, if the EPA were 

to promulgate a FIP, the FIP should 

impose control requirements on new 

and modified minor sources and minor 

modifications at major sources, as well 

as on existing sources. We also request 

comment on the specific emissions 

units we should include or exclude in 

such a proposed regulation addressing 

existing source emissions. 

Some state air rules also contain 

setback requirements that ensure that 

new oil and natural gas production 

activities occur outside a set distance 

from certain types of structures, such as 

schools, hospitals or residential 

dwellings. We request comment on the 

concept of including a setback 

requirement in a FIP, as well as the 

distances we might consider for any 

such setback requirement, and on the 

type of structures for which a setback 

requirement might be appropriate. 

Existing sources would not be 

addressed by a general permit or a 

permit by rule for oil and natural gas 

sources locating in Indian country 

because NSR general permits and 

permits by rule cannot apply to existing 

sources given that the EPA’s authority 

under the CAA new source review 

provisions relates to new sources. If the 

EPA were to develop a general permit or 

a permit by rule rather than a FIP to 

manage emissions impacts in Indian 

country due to oil and natural gas 

production activities, then we request 

comment on how could we best ensure 

protection of the NAAQS. 

C. Would a FIP or general permit apply 

uniformly or would the requirements 

vary depending on a source’s location? 

The EPA is also interested in 

receiving comments on the question of 

whether, if a FIP were promulgated or 

a general permit were issued, the FIP or 

general permit should apply uniformly 

across all of Indian country (including 

existing sources, regardless of whether 

they have undergone modifications) or 

whether the requirements should vary 

according to CAA designation status or 

based on other criteria. 

In conjunction with considering 

whether we should regulate existing 

emissions units in a national FIP or 

general permit, we will consider 

whether we should create uniform 

standards that apply in all areas, or have 

the requirements vary in different oil 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32517 

and natural gas basins or air quality 

control regions. If we were to vary the 

requirements depending on a source’s 

location, we would consider the areas of 

Indian country for which it may be 

appropriate or necessary to regulate 

existing emissions units. Potential 

options for a national FIP or general 

permit include: 

1. Uniform requirements across all 

areas of Indian country; 

2. Uniform requirements only in 

nonattainment areas for a particular 

pollutant; 

3. Uniform requirements in 

nonattainment areas and in certain 

attainment areas that are approaching 

nonattainment based on an area’s design 

value(s); 

4. Uniform requirements across oil 

and natural gas basins or air quality 

control regions that exceed a certain 

density of well pad sites; 

5. Requirements that vary by basin 

based on air quality needs; or 

6. Requirements that vary by basin 

based on information or requirements 

from surrounding states. 

In considering these options, we 

would consider factors such as the 

resources and time necessary to develop 

and implement the standards, a desire 

to foster a ‘‘level playing field’’ between 

sources located in different areas, the 

availability and cost-effectiveness of 

various control technologies, and our 

existing knowledge related to air quality 

in different areas of Indian country. 

In general, uniform standards that 

apply to all sources are less complex to 

establish and implement than 

requirements that vary. If, in a national 

FIP or general permit, we vary 

requirements in different oil and natural 

gas basins or air quality control regions, 

then the rule would likely take 

additional time to develop and 

implement. Compliance would be 

correspondingly delayed and emissions 

reduction benefits realized more slowly. 

Inconsistent regulations could also be 

more difficult and complicated for the 

regulated community to understand and 

comply with, especially for companies 

with operations in multiple areas. In 

comparison, the benefits from uniform 

standards could be realized sooner and 

the requirements could be more easily 

understood, but uniform standards 

would need to ensure a sufficient level 

of protection for all areas in which they 

would apply despite differences in air 

quality issues in different areas. 

During the comment period for the 

Indian Country Minor NSR rule, we 

received comments suggesting that 

requiring a single set of controls for all 

minor sources across Indian country 

does not provide the needed flexibility 

to adapt regulations to the needs of 

individual areas of Indian country or 

take into account the benefit of a ‘‘level 

playing field’’ with surrounding areas. 

Conversely, other commenters 

expressed concern that if a federal 

program varies requirements across 

Indian country, then sources within 

certain areas of Indian country may be 

placed at a competitive disadvantage 

compared to sources located in other 

areas of Indian country. 76 FR 38748, 

38760–61, July 1, 2011. For example, if 

we regulate existing units at a source by 

mirroring appropriate requirements 

found in surrounding state jurisdictions, 

then many emission units at a source in 

the same area may be subject to similar 

requirements, but sources in different 

areas of Indian country would be subject 

to different requirements because the 

requirements can vary from state to 

state. We request comment on the best 

manner for considering or reconciling 

these opposing views in the context of 

determining the manner, and the areas 

in which, we might regulate existing 

emissions units. 

Using design values or attainment 

status to identify areas in need of 

enhanced environmental protection may 

yield results that are not equitable and/ 

or fully protective of air quality, due to 

the scarcity of air monitoring in Indian 

country. For example, we might require 

more stringent controls in a tribal area 

designated as nonattainment, while an 

unmonitored unclassifiable/attainment 

area might be subject to lesser controls. 

We request comment on whether and 

how it would be appropriate to use 

information from nearby states as a 

surrogate to address the lack of air 

quality monitoring data in neighboring 

areas of Indian country. This 

information could include actual air 

monitoring data, attainment status based 

on actual monitoring data, or even oil 

and natural gas regulatory provisions. 

Referencing state requirements as the 

basis for requirements in surrounding 

areas under Federal jurisdiction is not 

without precedent. In adopting 

requirements for sources locating on the 

Outer Continental Shelf, Congress 

amended the CAA to add section 328, 

which requires sources locating on the 

Outer Continental Shelf to comply with 

requirements that apply on nearby state 

land in some circumstances. We 

specifically request comments from 

tribal governing bodies on the 

appropriateness of using state 

information or regulations in this 

manner. 

In sum, as we consider whether it is 

appropriate or necessary to reduce 

emissions from existing emissions units 

in the oil and natural gas production 

segment to balance new source growth 

with environmental protection, we must 

also consider the appropriate scope of 

those requirements in terms of the areas 

in which the requirements apply, the 

stringency of the requirements, and the 

manner in which we might apply them. 

We request comment on all aspects of 

this issue. 

D. What applicability threshold should 

apply if we regulate existing sources, 

and should we create exemptions? 

If we regulate existing sources, then 

we would specify an applicability 

threshold to identify which sources are 

subject to control requirements. In the 

NSR permitting program, we distinguish 

applicability of regulations to sources 

based on whether they are ‘‘major’’ 

versus ‘‘minor.’’ For example, under the 

provisions of the PSD program, an oil 

and natural gas source located in an 

ozone attainment or unclassifiable area 

would be a major source if it emits or 

has the potential to emit (PTE) 250 tpy 

of any regulated pollutant. Sources that 

are ‘‘major’’ are subject to permitting 

and emissions control requirements, 

among other requirements. Certain 

minor sources are subject to only 

recordkeeping requirements. Under the 

provisions of the Indian Country Minor 

NSR permitting program, an oil and 

natural gas source located in an ozone 

unclassifiable/attainment or 

unclassifiable area would be a minor 

source if it emits or has the PTE below 

250 tpy of all regulated pollutants, but 

VOC or NOX above the minor source 

regulatory thresholds for these 

pollutants. See 40 CFR 49.153. Minor 

sources and major sources undergoing 

minor modifications must comply with 

the provisions of the Indian Country 

Minor NSR permitting program, while 

sources with a PTE that is less than the 

regulatory threshold are exempt from 

the rule. 

In regulating emissions from existing 

emission units at a source, we could 

incorporate these commonly understood 

regulatory thresholds in a number of 

ways. We could apply requirements to 

only existing major sources, as defined 

under the NSR program. Alternatively, 

we could apply the requirements to both 

major and minor existing sources. If we 

apply requirements to both minor and 

major sources, then we would have to 

determine whether the regulations 

would regulate these sources equally, or 

whether we would establish different 

requirements based on the size of the 

source. We request comment on 

whether following a traditional 

applicability approach that would make 

a distinction between ‘‘major’’ or 

‘‘minor’’ source is a desirable way to 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32518 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

47The exact nature of the analysis required and 

the specific sources of emissions that must 

undertake that analysis has been a topic of recent 

litigation. See Summit Petroleum v. EPA, 690 F.3d 

733 (6th Cir. 2012) and National Environmental 

Development Association’s Clean Air Project v. 

EPA, No. 13.1035 (D.C. Cir.). To the extent the 

source determination requirements change as a 

result of this litigation, either as a general matter or 

with specific regard to application to oil and gas 

emissions, EPA will address those changes in future 

actions related to this ANPR. 

manage air quality from oil and natural 

gas production sources in Indian 

country and, if so, then at which 

existing sources should we impose 

control requirements. We also seek 

comment on what specific pieces of oil 

and natural gas production equipment 

should be regulated, and how and to 

what degree. 

In considering this issue, it is prudent 

to take into account the potential air 

quality impacts from oil and natural gas 

production activities. As explained in 

Section IV.B., the oil and natural gas 

production industry is comprised of 

numerous, geographically dispersed 

emissions points. The contribution of 

any individual emission point to the 

total emissions inventory may be 

comparatively small. But, collectively, 

the cumulative emissions of numerous 

existing emissions points could exceed 

that of large, new major sources, and 

result in adverse air quality impacts. If 

we were to regulate emissions only from 

existing major sources, then we would 

be ignoring the cumulative air quality 

impacts from existing minor sources. 

Regulating existing emissions units at 

both major and minor sources (or at 

some lower level) would afford the 

greatest level of environmental 

protection and, if sufficiently 

controlled, would create more room for 

growth. 

Another consideration relates to the 

complexity of making stationary source 

determinations. Determining whether 

one or more emissions points are part of 

the same stationary source can require 

an owner or operator, as well as the 

permitting authority, to undertake an indepth analysis of the inter-relationships 

between two or more emissions 

points.47 It is not uncommon for 

disputes to arise regarding the 

boundaries of a stationary source, 

whether the source qualifies as a 

‘‘minor’’ or ‘‘major’’ source, and where 

a source’s actual or potential emissions 

stand with respect to the minor source 

PTE thresholds. 

Rather than following traditional 

permitting tons per year applicability 

thresholds in determining what sources 

to regulate and how to regulate them, 

we could identify cost-effective 

emissions reduction strategies and 

apply these requirements regardless of 

the cumulative total emissions from any 

given stationary source. Nevertheless, 

sources that are subject to major source 

NSR and/or Title V would still need to 

comply with those requirements. By 

applying emissions reduction measures 

without regard to cumulative emissions 

from each source, we could ensure that 

all existing sources meet cost-effective 

emissions reduction requirements, and 

avoid potential disputes related to 

stationary source boundaries. We 

request comment on using such an 

approach for establishing emission 

control requirements for existing 

sources, in lieu of following a 

traditional approach that distinguishes 

sources based on their size. Such an 

approach would be consistent with 

control requirements established in the 

majority of New Source Performance 

Standards (NSPS) and could incorporate 

unit specific size thresholds. 

We are also seeking comment on 

whether we should include certain 

exemptions within the applicability 

provisions of any potential FIP to 

prevent regulatory redundancy. For 

example, should we exempt any 

emissions producing activity or 

emissions unit at a source that might 

otherwise be required to comply with 

requirements in a FIP, if we already 

require control of emissions from that 

activity or emissions unit under a 

Federal NSPS or a National Emissions 

Standard for Hazardous Air Pollutants 

(NESHAP) (77 FR 49490, Aug. 16, 2012) 

that has either the goal or effect of 

reducing criteria pollutant emissions? 

The Oil and Gas Sector NSPS and 

NESHAP apply nationally, including in 

Indian country, but the requirements in 

a FIP could go beyond those in the 

NSPS or NESHAP, if it is deemed 

necessary. This is similar to the 

approach in minor source NSR 

programs in some states. 

Another question we would consider 

is whether we should exempt existing 

emissions units at a source that obtained 

a major NSR permit within some recent 

time period if they are complying with 

BACT or LAER for a particular 

pollutant. If so, then how far in the past 

should we recognize BACT or LAER 

requirements? Are there other regulatory 

provisions with which oil and natural 

gas sources must comply that we should 

consider when crafting the applicability 

provisions of a potential oil and natural 

gas FIP? We note that if we create such 

exemptions, it would minimize the 

possibility of creating conflicting 

provisions, although we could 

potentially require that the more 

stringent provisions would apply where 

a conflict occurs. On the other hand, it 

could result in emission units at 

different sources being subject to 

requirements that are not of equal 

stringency. We request comment on this 

issue. 

Finally, based on our experience with 

the Fort Berthold FIP, there may be 

numerous sources that would be major 

based on their PTE, but whose actual 

emissions are below the major source 

threshold. We are requesting comment 

on whether a FIP should address these 

sources, and how that might be 

accomplished. 

E. Which pollutants would we regulate? 

Sources in the oil and natural gas 

production segment emit a number of 

different air pollutants. Section IV. 

provides a general overview of the 

exploratory and production processes 

and their associated emissions. To 

function as an appropriate substitute for 

the minor NSR permitting program, an 

oil and natural gas FIP or general permit 

would need to regulate emissions of all 

‘‘regulated NSR pollutants’’ from minor 

sources that construct, or major or 

minor sources that undertake a minor 

modification. This would mean that an 

oil and natural gas FIP or general permit 

could regulate all criteria pollutants and 

all PSD pollutants emitted or potentially 

emitted by activities at minor sources 

that would construct, or minor or major 

sources that would undertake a minor 

modification. We are not aware of an 

advantage to regulating only a portion of 

the regulated NSR pollutants through a 

FIP or general permit and allowing other 

pollutants to remain subject to sitespecific permitting through the Indian 

Country Minor NSR rule. If we do not 

regulate all pollutants under a FIP or 

general permit, then we would continue 

to require sources to obtain minor NSR 

permits for the pollutants not covered 

by the FIP or general permit through the 

minor NSR permitting program. 

Based on existing air quality 

information, including area 

designations, which indicates that 

attainment of the 2008 8-hour ozone 

NAAQS may pose the biggest concern 

from the expansion of the oil and 

natural gas production segment, the 

pollutants of interest include NOX and 

VOC. Because our objective in 

regulating existing emissions units 

would be to address emerging ozone 

concerns and provide for economic 

growth in Indian country in a manner 

that avoids such degradation, we might 

consider only regulating emissions 

related to ozone. We request comment 

on which criteria pollutants and/or 

precursors should be regulated for oil 

and natural gas sources in Indian 

country. 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32519 

F. How would we determine the 

appropriate control requirements for 

new and modified sources and existing 

sources? 

The EPA seeks input on the types of 

emission control requirements that 

would be appropriate for new and 

modified minor sources and minor 

modifications at major sources. The EPA 

also seeks input on the types of 

emission control requirements that 

would be appropriate for existing 

sources, if we were to propose a FIP for 

new sources as well as for existing 

sources. 

The Indian Country Minor NSR rule 

requires a reviewing authority to 

undertake a case-specific control 

technology review to determine the 

appropriate level of emissions control 

for a new or modified emission unit. As 

part of that control technology review, 

the reviewing authority considers local 

air quality needs, typical control 

technology used by similar sources in 

surrounding areas, anticipated 

economic growth in the area, and costeffective control alternatives (76 FR 

38760, July 1, 2011). If we establish a 

uniform set of control technology 

requirements for new, modified and 

existing sources under an oil and 

natural gas production FIP, then we 

envision undertaking a similar, but not 

identical, control technology review to 

establish the requirements. Specifically, 

we envision that we would develop a 

list of potential control technology 

options by reviewing requirements that 

are currently applicable or under 

consideration by state and local air 

pollution agencies. We also might 

consider requirements in the FIP that 

applies to the Fort Berthold Indian 

Reservation (78 FR 17836, March 22, 

2013), performance standards (including 

work practice standards) in NSPS 

regulations, and recommendations in 

control techniques guidelines (CTG), 

alternative control techniques (ACT), 

and in the EPA’s Natural Gas Star 

program. We may also consult other 

sources of outside information. We 

request comment on specific relevant 

sources of information. 

In evaluating the relative merits of 

various potential control technology 

options, we would follow a process that 

considers factors used in the EPA’s 

BACT approach of weighing energy, 

environmental, and economic impacts, 

and other costs; however, we would not 

be bound to selecting controls based on 

the maximum achievable level of 

control, but instead could consider the 

degree of enhanced protection 

appropriate or necessary on a 

nationwide basis. If we tailor 

requirements to the needs of individual 

air basins or air quality control regions, 

then we may follow a similar approach 

for identifying control technology 

options in a FIP or general permit, or 

look to mirror requirements applying in 

surrounding states. 

We request comment on these 

approaches for establishing emissions 

control requirements in a FIP or general 

permit. We specifically seek comment 

on whether any particular state 

regulation could serve as a good model 

for constructing requirements that 

would apply in a specific area, or on a 

nationwide basis. 

G. Should we require sources to install 

and collect data from ambient air 

quality monitors? 

As discussed in Section IV.B., our 

understanding of the oil and natural gas 

sector’s impact on ambient air quality in 

Indian country is incomplete at this 

time given the absence of ambient air 

quality monitoring sites in many areas 

of Indian country. At the same time, 

with the prospect of continued 

significant growth in emissions from the 

oil and natural gas sector, it may be 

necessary or appropriate to impose 

emissions control requirements on 

existing emissions units. More detailed 

information on the air quality in a 

region would help us better understand 

whether emission reductions from 

existing sources are necessary or 

appropriate to accommodate emissions 

growth while still protecting public 

health. 

We seek comment on whether and 

how we might use our CAA section 114 

or other CAA authority to require oil 

and natural gas sources in Indian 

country to install and operate ambient 

air monitors. For example, should we 

require emission controls on existing oil 

and natural gas sources in all areas of 

Indian country unless ambient air 

quality monitors demonstrate that there 

is not a need for such requirements? In 

lieu of including specific ambient 

monitoring requirements, we seek 

comment on whether and how we might 

encourage sources to voluntarily install 

and maintain air quality monitors that 

meet Federal reference monitoring 

(FRM) requirements. 

H. Next Generation Compliance 

Enforcing regulatory requirements 

imposed on the oil and natural gas 

production segment in Indian country 

poses unique challenges for regulators. 

In states, sources face compliance 

oversight by both Federal and state 

regulators. While tribes and the Federal 

government are actively building tribal 

capacity to accept delegation of 

implementation programs, this capacity 

is still developing in many areas. 

Consequently, EPA Regional Office 

personnel may provide the sole resource 

for compliance oversight, and they will 

likely face resource challenges with 

regard to enforcement. 

The nature of the oil and natural gas 

production segment in Indian country 

compounds this potential problem. The 

industry includes numerous, 

geographically dispersed pollutantemitting activities. Unlike a power 

plant, for example, that emits large 

amounts of criteria pollutants from a 

few, specific, well-defined emission 

points (i.e., smoke stacks), the oil and 

natural gas production segment may 

produce emissions from multiple, 

diverse, geographically-dispersed 

sources in relatively lower amounts. 

Collectively, however, these smaller 

sources can have adverse air impacts. 

But, the sheer numbers of well pads and 

the nature of the pollutant-emitting 

activities pose challenges for developing 

a strategically effective enforcement 

program for Indian country. We may not 

be able to rely on the traditional singlefacility inspection and enforcement 

approach to ensure widespread 

compliance. Accordingly, we are 

requesting comment on ways the EPA 

can use Next Generation Compliance 

methods to promote compliance with a 

FIP, general permit, or other approach 

such as a permit by rule. 

Next Generation Compliance is a 

multi-facet concept that encompasses 

(1) Using advances in emissions 

monitoring and information technology 

to readily detect violations and allow 

rapid corrective action by regulated 

entities or regulators; (2) using 

electronic reporting (e-reporting) 

systems to provide more timely and 

transparent emissions information to 

regulators and the public; and (3) 

building compliance management and 

incentive programs within regulations 

to promote compliance. Through Next 

Generation Compliance, the EPA can 

leverage motivational factors, market 

forces, technologies, and public 

accountability to drive higher 

compliance rates. 

We are interested in gaining feedback 

on existing or emerging monitoring and 

information technologies that can be 

used by the oil and natural gas 

production segment to promote 

compliance. For example, would 

infrared monitoring systems provide a 

cost effective method for either 

detecting fugitive emissions at remote 

well pads, or hidden mechanical or 

electrical problems that could lead to 

process-upset emissions events? Are 

there any monitoring systems used by 


rmajette on DSK2TPTVN1PROD with PROPOSALS
32520 Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 

48 ‘‘External to the facility’’ means that the party 

is neither the regulated entity nor a customer, 

supplier or purchaser of the facility’s goods or 

services. 

49See U.S. Dept. of Health and Human Services, 

Food and Drug Admin., ‘‘Implementation of Third 

Party Programs under the FDA Modernization Act 

of 1997: Final Guidance for Staff, Industry and 

Third Parties,’’ Feb. 2, 2001, available at http://

www.fda.gov/MedicalDevices/

DeviceRegulationandGuidance/

GuidanceDocuments/ucm094450.htm. 

50For example, in 2004, four sources were 

assessed a penalty of approximately $1.4 million for 

excess SO2 emissions. These sources would have 

spent only $139,500 to comply with the program. 

See J. Schakenbach, R. Vollaro and R. Forte, U.S. 

EPA, Office of Atmospheric Programs, 

‘‘Fundamentals of Successful Monitoring, 

Reporting, and Verification under a Cap-and-Trade 

Program,’’ Journal of the Air & Waste Management 

Assoc., vol 56, p 1576, Nov. 2006, available at 

http://www.epa.gov/airmarkets/cap-trade/docs/

fundamentals.pdf. 

the industry to comply with 

Occupational Safety and Health Act 

regulations and other safety laws (e.g. 

photoionization detectors) that might be 

used in tandem with protocols under a 

FIP or general permit to ensure 

compliance? Are there any processbased monitoring systems already in use 

by the industry that could serve as an 

effective predictive or surrogate 

monitoring system in lieu of monitoring 

emissions directly? Are any immediate 

feedback technologies available or 

emerging that would provide the 

operator with real time measures of, or 

information on, their compliance status? 

With regard to advances in reporting 

and transparency, we would intend to 

make e-reporting the default method of 

reporting information under a future 

permitting program for oil and natural 

gas production sources in Indian 

country. E-reporting is a standardized, 

internet-based, electronic reporting 

system. E-reporting reduces the cost of 

complying with reporting requirements 

compared to paper reporting systems. 

Also, with e-reporting, the EPA and 

public gain more timely access to 

compliance information and industry 

perceives a greater incentive to comply, 

because data are more readily available 

and transparent to the public. Although 

we would intend to rely on e-reporting 

as the default reporting method in a 

future permitting program for the oil 

and natural gas production segment in 

Indian country, we request comment on 

whether the segment faces any unique 

challenges that we should consider 

relative to the type of information 

collected, the frequency of collection, or 

the database system used to store 

information. 

We also request comment on the 

feasibility of using third-party 

compliance verification as a means for 

demonstrating compliance. Third-party 

compliance verification relies on a party 

external to a facility,48 such as a private 

auditor or inspector, to verify and report 

a facility’s compliance status. Thirdparty compliance verification can 

enhance accountability, improve 

compliance, and produce more and 

better compliance data. 

A successful third-party compliance 

system relies on the availability of 

competent and independent third 

parties. This means that the person 

conducting the compliance verification 

possesses the technical expertise and 

professional judgement to properly 

verify compliance. For purposes of an 

oil and natural gas FIP or general 

permit, what minimum level of 

education, experience, or training is 

appropriate? Should we require third 

parties to meet certain accreditation 

standards, and/or meet a minimum set 

of requirements to demonstrate 

independence? For example, the Food 

and Drug Administration (FDA) 

specifies requirements for independence 

and lack of a financial conflict of 

interest for persons carrying out section 

510(k) of the FDA Modernization Act of 

1997.49 Other requirements we could 

consider might be prohibiting the 

auditor from consulting with the clients 

on corrective actions to ensure financial 

independence; assigning verifiers to 

facilities randomly rather than allowing 

a company to select their verifier; 

limiting the number of occasions a 

company can rely on the same verifier; 

and barring the company from hiring a 

verifier for an established waiting 

period. 

One criticism that people have 

regarding third-party verification 

programs is that outside parties lack the 

specialized knowledge and 

understanding of standard business 

practices for a particular organization to 

most effectively audit company records. 

One recommendation that flows from 

this complaint is that companies that 

use an internal audit system in 

conjunction with an ISO 14001 

environmental management system 

should be permitted to rely on their 

internal, but sufficiently independent, 

auditing departments. Because of 

familiarity with standard business 

practices, internal auditors may have a 

higher level of understanding of the 

business’ activities and, therefore, be 

able to conduct more thorough audits 

then external auditors. We request 

comment on the use of independent 

internal audit systems for compliance 

verification. Should the EPA allow such 

an approach for compliance with a 

future permitting program for oil and 

natural gas sources in Indian country? If 

so, then what measures should the EPA 

impose to ensure an absence of a 

conflict of interest? Should a company 

be required to rely on an external third 

party for some demonstration period, 

after which a company could transition 

to an internal auditing department? 

We request comment on all aspects of 

using an independent compliance 

verification system to enhance and 

promote compliance. We specifically 

request comment on the issues we raise 

above, and on whether such a system 

should be mandatory for all sources 

regulated under a potential FIP, general 

permit, or other approach, or only for 

those who choose a flexible, alternative 

method of compliance. 

In addition to the use of an 

independent compliance verification 

system, we request comment on two 

compliance incentive programs: (1) An 

automatic, pre-set penalty system, and 

(2) use of modified monitoring, 

recordkeeping and/or reporting 

requirements. With an automatic, preset penalty system, the regulation could 

specify a set monetary penalty for 

certain non-compliance events. This 

penalty would be payable upon 

disclosure of an excess emissions event 

without notice or issuance of a demand 

for payment. The sum of the penalty 

could vary based on whether noncompliance was self-disclosed, 

disclosed by a third-party auditor, or 

discovered by EPA enforcement. 

Importantly, we would design an 

automatic penalty provision to 

encourage compliance by making the 

path to compliance easier than noncompliance. For example, the EPA’s 

Acid Rain Program assesses an excess 

emissions penalty set at $2,000/ton 

(adjusted annually for inflation). This 

penalty exceeds the cost of complying 

with the program and serves as an 

effective deterrent against noncompliance.50

A modified monitoring, 

recordkeeping and reporting program 

would reward facilities for 

demonstrating a continued commitment 

to compliance by adjusting the 

frequency or type of monitoring, 

recordkeeping and reporting that is 

required based on the particular 

facility’s compliance record. It may also 

incorporate substitute emission data 

requirements that become increasingly 

more conservative when the facility 

experiences repeated data collection 

failures. This provides an incentive for 

operators to properly maintain and 

operate monitoring systems. 

In sum, we request comment on any 

manner in which the Agency can use 


rmajette on DSK2TPTVN1PROD with PROPOSALS
Federal Register / Vol. 79, No. 108 / Thursday, June 5, 2014 / Proposed Rules 32521 

principles of Next Generation 

Compliance to promote higher rates of 

compliance with requirements we may 

include in a FIP, general permit, or 

other permitting approach for oil and 

natural gas production sources located 

in Indian country. Our objective is to 

promote high rates of compliance 

through cost-effective, incentive-based 

approaches that capitalize on existing 

systems used by the industry, and that 

ensure the availability and transparency 

of compliance information to the public 

and the EPA. 

VIII. Statutory and Executive Order 

Reviews 

Under Executive Order 12866 

Regulatory Planning and Review (58 FR 

51735, October 4, 1993) and Executive 

Order 13563 Improving Regulation and 

Regulatory Review (76 FR 3821, January 

21, 2011), this is not a ‘‘significant 

regulatory action.’’ Because this action 

does not propose or impose any 

requirements, the various statutes and 

Executive Orders that normally apply to 

rulemaking do not apply. Should the 

EPA subsequently determine to pursue 

a rulemaking, the EPA will address the 

statutes and Executive Orders as 

applicable to that rulemaking. 

Because this document does not 

impose or propose any requirements, 

and instead seeks comments and 

suggestions for the Agency to consider 

in possibly developing a subsequent 

proposed rule, the various other review 

requirements that apply when an agency 

imposes requirements do not apply to 

this action. 

The EPA seeks any comments or 

information that would help the Agency 

ultimately to assess the potential impact 

of a rule on small entities pursuant to 

the Regulatory Flexibility Act (RFA) (5 

U.S.C. 601 et seq.); to consider 

voluntary consensus standards pursuant 

to section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA) (15 U.S.C. 272 

note); to consider environmental health 

or safety effects on children pursuant to 

Executive Order 13045, entitled 

‘‘Protection of Children from 

Environmental Health Risks and Safety 

Risks’’ (62 FR 19885, April 23, 1997); or 

to consider human health or 

environmental effects on minority or 

low-income populations pursuant to 

Executive Order 12898, entitled 

‘‘Federal Actions to Address 

Environmental Justice in Minority 

Populations and Low-Income 

Populations’’ (59 FR 7629, February 16, 

1994). 

The Agency will consider such 

comments during the development of 

any subsequent proposed rule. 

List of Subjects in 40 CFR Part 49 

Environmental protection, 

Administrative practices and 

procedures, Air pollution control, 

Indians, Indians-law, Indians-tribal 

government, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

Dated: May 22, 2014. 

Gina McCarthy, 

Administrator. 

[FR Doc. 2014–12951 Filed 6–4–14; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 190 

[EPA–HQ–OAR–2013–0689; FRL 9911–65– 

OAR] 

RIN 2060–AR12 

Environmental Radiation Protection 

Standards for Nuclear Power 

Operations 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Advance notice of proposed 

rulemaking; extension of comment 

period. 

SUMMARY: The U.S. Environmental 

Protection Agency is announcing an 

extension of the public comment period 

for the Advance Notice of Proposed 

Rulemaking (ANPR) requesting public 

comment and information on potential 

approaches to updating the EPA’s 

‘‘Environmental Radiation Protection 

Standards for Nuclear Power 

Operations’’. The EPA published the 

ANPR on February 4, 2014 in the 

Federal Register, which included a 

request for comments on or before June 

4, 2014. The purpose of this action is to 

extend the public comment period an 

additional 60 days. 

DATES: The comment period for the 

advanced notice of proposed 

rulemaking published on February 4, 

2014 (79 FR 6509), is extended. Written 

comments must be received on or before 

August 3, 2014. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2013–0689, by one of the 

following methods: 

• www.regulations.gov: Follow the 

on-line instructions for submitting 

comments. 

• Email: a-and-r-docket@epa.gov. 

• Fax: (202) 566–9744. 

• Mail: U.S. Postal Service, send 

comments to: EPA Docket Center, 

Environmental Radiation Protection 

Standards for Nuclear Power 

Operations—Advance Notice of 

Proposed Rulemaking Docket, Docket ID 

No. EPA–HQ–OAR–2013–0689, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20460. Please include a total of two 

copies. 

Hand Delivery: In person or by 

courier, deliver comments to: EPA 

Docket Center, Environmental Radiation 

Protection Standards for Nuclear Power 

Operations—Advance Notice of 

Proposed Rulemaking Docket, Docket ID 

No. EPA–HQ–OAR–2013–0689, EPA 

West, Room 3334, 1301 Constitution 

Avenue NW., Washington, DC 20004. 

Such deliveries are only accepted 

during the Docket’s normal hours of 

operation, and special arrangements 

should be made for deliveries of boxed 

information. Please include a total of 

two copies. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2013– 

0689. The Agency’s policy is that all 

comments received will be included in 

the public docket without change and 

may be made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or email. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to EPA without going 

through www.regulations.gov your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional information 

about the EPA’s public docket, visit the 

EPA Docket Center homepage at 

www.epa.gov/epahome/dockets.htm. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 


rmajette on DSK2TPTVN1PROD with PROPOSALS