Vol. 78 Friday, 

No. 56 March 22, 2013 

Part III 

Environmental Protection Agency 

40 CFR Part 49 

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; Rule 

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17836 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 49 

[EPA–R08–OAR–2012–0479; FRL–9789–3] 

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 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The EPA is taking final action 

to promulgate a Reservation-specific 

Federal Implementation Plan in order to 

regulate emissions from oil and natural 

gas production facilities located on the 

Fort Berthold Indian Reservation in 

North Dakota. The Federal 

Implementation Plan includes basic air 

quality regulations for the protection of 

communities in and adjacent to the Fort 

Berthold Indian Reservation. The 

Federal Implementation Plan requires 

owners and operators of oil and natural 

gas production facilities to reduce 

emissions of volatile organic 

compounds emanating from well 

completions, recompletions, and 

production and storage operations. This 

Federal Implementation Plan will be 

implemented by the EPA, or a delegated 

tribal authority, until replaced by a 

Tribal Implementation Plan. The EPA 

proposed a Reservation-specific Federal 

Implementation Plan concurrently with 

an interim final rule on August 15, 

2012. This final Federal Implementation 

Plan replaces the interim final rule in all 

intents and purposes on the effective 

date of the final rule. The EPA is taking 

this action pursuant to the Clean Air Act 

(CAA). 

DATES: This final rule is effective on 

April 22, 2013. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–R08–OAR–2012–0479. All 

documents in the docket are listed on 

the www.regulations.gov Web site. 

Although listed in the index, some 

information is not publicly available, 

i.e., CBI or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

www.regulations.gov, or in hard copy at 

the Air Program, Environmental 

Protection Agency (EPA), Region 8, 

1595 Wynkoop Street, Denver, Colorado 

80202–1129. The EPA requests that if at 

all possible, you contact the individual 

listed in the FOR FURTHER INFORMATION

CONTACT section to view the hard copy 

of the docket. You may view the hard 

copy of the docket Monday through 

Friday, 8 a.m. to 4 p.m., excluding 

federal holidays. 

FOR FURTHER INFORMATION CONTACT: 

Deirdre Rothery, U.S. Environmental 

Protection Agency, Region 8, Air 

Program, Mail Code 8P–AR, 1595 

Wynkoop Street, Denver, Colorado 

80202–1129, (303) 312–6431, 

rothery.deirdre@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document, ‘‘we’’, ‘‘us’’, 

and ‘‘our’’ refer to the EPA. 

Definitions 

For the purpose of this document, we are 

giving meaning to certain words or initials as 

follows: 

i. The initials APA mean or refer to the 

Administrative Procedure Act. 

ii. The words or initials Act or CAA mean or 

refer to the Clean Air Act, unless the 

context indicates otherwise. 

iii. The initials BTU mean or refer to British 

Thermal Unit. 

iv. The initials CAFOs mean or refer to 

Consent Agreement Final Orders. 

v. The initials CDPHE mean or refer to 

Colorado Department of Public Health 

and Environment Air Pollution Control 

Division. 

vi. The initials CO mean or refer to carbon 

monoxide. 

vii. The words EPA, we, us or our mean or 

refer to the United States Environmental 

Protection Agency. 

viii. The words Reservation or the initials 

FBIR mean or refer to the Fort Berthold 

Indian Reservation. 

ix. The initials FIP mean or refer to Federal 

Implementation Plan. 

x. The initials GOR mean or refer to gas-tooil ratio. 

xi. The initials LACT mean or refer to lease 

automatic custody transfer. 

xii. The initials MDEQ mean or refer to 

Montana Department of Environmental 

Quality. 

xiii. The initials NAAQS mean or refer to the 

National Ambient Air Quality Standards. 

xiv. The initials NAICS mean or refer to the 

North American Industry Classification 

System. 

xv. The initials NDDoH mean or refer to the 

North Dakota Department of Health. 

xvi. The initials NDIC mean or refer to the 

North Dakota Industrial Commission. 

xvii. The initials NESHAP mean or refer to 

National Emission Standards for 

Hazardous Air Pollutants. 

xviii. The initials NMED mean or refer to 

New Mexico Environment Department 

Air Quality Bureau. 

xix. The initials NOX mean or refer to 

nitrogen oxides. 

xx. The initials NO2 mean or refer to nitrogen 

dioxide. 

xxi. The initials NSPS mean or refer to New 

Source Performance Standards. 

xxii. The initials NSR mean or refer to new 

source review. 

xxiii. The initials ODEQ mean or refer to 

Oklahoma Department of Environmental 

Quality Air Quality Division. 

xxiv. The initials PM mean or refer to 

particulate matter. 

xxv. The initials PSD mean or refer to 

prevention of significant deterioration. 

xxvi. The initials PTE mean or refer to 

potential to emit. 

xxvii. The initials RCT mean or refer to 

Railroad Commission of Texas, Oil and 

Gas Division. 

xxviii. The initials SCADA mean or refer to 

Supervisory Control and Data 

Acquisition. 

xxix. The initials SIP mean or refer to State 

Implementation Plan. 

xxx. The initials SO2 mean or refer to sulfur 

dioxide. 

xxxi. The initials TAR mean or refer to Tribal 

Authority Rule. 

xxxii. The initials TAS mean or refer to 

treatment as state. 

xxxiii. The initials TIP mean or refer to Tribal 

Implementation Plan. 

xxxiv. The initials UDEQ mean or refer to 

Utah Department of Environmental 

Quality. 

xxxv. The initials VOC mean or refer to 

volatile organic compound(s). 

xxxvi. The initials VRU mean or refer to 

vapor recovery unit. 

xxxvii. The initials WDEQ mean or refer to 

Wyoming Department of Environmental 

Quality Air Quality Division. 

Table of Contents 

I. Background 

II. Basis for Final Action 

III. Final Action 

IV. Major Issues Raised by Commenters and 

EPA’s Response 

A. Purpose and Scope of FIP 

B. Legal Basis and Authority 

C. Rule Development and Implementation 

D. Applicability 

E. Control Equipment and Requirements 

F. Monitoring and Recordkeeping 

Requirements 

G. Reporting Requirements 

H. Cost Analysis 

I. Public Notice 

V. Summary of Final Rule and Significant 

Changes From the Proposed and Interim 

Final Rule 

A. Administrative Edits 

B. Introduction 

C. Compliance Schedule 

D. Provisions for Delegation of 

Administration to the Three Affiliated 

Tribes of the Mandan, Hidatsa, and 

Arikara Nation 

E. General Provisions 

F. Construction and Operational Control 

Measures 

G. Control Equipment Requirements 

H. Monitoring Requirements 

I. Recordkeeping Requirements 

J. Reporting Requirements 

K. Effect on Permitting of Facilities 

L. Registration Requirements 

VI. Statutory and Executive Order Reviews 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17837 

1 ‘‘Oil and Natural Gas Sector: New Source 

Performance Standards and National Emission 

Standards for Hazardous Air Pollutants Review, 

Final Rule’’ Federal Register 77:159 (16 August 

2012) p. 49490. The regulations can be accessed at 

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

actions.html and are included in the docket for this 

rule. 

2The Technical Support Document includes a 

more detailed explanation of the development of 

this FIP. It can be found in the docket for this rule, 

Docket ID: EPA–R08–OAR–2012–0479, which can 

be accessed at: http://www.regulations.gov. 

I. Background 

On August 1, 2012, we signed a 

proposed rulemaking to establish a 

Federal Implementation Plan (FIP) for 

oil and natural gas production facilities 

located on the Fort Berthold Indian 

Reservation (FBIR). We also signed an 

interim final rule concurrent with the 

proposed action because we found good 

cause under Section 553(b)(B) of the 

Administrative Procedure Act, 5 U.S.C. 

551 et seq. that notice-and-comment are 

impracticable, unnecessary or contrary 

to the public interest in this instance. 

The proposal and concurrent interim 

final rule were published in the Federal 

Register on August 15, 2012 (77 FR 

48878), and residents of the FBIR, as 

well as industry representatives and 

environmental groups commented on 

the proposed rule. During the 60-day 

comment period that ended on October 

15, 2012, we also held a public hearing 

in New Town, North Dakota on 

September 12, 2012. We received seven 

written comments during the comment 

period and 12 people provided oral 

testimony at the public hearing. This 

Federal Register action announces our 

final action on the proposed regulations. 

In promulgating this rule, the EPA is 

exercising its discretionary authority 

under Sections 301(a) and 301(d)(4) of 

the Clean Air Act (CAA) to promulgate 

regulations as necessary to protect tribal 

air resources. Promulgating this final 

rule addresses an important initial step 

to fill a regulatory gap between state and 

federal requirements with regard to 

controlling volatile organic compound 

(VOC) emissions from oil and natural 

gas operations on the FBIR. There is no 

other federal rule, including the recently 

finalized New Source Performance 

Standards (NSPS) and National 

Emissions Standards for Hazardous Air 

Pollutants (NESHAP) for the Oil and 

Natural Gas Sector (NSPS OOOO and 

NESHAP HH),1 that establishes 

regulations for the particular oil and 

natural gas production operations that 

exist on the FBIR. This is in contrast to 

oil and natural gas operations off the 

Reservation, which are governed by the 

North Dakota Department of Health 

(NDDoH) regulations and North Dakota 

Industrial Commission (NDIC) 

regulations within the State of North 

Dakota’s jurisdiction. The NDDoH 

requirements were developed with an 

understanding of the high VOC 

emissions and infrastructure constraints 

that exist in the region. Consistent with 

the regulatory structure that exists off 

the FBIR, and NSPS OOOO, this rule 

has requirements for VOC emissions 

control and reductions, monitoring, 

recordkeeping, and reporting. This rule 

also establishes requirements that are 

clear and legally and practicably 

enforceable. 

We developed this rule in 

consultation with the Three Affiliated 

Tribes of the Mandan, Hidatsa, and 

Arikara Nation. As part of this 

consultation, we evaluated the oil and 

natural gas activities and sources of 

VOC emissions that could impact air 

resources on the Reservation and the 

differences in the VOC emission 

reduction requirements for those 

facilities operating on the FBIR 

compared to those facilities operating in 

NDDoH jurisdiction. The final rule we 

are promulgating today establishes 

regulations for oil and natural gas 

production and storage operations 

specific to the FBIR and applies to all 

lands on the FBIR, which is defined by 

the Act of March 3, 1891 (26 Statute 

1032) and which includes all lands 

added to the Reservation by Executive 

Order of June 17, 1982. 

We drafted the requirements that are 

consistent to the greatest extent 

practicable with the most relevant 

aspects of neighboring state and local 

rules concerning the air pollutant 

emitting activities on the FBIR. We do 

not intend, nor do we expect, this 

regulation to impose significantly 

different regulatory burdens upon 

industry or the residents of the FBIR 

than those imposed by the rules of state 

and local air agencies in the 

surrounding areas. We evaluated the 

regulations imposed by other oil and 

natural gas producing state 

jurisdictions, NDDoH, NDIC, and NSPS 

OOOO. Included in the docket for this 

rule are copies of the regulations and 

guidance that we considered in this 

process, as well as a technical support 

document 2 (TSD) explaining the 

requirements. 

We requested comments on all 

aspects of our proposed action and 

provided a 60-day comment period. 

During the comment period, we 

received comments on our proposed 

rule that supported our proposed action 

and that were critical of our proposed 

action. After evaluating all the 

comments that were received, we are 

taking final action to respond to the 

comments we have received, explain the 

basis for our action, and promulgate the 

final rule. In this final rule, also referred 

to as the Federal Implementation Plan 

for Oil and Natural Gas Well Production 

Facilities; Fort Berthold Indian 

Reservation (Mandan, Hidatsa, and 

Arikara Nation), North Dakota, we are 

making certain revisions based on the 

information provided by commenters 

and regulated entities. This preamble to 

the final rule responds to the issues 

raised by commenters and describes the 

final rule and significant changes from 

the proposed rule. 

II. Basis for Final Action 

This Federal Register action 

announces the EPA’s final action on the 

proposed regulations of August 15, 

2012. In promulgating this rule, the EPA 

is exercising its discretionary authority 

under Sections 301(a) and 301(d)(4) of 

the CAA to promulgate such 

implementation plan provisions as are 

necessary or appropriate to protect air 

quality within the FBIR, specifically 

identified in 40 CFR part 49, subpart 

K—Implementation Plans for Tribes— 

Region VIII. After evaluating air quality 

issues for the FBIR, the EPA was 

concerned that there was a gap in air 

quality requirements for oil and natural 

gas production facilities on the FBIR 

under the CAA and its implementing 

regulations. 

Our proposed rule in August 2012 

was generally based upon the aspects of 

neighboring NDIC and NDDoH 

regulations most relevant to the oil and 

natural gas production VOC-emitting 

activities occurring on the FBIR. We 

acknowledged that there were some 

differences between the requirements in 

the proposed rule and those in the NDIC 

and NDDoH regulations, most notably 

additional monitoring requirements. 

These differences were necessary to 

meet the standards for promulgating 

FIPs. Included in the docket for the 

proposed rulemaking were copies of all 

of the state rules that the EPA 

considered in this process, as well as a 

TSD comparing the proposed 

regulations with the state regulations 

and a description of why the EPA 

believed the proposed rule was 

appropriate. 

During the public comment period, a 

number of FBIR residents, industry 

representatives and the regulated 

entities, environmental and resident 

advocate organizations, and tribal 

government agencies submitted 

comments on the rule proposed by the 

EPA and offered suggestions for 

improving the proposed rule. We have 

fully considered all substantive public 

comments on our proposal and have 

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17838 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

3Commenter cites ‘‘EPA Tribal Science Council, 

Tribal Science Priority’’ at 1 (June 2011). A copy of 

the document is included in the docket for this rule, 

Docket ID: EPA–R08–OAR–2012–0479, which can 

be accessed at: http://www.regulations.gov. 

concluded that certain changes are 

warranted. Those changes are discussed 

in Section V of this notice. However, the 

EPA does not intend, nor does it expect, 

these regulations to impose significantly 

different regulatory burdens upon 

industry or the residents within the 

FBIR than those imposed by the rules of 

the NDIC and NDDoH in the 

surrounding areas. 

III. Final Action 

In this action, we are promulgating a 

Reservation-specific FIP to establish 

enforceable control requirements for 

reducing VOC emissions from oil and 

natural gas production activities on the 

FBIR in North Dakota. This final rule 

replaces the interim final rule 

promulgated on August 15, 2012 (77 FR 

48878) in all intents and purposes on 

the effective date of the final rule. 

IV. Major Issues Raised by Commenters 

and EPA’s Response 

A. Purpose and Scope of FIP 

Comment: Multiple commenters 

described the ways in which the 

existing oil and natural gas development 

had negatively affected their 

communities. For example, commenters 

described black smoke, visible soot, and 

strong gas odors. Other commenters 

expressed support of the EPA’s decision 

to cover existing wells in the FIP. 

Response: We acknowledge the 

concerns expressed by the commenters 

related to oil and natural gas production 

activities on the FBIR. The purpose of 

this FIP, in part, is to address the 

potential impacts of VOC emissions 

caused by the oil and natural gas 

production occurring in the region. By 

requiring process equipment at oil and 

natural gas production facilities to be 

operated with specific air emission 

controls, under specific operating 

conditions and following specific 

procedures, this FIP will help address 

these concerns. We are requiring that 

operations at these facilities be 

monitored and records be kept such that 

any improper process or emission 

control equipment operated by the 

owner or operator at a facility can be 

identified and remedied by the EPA 

through enforcement of this FIP. The 

public can report possible harmful 

environmental activity on the EPA’s 

Web site at http://www.epa.gov/tips/. 

We acknowledge the commenters 

support of the FIP to cover existing 

wells. As discussed in the TSD, one goal 

of this FIP was to provide an avenue of 

compliance with the CAA for those 

companies subject to CAFO agreements. 

Our primary goal, as always is with 

regard to regulations developed under 

the CAA, was to ensure increased 

protection to the public health and the 

environment. This FIP provides these 

benefits through promulgation of 

enforceable requirements to limit VOC 

emissions from facilities that 

constructed prior to the effective date of 

the interim final FIP. 

Comment: One commenter stated that 

the EPA needs to control air quality 

because hydraulic fracturing 

(‘‘fracking’’) is under-regulated. 

Response: The majority of oil and 

natural gas wells drilled today are 

hydraulically fractured. Hydraulic 

fracturing occurs when wells are being 

completed and recompleted. NSPS 

OOOO ensures that VOC emissions are 

controlled from the completion and 

recompletion of natural gas wells. 

Additionally, this FIP requires that 

owners and operators of oil and natural 

gas production facilities on the FBIR 

reduce by at least 90% the VOC 

emissions from casinghead natural gas 

during the completion or recompletion 

of any oil and natural gas well. 

Together, these recent regulatory actions 

will provide significant control of 

emissions from hydraulic fracturing 

activities. 

Comment: Several commenters stated 

that the EPA should set methane 

standards in the final FIP noting that 

methane is a greenhouse gas (GHG) with 

a high carbon dioxide (CO2) equivalent, 

and that leaked methane therefore 

negatively influences climate change. 

These same commenters also stated that 

the EPA already requires control 

technologies that could facilitate 

emissions standards for methane and 

that tribes have particular interest in 

mitigating climate change because they 

are disproportionately impacted by it.3

The commenters also stated that leaked 

methane decreases a potentially 

significant revenue stream for 

producers. Another commenter stated 

that flaring creates significant CO2

pollution, which contributes to climate 

change. 

Response: We had a very specific 

purpose for developing this FIP, which 

was to regulate VOC emissions from oil 

and natural gas production operations 

on the FBIR which represented the 

largest source of air quality concerns at 

this time. While this rule does not 

directly regulate other pollutants subject 

to regulation under the CAA, such as 

the GHGs methane and CO2, it does 

result in significant reductions of GHGs 

because of the substantial methane 

reduction as a co-benefit of the required 

VOC control. 

Comment: Other commenters 

expressed concern about the dust now 

prevalent in the area. The commenters 

stated that excessive dust was often seen 

in the air as well as on trees and grass. 

Some commenters insisted that oil and 

trucking companies should participate 

in control of dust in the area. One 

commenter stated that visible emissions 

have not been responded to by the EPA 

or the Three Affiliated Tribes of the 

Mandan, Hidatsa, and Arikara Nation. 

Response: This FIP is focused on 

emissions of VOCs, and regulating 

fugitive dust resulting from oil and 

natural gas production activities on the 

FBIR was not within the scope of the 

rulemaking. If the EPA determines it is 

necessary to regulate other pollutants, 

we will address those at that time. 

Generally, dust from road traffic is a 

local issue and the public should 

contact the local environmental or 

health agency with these concerns. The 

public can report possible harmful 

environmental activity on the EPA’s 

Web site at http://www.epa.gov/tips/. 

Comment: Several commenters noted 

a significant increase in truck traffic 

since oil and natural gas production on 

the FBIR had begun. One commenter 

noted that the incidence of traffic 

accidents, often fatal, has significantly 

increased on the FBIR since production 

has begun. 

Response: Traffic in North Dakota and 

on the FBIR is regulated by the Three 

Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nation or the 

United States Department of 

Transportation, and not by the EPA and 

thus is not within the EPA’s authority 

to address. 

Comment: One commenter discussed 

being bothered by noticeable diesel 

emissions from the increased truck 

traffic. Another commenter noted that 

an oil rig was polluting in close 

proximity to a school. 

Response: This FIP does not regulate 

the exhaust emissions from the trucks or 

oil rigs. These sources of emissions meet 

the definition of on-road and non-road 

motor vehicles (mobile sources) under 

the CAA and are subject to regulations 

under those provisions. This FIP only 

regulates stationary oil and natural gas 

production sources. A stationary source 

is defined in the CAA (42 U.S.C. 

7602(z)) to mean ‘‘generally any source 

of an air pollutant.’’ The definition 

specifically excludes those emissions 

resulting directly from an internal 

combustion engine for transportation 

purposes or from a nonroad engine or 

nonroad vehicle as defined in 42 U.S.C. 

7550. This rule however does not 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17839 

4 Information on the EPA’s Natural Gas STAR 

Program is available online at: http://www.epa.gov/ 

gasstar/, Accessed November 15, 2012. 

5Commenter references the interim final rule at 

77 FR 48886. 

6The FBIR CAFOs are included in the docket for 

this rule, Docket ID: EPA–R08–OAR–2012–0479, 

which can be accessed at: http:// 

www.regulations.gov. 

exempt the owners and operators from 

any other requirements under the CAA 

to minimize pollutants and control 

emissions from these sources. 

Comment: Some commenters stated 

that oil and natural gas development 

had also negatively impacted water 

quality. One commenter stated that the 

water at her house is undrinkable and 

is often too poor to be used for other 

common functions like laundry. Some 

commenters stated that they had 

witnessed trucks dumping waste from 

oil and natural gas production in 

unauthorized locations, including the 

ground near Skunk Bay. 

Response: We acknowledge the 

concerns expressed by the commenters 

in regard to the effect that oil and 

natural gas production activities may 

have on water quality. Our authority to 

issue this rule, however, falls under the 

CAA. Water pollution on the FBIR is 

addressed through separate regulations 

established under the Clean Water Act 

(CWA). Additional information about 

the CWA can be found at http:// 

www.epa.gov/regulations/laws/ 

cwa.html. In addition, the public can 

report possible harmful environmental 

activity on the EPA’s Web site at http:// 

www.epa.gov/tips/. 

Comment: One commenter 

recommended that the EPA explore 

voluntary partnerships with FBIR 

producers in order to deploy best 

practices for gas capture and use. 

Commenter stated that this may allow 

FBIR producers to demonstrate the 

feasibility and benefits of 

comprehensive gas capture at coproducing sites, and in doing so 

encourage these practices for other 

producers in the Bakken and elsewhere. 

Response: We appreciate the 

commenter’s suggestion; however, such 

a partnership is outside of the scope of 

this FIP and 40 CFR part 49. The 

comment is more appropriately 

addressed through the EPA’s voluntary 

programs, such as the Natural GasSTAR 

Program.4 Therefore we have forwarded 

this comment on to the Natural 

GasSTAR Program for their 

consideration. 

B. Legal Basis and Authority 

Comment: Some commenters 

disagreed with our assertion that the 

rule is needed and justified to mitigate 

hazards to the public health and the 

environment, stating that actual 

emissions are much lower than 

potential emissions, and are low enough 

to present no hazard to public health or 

the environment. The commenters 

further stated that rather than the 

protection of the public health and 

environment, the purpose of this FIP is 

to solve the ‘‘legal and hypothetical 

problem’’ of ensuring potential 

emissions do not exceed regulatory 

applicability thresholds, such as the 

PSD thresholds. The commenters stated 

that the EPA proposed the FIP not to 

improve already good air quality5 or to 

satisfy CAA requirements, but because 

many FBIR operators need 

preconstruction permits and the EPA 

lacks adequate time or resources to issue 

those permits by the time the Consent 

Agreement and Final Orders (CAFOs) 6

governing the sources expire. 

Several commenters support the 

proposed FIP and also agree that we 

have just cause to mitigate hazards to 

the public health and the environment 

and with our assertion and that we are 

acting in accordance with our trust 

responsibilities to protect the public 

health and environment in Indian 

country. 

Response: The purpose of this FIP is 

to address potential impacts to the 

public health and the environment. It 

also solves some of the unusual 

challenges that owners and operators on 

the FBIR face with regard to compliance 

with the permitting requirements of the 

CAA. However, our primary purpose for 

developing rules to regulate air 

emissions is to meet the requirements of 

the CAA to protect the public health 

and the environment by providing those 

living on the Reservation the same level 

of air quality and health protection as 

people living outside the Reservation. 

So, while this FIP solves some of the 

challenges that the owners and 

operators on the FBIR face with regard 

to requirements of the CAA, or more 

specifically the PSD permitting 

requirements, the primary focus is to 

prevent the potential degradation of the 

air quality on the FBIR. 

The CAA is a comprehensive federal 

law that regulates air emissions from 

stationary and mobile sources. Among 

other things, this law authorizes us to 

establish National Ambient Air Quality 

Standards (NAAQS) to protect public 

health and the environment. 

Amendments to the CAA codified the 

PSD preconstruction permitting 

program to protect the public health and 

the environment from any actual or 

potential adverse effects which may 

reasonably be anticipated to occur 

notwithstanding attainment and 

maintenance of the NAAQS. 

Because of the high quantity of VOC 

emissions present in the oil and natural 

gas operations in the Bakken formation, 

the absence of infrastructure to capture 

excess volatile liquids, and the 

regulatory gap that rendered the use of 

control technology unenforceable prior 

to the FIP, some sources had potential 

emissions that would have required 

major source permits. These 

preconstruction PSD permits are one 

mechanism available to the EPA to 

assure that emissions increases 

associated with economic development 

do not threaten the NAAQS. Under the 

Federal Tribal NSR rule, sources located 

on the FBIR may also obtain synthetic 

minor NSR permits to limit their 

emissions below major source levels. 

Either of these options would require 

that the EPA review and issue several 

hundred air permits to emissions 

limitations similar to those required by 

this FIP. We determined, therefore, that 

issuing this FIP, and imposing emission 

limitations for these sources at one time 

was a more efficient and streamlined 

mechanism than issuing individual 

permits. We believe that this is the best 

way to address the potential harm that 

these previously unregulated VOC 

emissions would create, and ensure that 

we are not inhibiting the growth of oil 

and natural gas due to the permitting 

process, which could put the Tribe at an 

economic disadvantage. 

Finally, while actual emissions for 

some sources may be lower than 

potential emissions, there are no 

federally and practicably enforceable 

emission control requirements for the 

affected equipment limiting the 

potential to emit. This rule imposes 

emission limitations that are federally 

and practicably enforceable. 

Comment: Several commenters stated 

that by proposing to adopt this FIP, the 

EPA is stepping into the shoes of the 

Tribes and acting as the local air 

pollution control authority. The FIP 

includes a comprehensive set of control 

measures for oil and natural gas 

operations—imposing requirements on 

such operations merely because they 

exist and not because they have engaged 

in an activity that triggers a regulatory 

requirement, such as building a new 

source or modifying an existing source 

such that a PSD permit or a synthetic 

minor NSR permit is needed. In other 

words, the EPA is adopting what would 

otherwise amount to a State 

Implementation Plan (SIP) or TIP for the 

FBIR. The authority for such a control 

program necessarily flows from section 

110(a), which specifies the measures 

that a SIP may include. This section of 

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17840 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

7Section 49.11(a) states that the Agency, ‘‘[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.’’ 40 CFR 49.11(a). 

the CAA specifies that a SIP may 

‘‘include enforceable emission 

limitations and other control measures, 

means, or techniques * * * as may be 

necessary or appropriate to meet the 

applicable requirements of this 

chapter.’’ CAA section 110(a)(2)(A) 

(emphasis added). Thus, the EPA may 

adopt as part of this FIP only those 

measures that are needed to attain or 

maintain NAAQS or to meet other 

specified CAA applicable requirements. 

Response: We disagree; the 

commenter is mistaken that the 

underlying authority for this FIP is 

found in Section 110(a) of the Act. 

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 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’’ 

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

Our regulations delineate the CAA 

provisions for which it is appropriate to 

treat tribes in the same manner as a 

state. See 40 CFR 49.3, 49.4. Among 

those provisions for which we 

determined such treatment was 

inappropriate are CAA section 110(a)(1) 

(SIP submittal and implementation 

deadlines) and CAA section 110(c)(1) 

(directing the EPA to promulgate a 

Federal Implementation Plan (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). 

See 40 CFR 49.4(a), (d); 63 FR 7262– 

7266, 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 7265, 

February 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 reasonable time.’’ Id. (referencing 

§ 49.11(a) which provides that the 

Agency will promulgate a FIP to protect 

tribal air quality within a reasonable 

time if tribal efforts do not result in 

adoption and approval of tribal plans or 

program).7

The preamble to the TAR set forth our 

view articulated in the proposed rule 

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 63 FR 7262. 

It further discussed our 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. 

The NDDoH, the CAA permitting 

authority for areas of North Dakota 

outside of Indian country, including 

outside of the FBIR, has promulgated 

rules to control emissions from oil and 

natural gas production facilities. Since 

there is not currently an approved TIP 

specifically covering the reduction of 

VOC emissions related to natural gas 

emissions from oil and natural gas 

production facilities on the FBIR, a lack 

of regulation exists with regard to such 

facilities operating within the exterior 

boundaries of the Reservation. This FIP 

establishes legally and practicably 

enforceable requirements to control and 

reduce VOC emissions. Therefore, in 

this rule, we determined that it is 

necessary and appropriate to exercise 

our discretionary authority under 

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

and 40 CFR 49.11(a) to promulgate a FIP 

to remedy an existing regulatory gap 

under the Act with respect to oil and 

natural gas operations on the FBIR. 

Comment: One commenter was 

concerned that the Tribe would have 

enforcement authority and be allowed to 

act arbitrarily and capriciously with 

regard to shutting down operations and 

requested that the requirements of this 

rule be enforced by the federal 

government. The commenter stated that 

the Three Affiliated Tribes of the 

Mandan, Hidatsa, and Arikara Nation 

should not be allowed to enforce the 

rule because its elected officials have 

economic interest in the oil and natural 

gas industry, making them conflicted. 

Response: At this time, EPA has not 

delegated to the Three Affiliated Tribes 

of the Mandan, Hidatsa, and Arikara 

Nation the authority under these 

regulatory provisions to enforce the 

provisions of this FIP. The provisions in 

§ 49.4162 of the Code of Federal 

Regulations establish the steps by which 

the Three Affiliated Tribes of the 

Mandan, Hidatsa, and Arikara Nation 

may request delegation to assist us with 

the administration of this rule. As 

described in the regulatory provisions 

and the preamble to the proposed rule, 

any such delegation will be 

accomplished through a delegation of 

authority agreement between the EPA 

Region 8 Administrator and the Three 

Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nation. In the 

event such an agreement is reached, the 

rule would continue to operate under 

federal authority throughout the FBIR, 

and the Three Affiliated Tribes of the 

Mandan, Hidatsa, and Arikara Nation 

would assist us with administration of 

the rule to the extent specified in the 

delegation agreement. 

C. Rule Development and 

Implementation 

Comment: One commenter indicated 

that the State of North Dakota was 

issuing permits to drill on the FBIR and 

asserted that the State has been giving 

out drilling permits ‘‘like candy,’’ 

leading to an overwhelming level of oil 

and natural gas development and 

increase in pollution on the FBIR. The 

commenter stated that the Tribe did not 

have, nor did they develop, necessary 

regulations when development began, 

and that the Tribe, as well as the EPA, 

is now playing ‘‘catch-up.’’ 

Response: We acknowledge the 

commenter’s concern with increased oil 

and natural gas development on the 

FBIR, as well as increased development 

under the State of North Dakota’s 

jurisdiction and the need for 

reservation-specific regulations to 

protect public health and the 

environment. We note that the State of 

North Dakota does not have jurisdiction 

over development on the FBIR. As 

discussed in the preamble for the 

interim final rule, we first became aware 

of the need to address VOC emissions 

from these operations in August of 2011. 

At that time, a significant number of 

entities engaged in oil and natural gas 

operations on the FBIR informed us that 

the emissions of regulated air 

pollutants, including VOC, were 

significantly larger than previously 

understood and larger than emissions in 

other areas, due to the geologic 

characteristics and infrastructure 

challenges in the Bakken formation. At 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17841 

8The commenter is referring to the interim final 

rule Section III.E. ‘‘Effect on Permitting of 

Facilities.’’ (77 FR 48885). 

that time, we immediately took 

measures to ensure that VOC emissions 

were appropriately controlled by 

entering into CAFOs with the owners/ 

operators to implement VOC controls. 

We then developed and promulgated 

this FIP as an interim final rule to 

immediately establish federally and 

practicably enforceable emission control 

requirements for the affected 

equipment. In addition, given the 

number of existing facilities that were 

operating as unregulated sources, we 

determined that existing facilities 

should also be subject to the FIP. We 

believe the series of actions taken to 

address the unregulated sources of VOC 

emissions on the FBIR occurred as soon 

as practicable after becoming aware of 

the issue. 

Comment: One commenter stated that 

the EPA had accelerated development of 

this FIP without consideration of its 

impact on the community to avoid 

disrupting the pace of oil and natural 

gas development. Another commenter 

stated that this FIP is not strict enough, 

citing the estimated potential long-term 

development of 1,000 oil and natural 

gas facilities by 2029 as discussed in the 

interim final rule (77 FR 48887). 

Response: We disagree with the 

assertion that the expedited process for 

developing this FIP did not take into 

consideration the impacts of oil and 

natural gas development on the 

community. The mitigation of the air 

quality impact of oil and natural gas 

development on the FBIR was a priority 

when developing this rule. This rule 

will reduce VOC emissions from 

existing operations and limit the 

amount of VOC emissions from 

potential new development. Our intent 

is to level the health protections 

between the residents living on the FBIR 

and the residents living in the State of 

North Dakota. In other words, the EPA 

intends that the FBIR residents receive 

equivalent air quality protections as 

those residing in the State. We acted 

quickly in developing this FIP in order 

to provide those protections as soon as 

possible and avoid unnecessary 

disruption to oil and natural gas 

development. While the FIP 

development process has been quick, as 

discussed in this notice we have 

provided for full public participation 

and fully responded to all concerns. 

We also disagree that the FIP is not 

strict enough. This FIP establishes 

requirements to control air pollution in 

the form of VOC emissions from oil and 

natural gas production and storage 

operations on the FBIR, comparable to 

those requirements developed by state 

permitting authorities. In addition, this 

FIP imposes emission reduction 

requirements that are robust and 

consistent with the control technology 

requirements for the oil and natural gas 

production and storage industry under 

NSPS OOOO. 

Comment: One commenter stated that 

an environmental impact statement 

(EIS) was not required prior to leasing 

the tribal land for oil and natural gas 

development. The commenter noted 

that a programmatic environmental 

assessment (EA) is being conducted, but 

insisted that the more rigorous EIS 

should have been required. The 

commenter questioned whether it was 

legal for the EIS requirement to be 

bypassed, and stated that the 

requirements of the National 

Environmental Policy Act (NEPA) had 

been ‘‘minimized.’’ Therefore, the 

commenter asserted that area residents 

were denied the opportunity to make 

statements regarding the impact of oil 

and natural gas development on their 

lives. Another commenter stated that 

the lack of adequate public notice for 

the EA was not compliant with NEPA 

and environmental justice. 

Response: This FIP only regulates the 

VOC air pollutant emissions generated 

by the well completion and production 

and storage operations on the FBIR and 

is not subject to the requirements of 

NEPA (EIS or EA). A FIP is an action 

under the CAA and Section 7(c) of the 

Energy Supply and Environmental 

Coordination Act of 1974 (15 U.S.C. 

793(c)(1)) exempts actions under the 

CAA from the requirements of NEPA, 

specifically this section reads ‘‘* * * (c) 

Major federal actions significantly 

affecting the quality of the human 

environment (1) No action taken under 

the Clean Air Act [42 U.S.C. 7401 et 

seq.] shall be deemed a major Federal 

action significantly affecting the quality 

of the human environment within the 

meaning of the National Environmental 

Policy Act of 1969 [42 U.S.C. 4321 et 

seq.].’’ Therefore a NEPA analysis is not 

required for this FIP. 

Leasing of the mineral rights and 

drilling of the oil and natural gas wells 

is regulated by the Bureau of Indian 

Affairs (BIA) and the Bureau of Land 

Management (BLM). Those federal 

agencies are undertaking any applicable 

NEPA requirements when approving 

leasing and drilling activities. 

Comment: Many commenters asserted 

that this FIP falls short of its stated 

purpose because some facilities’ 

potential to emit (PTE) of VOCs or any 

other regulated NSR pollutant may 

exceed the applicability thresholds for 

PSD permitting resulting in the need for 

a synthetic minor NSR permit issued 

under Federal Tribal NSR Rule (if PSD 

permitting is to be avoided) even after 

applying the legally and practicably 

enforceable emission reductions 

provided in this rule (77 FR 48885). 

Several commenters stated that the EPA 

should declare in the final FIP that all 

sources that become minor under the 

Federal Tribal NSR rule will be 

considered ‘‘true minor’’ sources. More 

specifically, commenters claim that 

sources treated as synthetic minor 

sources under this FIP could not install 

new wells for the foreseeable future 

because the EPA has not developed an 

expeditious process for issuing 

synthetic minor NSR permits. 

Another commenter questioned why 

owners and operators working within 

the FBIR would be allowed to exceed 

VOC emission standards.8 The 

commenter asked if there was any point 

in setting these standards if permits 

could be obtained to exceed them. 

Response: The owners and operators 

subject to this FIP are not allowed to 

exceed established standards, and 

nothing in this FIP is intended to relieve 

the owners and operators of the 

responsibility to comply with all federal 

environmental laws and rules. This rule 

does not replace any requirement to 

obtain permission to construct under 

the PSD regulations at 40 CFR 52.21 or 

the Federal Tribal NSR regulations at 40 

CFR 49.151; therefore, this FIP does not 

automatically create ‘‘true minor’’ status 

for those sources that become minor 

under the Federal Tribal NSR Rule. 

Owners and operators complying with 

this rule may still be required to obtain 

preconstruction permits to further 

reduce VOC emissions or the emissions 

of other pollutants that are regulated by 

the PSD and Federal Tribal NSR 

permitting regulations if the emissions 

thresholds for these regulations are 

exceeded. Further, this rule does not 

automatically make sources synthetic 

minor sources for purposes of the PSD 

regulations. A synthetic minor source is 

generally understood to include any 

source that would be major but for a 

requested enforceable limitation. For 

example, a source can become a 

synthetic minor source when the owner 

or operator requests a synthetic minor 

NSR permit through the Federal Tribal 

NSR regulations to avoid major source 

requirements of PSD and that request is 

approved and the permit is issued. 

This rule is similar to NSPS OOOO 

promulgated at 40 CFR part 60, 

NESHAP HH promulgated at 40 CFR 

part 63, and the NDDoH regulations 

specific to oil and natural gas 

production operations at Chapters 33– 

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17842 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

9Summit Petroleum Corp. v. EPA, Nos. 0904348, 

10–4572 (Sixth Cir. 2012) at 1. The document is 

included in the docket for this rule, Docket ID: 

EPA–R08–OAR–2012–0479, which can be accessed 

at: http://www.regulations.gov. 

10Memo from Stephen D. Page, Director, Office of 

Air Quality Planning and Standards, to Regional Air 

Division Directors, Regions 1–10, Applicability of 

the Summit Decision to EPA Title V and NSR 

Source Determinations (Dec. 21, 2012), available at 

http://epa.gov/nsr/documents/SummitDecision.pdf 

and included in the docket for this rule, Docket ID: 

EPA–R08–OAR–2012–0479, which can be accessed 

at: http://www.regulations.gov. 

11Commenter specifically mentions the ‘‘New 

Source Performance Standards for Crude Oil and 

Natural Gas Production, Transmission and 

Distribution’’ (40 CFR part 60, subpart OOOO) and 

the ‘‘Greenhouse Gas Reporting Rule’’ (40 CFR part 

98, subpart W). 

12The Bakken Pool is defined as a compilation of 

crude oil formations consisting of Bakken, Sanish 

and Three Forks formations. 

13Bakken Pool Oil and Gas Production Facilities 

Air Pollution Control Permitting & Compliance 

Guidance, NDDoH Air Quality Division, May 2, 

2011. This guidance document was developed by 

the Bakken VOC Task Force. The Bakken VOC Task 

Force was a collaboration between the NDDoH and 

the owners and operators of oil and gas operations 

producing from the Bakken Pool. A copy of the 

guidance document is included in the docket for 

this rule, Docket ID: EPA–R08–OAR–2012–0479, 

which can be accessed at: http:// 

www.regulations.gov. 

15–07 and 33–15–20 of the North 

Dakota Administrative Code, none of 

which replace CAA permitting 

requirements. Similar to the NSPS, 

NESHAPs, and NDDoH regulations, this 

rule provides legally and practicably 

enforceable restrictions for VOC 

emissions on an emission unit specific 

basis. Any reductions realized by 

complying with this rule can then be 

used to calculate the PTE of VOCs when 

determining whether any CAA 

permitting may be required. In addition, 

the rule only requires controls on VOC 

emissions, because of the high amount 

of associated natural gas in the crude oil 

from the FBIR and the absence of 

infrastructure to capture the natural gas 

emissions. Therefore, any potential 

emissions of VOCs or any other criteria 

pollutant that exceed the PSD 

permitting thresholds after taking credit 

for the enforceable restrictions in this 

rule would still result in the 

requirement to obtain a PSD permit for 

permission to construct. A synthetic 

minor NSR permit to avoid the PSD 

permitting requirements can still be 

requested through the Federal Tribal 

NSR regulations. Those facilities with 

potential emissions of VOCs and all 

other criteria pollutants that are below 

the PSD permitting thresholds and 

above the Federal Tribal NSR permitting 

thresholds after complying with the 

requirements of this FIP would be 

considered true minor sources under the 

Federal Tribal NSR regulations. 

Finally, regarding the commenter’s 

claim that sources treated as synthetic 

minor sources under this FIP could not 

install new wells for the foreseeable 

future because the EPA has not 

developed an expeditious process for 

issuing synthetic minor permits, the 

EPA has issued and continues to issue 

synthetic minor permits to sources on 

the FBIR to those who request them. 

Comment: Several commenters 

requested that the EPA clarify that a 

stationary source and corresponding 

minor NSR permitting requirements 

apply to operations and equipment on a 

well pad and immediately appurtenant 

operations. These commenters also 

urged the EPA to clarify that 

geographically separated ‘‘well pads and 

related operations’’ should not be 

aggregated into one stationary source 

simply because they are connected by 

gathering or production lines. The 

commenters asserted that the EPA’s use 

of the term ‘‘integrally connected’’ (77 

FR 48885) could create confusion as to 

what equipment and activities are 

considered part of a facility. The 

commenters cited Summit Petroleum 

Corp. v. EPA 9 as an example of the EPA 

incorrectly aggregating multiple wells, 

well pads and related facilities that were 

geographically widespread into one 

single facility for the purposes of the 

CAA. The commenters stated that such 

an approach is ‘‘nonsensical’’ and 

inconsistent with the CAA definition of 

‘‘stationary source.’’ The commenters 

also requested that the EPA explain the 

limited circumstances in which 

aggregation into a ‘‘facility’’ or 

‘‘stationary source’’ is appropriate, and 

suggested the following as those 

circumstances; When: (1) The 

operations share a single two-digit major 

SIC code; (2) the operations are under 

common ownership or control; and (3) 

the operations are physically contiguous 

or physically proximate. The EPA 

should specify that functional 

interrelatedness should not be used to 

determine physical proximity. 

Response: This action affects facilities 

operating on the FBIR in North Dakota, 

and thus the 6th Circuit’s Summit 

Petroleum decision cited by the 

commenters does not apply.10 When the 

EPA issues permits to sources that are 

also subject to this rule, the ultimate 

determination regarding the scope of the 

stationary source to be permitted will be 

made by implementing the stationary 

source definition contained in the 

federal NSR and Title V regulations (40 

CFR 52.21(b)(5) and (6), 71.2). Such 

determinations are highly fact specific 

and will continue to be made on a caseby-case basis, applying the relevant 

regulatory criteria to the facts of the oil 

and natural gas production activities 

being permitted. 

Comment: Several commenters stated 

that the final FIP should refer to Bakken 

Pool wells located on the FBIR simply 

as ‘‘oil wells’’ or ‘‘Fort Berthold Indian 

Reservation wells’’ rather than using the 

phrases ‘‘oil and natural gas production 

wells’’ or ‘‘oil and natural gas 

production facilities.’’ The commenters 

asserted that using the characterization 

‘‘oil wells’’ is consistent with related 

EPA rules.11 One commenter also stated 

that North Dakota permits refer to these 

as oil wells. On the other hand, two 

commenters stated that they support the 

inclusion of co-producing oil and 

natural gas wells, which are defined as 

‘‘oil and natural gas production 

facilities’’ in this FIP. 

Response: The reference to the 

Bakken Pool 12 production facilities as 

oil and natural gas production facilities 

in this FIP is consistent with: (1) 

NDDoH regulations at 33–15–20 which 

defines an oil well as ‘‘any well capable 

of producing oil or oil and casinghead 

gas from a common source of supply’’; 

and (2) the NDDoH’s Bakken Pool 

Guidance 13 (Bakken Pool Guidance) 

which refers to the facilities as oil and 

gas production facilities, both of which 

form the basis of this rule. We believe 

this reference adequately describes the 

affected facilities under the FIP and is 

consistent with NDDoH regulations and 

guidance. 

We acknowledge the commenter’s 

assertions that the facilities may be 

described differently in other EPA 

regulations. Although the Bakken Pool 

production wells on the FBIR would be 

considered oil wells based on the 

discussions in NSPS OOOO and 

Subpart W (76 FR 80567), those 

discussions do not adequately reflect 

the volume of natural gas coproduced 

from a Bakken Pool well. NSPS OOOO 

and Subpart W are national rules, and 

therefore, the discussions they contain 

must be broad enough to apply 

nationwide. Since this a reservationspecific FIP, we believe it is appropriate 

to use a more focused definition, as did 

the State of North Dakota in the Bakken 

Pool Guidance, due to the unique nature 

of the oil being produced from the 

Bakken Pool. 

D. Applicability 

Comment: Several commenters stated 

that the FIP should establish a 

minimum emissions threshold for 

applicability, which exists in NSPS 

OOOO. 

Response: The only minimum 

emission threshold for applicability that 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17843 

14The applications can be found in the docket for 

this rule, Docket ID: EPA–R08–OAR–2012–0479, 

which can be accessed at http:// 

www.regulations.gov. 

15Letter from EPA to Mr. Timothy J Mahin, Intel 

Government Affairs, dated November 27, 1995; see 

also Letter from EPA to Edward R. Herbert III, 

Director of Environmental Affairs, National Ready 

Mixed Concrete Association, July 10, 2002, 

included in the docket for this rule under Docket 

ID: EPA–R08–OAR–2012–0479, which can be 

accessed at: http://www.regulations.gov. 

16 ‘‘CAM Response to Comments, Part III,’’ at 6– 

7, October 2, 1997, available online at http:// 

www.epa.gov/airtoxics/cam/ricam.html and 

included in the docket for this rule under Docket 

Continued 

exists in NSPS OOOO and could apply 

to emission units regulated under this 

FIP is the 6 tpy applicability threshold 

for storage tanks. While this FIP does 

not provide the same applicability 

threshold for tanks as that found in 

NSPS OOOO, it does exempt storage 

tanks that are or become subject to the 

requirements of NSPS OOOO. See 

§ 49.4164(f). However, several tanks 

operating on the FBIR prior to the 

applicability date of NSPS OOOO are 

not subject to NSPS OOOO. Therefore, 

since these tanks are not subject to 

NSPS OOOO and do not have a 

minimum emissions threshold for 

applicability, we decided that it was 

appropriate to regulate these tanks in a 

manner consistent with NDDoH 

requirements for tanks at oil and natural 

gas production facilities outside the 

FBIR. Specifically, the Bakken Pool 

Guidance at Appendix D and this FIP at 

§ 49.4164(d)(2)(ii), allow for a reduced 

VOC destruction efficiency and the use 

of pit flares where the PTE of VOCs 

from the aggregate of all produced oil 

storage tanks and produced water 

storage tanks interconnected with 

produced oil storage tanks at an oil and 

natural gas production facility is less 

than, and reasonably expected to remain 

below, 20 tons in any consecutive 12- 

month period. The commenters failed to 

provide any supporting information on 

appropriate applicability thresholds for 

the other production equipment 

regulated under this FIP. As previously 

discussed, we believe the volume of 

VOC emissions from oil and natural gas 

operations on the FBIR warrants 

specially tailored regulation, which we 

have developed in this FIP, and which 

NDDoH developed in their Bakken Pool 

Guidance. At this time, we do not have 

sufficient information to establish 

minimum thresholds for other 

production equipment. 

Comment: Several commenters stated 

that the EPA should clarify that the FIP 

statements ‘‘[t]he completion date is 

considered the date that construction at 

an oil and natural gas production 

facility has commenced’’ (77 FR 48885), 

and ‘‘[t]he recompletion date is 

considered the date that a modification 

has occurred at an oil and natural gas 

production facility’’ (77 FR 48885) are 

for the purposes of determining whether 

this FIP applies to a particular oil 

production facility and does not apply 

to other EPA rules or programs. 

Response: We agree that the suggested 

clarification is necessary. We have 

added language to the applicable 

provision (§ 49.4161(b)) to indicate that 

the correlation of the initiation of well 

completion operations and well 

recompletion operations to the dates 

that construction and modifications 

commence is specific to this rule. In 

addition, we have changed the language 

to clarify that the compliance date is 

upon initiation of well completion 

operations and well recompletion 

operations. 

Comment: Several commenters 

disagree with the EPA’s assertion 

contained in the NSPS OOOO that 

recompletion of an existing well 

constitutes a modification. Because the 

EPA acts in accordance with the NSPS 

OOOO regarding this position, the 

commenters restated the position they 

had voiced in comments on the 

proposed NSPS OOOO. The 

commenters concluded that this same 

error should not be perpetuated in the 

final FIP. 

Response: The issue of what 

constitutes modifications under CAA 

section 111 was decided by EPA in the 

prior rulemaking and is not being 

reopened here. While we are not 

statutorily compelled to use the same 

definition here, we think it is 

appropriate to do so and commenters 

have not provided a policy basis on 

which to revisit EPA’s conclusion. As 

explained in detail in section IX.A. of 

the preamble for the final Federal 

Register notice of NSPS OOOO (77 FR 

49510), a completion operation 

associated with refracturing is 

considered a modification under CAA 

section 111(a) because a physical 

change occurs to the well resulting in 

emissions increases during the 

recompletion operation. When 

determining applicability for the rule, 

we used August 12, 2007, which is the 

earliest well completion date identified 

in the CAFOs and thus the earliest well 

completion date information available 

to the EPA at the time of the 

rulemaking. Due to the nature of 

operations producing from the Bakken 

Pool and the significant amount of coproduced natural gas emissions, it is 

important that modified facilities are 

required to control emissions from 

affected equipment. We believe 

including the definition of a modified 

facility in the final FIP is important 

because it will require the control of 

emissions from the recompletion of any 

existing well that was completed prior 

to August 12, 2007 that the agency may 

not have been aware of at the time of the 

rulemaking and that would not be 

subject to the rule prior to a 

modification. 

Comment: One commenter urged the 

EPA to include pollution control 

requirements for dehydration units, 

pneumatic controllers and pumps, and 

compressors, stating that these sources 

could be significant sources of 

pollution. The commenter requested 

that the EPA incorporate the 

requirements for compressors and 

pneumatics from the NSPS OOOO, at a 

minimum. 

Response: We agree with the 

commenter that dehydration units, 

pneumatic controllers and pumps, and 

compressors are other sources of air 

pollution that may be operating at the 

oil and natural gas production facilities 

on the FBIR. We reviewed information 

provided in 154 applications for 

synthetic minor NSR permits submitted 

to the Region 8 office 14 during the 

development of the FIP. Based on these 

applications, we were able to determine 

that the most significant sources of the 

VOC emissions are the pieces of 

equipment used to produce the oil and 

natural gas during well completions, 

phase separation of the extracted 

reservoir fluids (heater-treater), and the 

temporary storage of the crude oil 

(tanks). The information in the 

applications indicates pneumatic 

devices, dehydration units, 

compressors, and associated fugitive 

emissions listed in the applications 

were minor sources of VOC emissions 

when compared to other emission units. 

Therefore, requirements for this 

equipment have not been included in 

this rule. If we determine at a later date 

that there is a need for control of VOC 

emissions from oil and natural gas 

production equipment and operations 

not covered by this rule, we may 

propose additional FIPs or propose 

supplements to this FIP. 

Comment: Several commenters stated 

that the EPA should remove all 

requirements applicable to heater-treater 

combustion devices from the FIP. The 

commenters asserted that the use of 

heater-treater combustion devices can 

already be taken into account when 

determining PTE because they are 

‘‘inherent process equipment,’’ and that 

additional requirements for these 

devices are therefore unnecessary. The 

commenters cited criteria from the EPA 

letters 15 and the Compliance Assurance 

Monitoring (CAM) rulemaking 16 to 

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17844 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

ID: EPA–R08–OAR–2012–0479, which can be 

accessed at: http://www.regulations.gov. 

17Memo from John S. Seitz, Director, Office of Air 

Quality Planning and Standards, to Regional Air 

Division Directors, Regions 1–10, Calculating 

Potential to Emit (PTE) for Emergency Generators 

(September 6, 1995), available at http://epa.gov/ 

region07/air/title5/t5memos/emgen.pdf and 

included in the docket for this rule under Docket 

ID: EPA–R08–OAR–2012–0479, which can be 

accessed at: http://www.regulations.gov. 

argue that heater-treater combustion 

devices must be considered inherent 

process equipment based on those 

criteria. 

The commenters stated that the EPA’s 

description of the heater-treater 

combustion device requirement in the 

FIP mandates the use of such devices at 

oil facilities, primarily for safety and 

product recovery, and does not address 

air quality concerns (77 FR 48883– 

48884). 

The commenters also stated that the 

possibility of some oil facilities 

operating without heater-treater devices 

is not an appropriate justification for the 

FIP requirements, because any facilities 

operating as such would be in clear 

violation of standard operating 

procedures which ensure safe working 

conditions. The commenters insisted 

that the EPA should not base this 

justification on ‘‘unsupported 

assumptions’’ that standing laws are 

being violated or inadequately enforced. 

Response: We acknowledge that the 

preamble at 77 FR 48883 states that the 

oil/natural gas/water emulsion from the 

production wells is transported through 

2-phase separators (separators), which 

are an inherent component of the 

pipeline. We also state in the same 

paragraph that following the 2-phase 

separator, the emulsion enters a 3-phase 

separator (heater-treater), which is a 

necessary step in the production process 

and produces gas that is separated from 

the emulsion. However, until the 

separated gas from the heater-treater is 

captured as product or used in some 

other beneficial way at the facility (e.g., 

a fuel source for gas burning equipment) 

it is a significant source of the high 

volume VOC emissions we determined 

requires control to protect public health 

and the environment on the FBIR. 

Throughout the rulemaking process, one 

of our priorities was to equalize the 

requirements that apply to sources 

operating in the State of North Dakota’s 

jurisdiction with the requirements that 

apply to sources outside of the State’s 

jurisdiction. The NDIC regulations 

found in the Control of Oil and Gas 

Resources at Chapter 38–08–06 require 

that natural gas from the heater-treaters 

be routed to a natural gas gathering 

pipeline as soon as practicable. When a 

pipeline is not available, the natural gas 

produced in the heater-treater process is 

required to be routed to a control system 

or device. While we acknowledged in 

the preamble for the interim final rule 

that the purpose of the NDIC 

requirements was principally for safety 

and product recovery reasons, we also 

acknowledged that the requirements for 

heater-treaters were modeled after the 

Bakken Pool Guidance which requires 

that the emissions from heater-treaters 

be controlled. 

E. Control Equipment and Requirements 

Comment: One commenter stated that 

flares of roughly 40 feet are a usual sight 

in Mandaree and can be a nuisance to 

area residents because of light and noise 

pollution. Another commenter stated 

that flares were not being lit when they 

should have. 

Response: We acknowledge the 

concerns expressed by the commenters 

and offer a clarified explanation of the 

purpose and operation of the flares 

being used by operators of oil and 

natural gas production facilities on the 

FBIR. 

The purpose of flaring the natural gas 

that is coproduced when extracting oil 

from the FBIR wells is to prevent the 

emission of VOC gases that might 

otherwise be vented to the ambient air 

when the natural gas cannot be captured 

and injected into a sales pipeline. The 

flames from the flares indicate that the 

VOCs are actually being combusted. The 

flares should be lit at all times that coproduced natural gas is being routed to 

them rather than to the sales pipeline. 

In situations where production facilities 

are able to take advantage of existing 

infrastructure and inject produced gas 

into a pipeline, flaring is significantly 

reduced, in some cases to the point of 

only occurring as a backup control 

measure in the event that pipeline 

injections of all or part of the produced 

natural gas becomes temporarily 

infeasible. Situations at production 

facilities that are unable to route the gas 

to a sales pipeline and where flares are 

not visibly operating may indicate the 

flares are not being operated properly 

and gas is being vented directly to the 

ambient air. This FIP has appropriate 

monitoring, recordkeeping, and 

reporting requirements to ensure that 

the flares are operating properly. 

Further, because the FIP intends to limit 

the use of flares in favor of capture and 

injection of the produced natural gas 

into sales pipelines as soon as 

practicable, secondary impacts such as 

noise and light pollution from 

combustion of gas are expected to be 

reduced by the owner or operator 

complying with the rule. 

Comment: One commenter speculated 

that the level of emissions from flares is 

above the allotted amount. 

Response: It is unclear what is meant 

by the term ‘‘allotted amount.’’ The 

majority of oil and natural gas 

production facilities currently in 

operation on the FBIR do not hold any 

air pollution control permits that 

specify any ‘‘allotted amount’’ of 

emissions from the flares. Should the 

combustion emissions from flaring 

exceed the major source permitting 

thresholds under PSD specified at 40 

CFR 52.21, the owner or operator would 

be required to obtain a PSD permit or 

may opt to obtain a minor NSR permit 

to become synthetically minor for 

purposes of PSD prior to beginning 

actual construction, independently of 

this FIP. Either of these permits would 

require the installation of control 

technology sufficient to ensure 

protection of air quality. 

Comment: Several commenters stated 

that the EPA should eliminate the 500 

hour limitation on pit flare usage 

because it is inconsistent with the 

Bakken Pool Guidance and unnecessary. 

One commenter wondered why use of 

the pit flare was limited to 500 hours 

per year and not something different. 

The commenters also asserted that only 

being allowed to assume 90% VOC 

destruction and removal efficiency 

(DRE) for pit flares already limits the 

amount of pit flaring that could occur 

without exceeding major source 

thresholds. The commenters also stated 

that a limitation on the use of pit flares 

punishes operators that inject recovered 

produced natural gas and natural gas 

emissions into existing pipeline 

infrastructure to sell it, because 98% 

VOC DRE control devices are more 

costly. Another commenter asked who 

will monitor the pit flare operations and 

what the repercussions are if a source 

exceeds the limit of 500 hours of 

operation in any consecutive 12-month 

period? 

Response: We disagree with the 

commenters that the 500 hour limitation 

on pit flare usage is unnecessary. The 

purpose of the 500-hour per year limit 

on use of a pit flare as a backup control 

device in instances where injection of 

produced natural gas and natural gas 

emissions is temporarily infeasible is to 

discourage the use of pit flares as a 

primary control device. Based on past 

EPA guidance 17 that addresses backup 

situations, we have concluded that 

applying a 500 hour per year limit to the 

oil and natural gas production facilities 

for the use of a pit flare in backup 

situations is reasonable and consistent 

with backup operation timeframes 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17845 

18Consent Decree United States of America v. 

Marathon Petroleum Company, LP, and 

Catlettsburg Refining, LLC, available at: http:// 

epa.gov/compliance/resources/decrees/civil/caa/ 

marathonrefining-cd.pdf and included in the docket 

for this rule under Docket ID: EPA–R08–OAR– 

2012–0479, which can be accessed at: http:// 

www.regulations.gov. 

19Consent Decree United States of America, and 

the State of Indiana, and Plaintiff Intervenors v. BP 

Products North America, Inc, available at: http:// 

epa.gov/compliance/resources/decrees/civil/caa/ 

whiting-cd.pdf and included in the docket for this 

rule under Docket ID: EPA–R08–OAR–2012–0479, 

which can be accessed at: http:// 

www.regulations.gov. 

20As discussed in the preamble for the interim 

final rule (77 FR 48880), the EPA Region 8 air 

permit and enforcement programs hosted a Fort 

Berthold Oil and Natural Gas Production Minor 

NSR Permitting Process Meeting with the oil 

producers in late August 2011. Representatives 

from the Tribes were invited and attended in person 

and by phone. Discussions included the anticipated 

permitting timeline for permit applications 

submitted by the oil producers. Between August 23 

and September 1, 2011, a draft example synthetic 

minor permit was sent by EPA to the meeting 

attendees and the Tribes in preparation for the next 

meeting on September 1, 2011. Then, on September 

1, 2011, Region 8 hosted a permitting workshop. 

Representatives from the various oil producers and 

the Tribes were invited and attended. 

Representatives of the NDDoH also participated by 

phone. The minor NSR permitting process was 

discussed, as well as questions that the companies 

submitted ahead of time. The group began 

discussions on the draft example permit and set up 

a workshop specifically to delve into the specific 

permit conditions for the following week. On 

September 7 and 8, 2011, the EPA hosted a two-day 

follow-up permitting workshop. All previous 

meeting attendees were invited, including the 

Tribes. Participants included the oil producers and 

their consultants. NDDoH representatives were also 

on the phone. At this meeting the group went 

through the draft example permit and discussed the 

proposed conditions and appropriate edits. Also 

discussed was what would constitute a complete 

application (administrative and technical) and the 

various methods of PTE calculation proposed by the 

companies in attendance. The EPA Region 8 hosted 

an additional meeting on November 30, 2011 to 

discuss the revised example permit, and 

representatives from the various oil producers and 

the Tribes were invited and attended. During these 

permitting workshops, it was brought to our 

attention that owners and operators routinely use 

temporary, portable utility flares capable of 

achieving a 98% VOC DRE for the initial period 

when a new oil and natural gas production facility 

is being prepared for permanent operations. A copy 

of the attendee list for each meeting has been 

included in the docket for this rule under Docket 

ID: EPA–R08–OAR–2012–0479, which can be 

accessed at: http://www.regulations.gov. 

21A copy of the letter has been included in the 

docket for this rule under Docket ID: EPA–R08– 

OAR–2012–0479, which can be accessed at: 

http://www.regulations.gov. 

allowed for other industry sectors. In 

addition, past EPA enforcement 

settlements 18 19 that address backup 

situations have led us to conclude that 

500 hours (or 21 days) is a reasonable 

period of time for owners and operators 

of oil and natural gas production 

facilities to address these situations and 

maintain compliance with the rule. 

During development of the draft 

synthetic minor NSR permits prior to 

this rule, we had discussions with 

owners and operators indicating that 

many oil and natural gas production 

facilities on the FBIR regularly utilize 

temporary 98% VOC DRE control 

devices while they are preparing a 

facility for permanent production and 

storage operations;20 therefore, we 

concluded it is reasonable to expect that 

an owner or operator could acquire one 

of these temporary control devices in 

situations where use of the pipeline may 

be infeasible for more than 500 hours. 

The final rule requires the owners and 

operators to monitor and keep records of 

the hours that a pit flare is operated, a 

description of the justification for use 

and the volume of gas sent to it, to 

ensure that the EPA can make a 

determination, if necessary, that 

injection of produced natural gas and 

natural gas emissions into a pipeline for 

sale or other beneficial purpose, or the 

use of the primary control device, has 

been maximized. Any deviations of 

these requirements must be reported to 

the EPA. 

Comment: Several commenters stated 

that the EPA should clarify that 98% 

DRE utility flares and combustors are 

not required to be installed as backup 

control devices if an operator chooses to 

route vapors to a production line and 

use a 90% VOC DRE control device as 

backup. The commenters stated that 

such a clarification would prevent 

operators tied into a sales line from 

keeping utility flares or combustors idle 

and on-site for infrequent backup use. 

Response: We agree. While the rule 

does not require the use of utility flares 

and combustors as back-up control 

devices if the owner or operator is 

routing produced natural gas and 

natural gas emissions to a sales line, the 

rule does not clearly state this. The rule 

has been clarified. 

Comment: Commenters stated that 

control requirements during 

completions, recompletions, and for the 

first 90 days of production are 

insufficient. The commenters urged the 

EPA to require that any flaring under 

the FIP be performed using an enclosed 

vent system, along with a utility flare or 

a similar device, which is capable of 

98% VOC DRE. 

Response: We disagree with the 

commenter that control requirements 

during completions, recompletions, and 

for the first 90 days of production are 

insufficient. This FIP establishes 

requirements to control air pollution in 

the form of VOC emissions from oil and 

natural gas production and storage 

operations on the FBIR, comparable to 

those requirements developed by state 

permitting authorities. In other words, 

we were motivated to level the playing 

field for the regulated community. With 

that in mind, the NDIC and NDDoH 

allow the use of pit flares or other 90% 

VOC DRE control devices during 

completions and recompletions. Shared 

by both the State of North Dakota and 

the EPA, another reason to limit the 

required VOC destruction efficiency to 

90% VOC DRE is that an owner or 

operator may be put at a significant 

economic disadvantage if they purchase 

and install the much more expensive 

98% VOC DRE control devices and 

within the first 90 days after the first 

date of production a well is found to be 

too low producing to justify continued 

production and must be shut-in. 

Comment: Several commenters stated 

that the EPA must clarify that emissions 

from completion and recompletion 

operations do not need to be vented to 

a flare until the level of VOC is 

sufficient to support combustion. The 

commenters asserted that one might 

interpret the FIP language which 

required each owner or operator to 

‘‘route all casinghead natural gas to a 

utility flare or a pit flare capable of 

reducing the mass content of VOC by at 

least 90%’’(77 FR 48895) to include 

venting materials that are not flammable 

and therefore unable to sustain 

combustion. The commenters stated that 

such an interpretation would make 

compliance with the rule impossible, as 

vented materials are typically not 

flammable in the early stages of 

completion or recompletion. The 

commenters cite ‘‘Letter to Mr. Matthew 

Todd from Peter Tsirigotis, Director, 

Sector Policies and Programs Division 

(Sept. 28, 2012)’’ as evidence that the 

EPA recently reached a similar 

conclusion.21

Response: While the regulatory 

language at § 49.4164(b) in the interim 

final rule is not specific on this point, 

the recordkeeping requirements for well 

completion and recompletion 

operations in § 49.4167(a)(4)(ii) of the 

interim final rule specifically require 

logging the date, time, and duration of 

any venting of casinghead natural gas 

from the oil and natural gas well; and 

specific reasons for each instance of 

venting in lieu of capture or 

combustion. Therefore, this requirement 

allows some degree of venting materials 

that may not be flammable during well 

completion and recompletion 

operations. 

Comment: Several commenters stated 

that this FIP is inconsistent with NSPS 

OOOO and adds further confusion for 

operators who will be required to 

comply with both sets of requirements. 

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17846 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

22Commenter cites William C. Allison, Director, 

Air Pollution Control Division, Colorado 

Department of Public Health and the Environment, 

Testimony before the United States Senate, 

Environment and Public Works Committee, Clean 

Air and Nuclear Safety Subcommittee, June 19, 

2012. A copy of this transcript has been included 

in the docket for the rule under Docket ID: EPA– 

R08–OAR–2012–0479, which can be accessed at: 

http://www.regulations.gov. 

These commenters further state that for 

all sources to which NSPS OOOO 

applies, the FIP should mirror NSPS 

OOOO requirements for oil and 

produced water tank control devices. 

Specifically, the commenters stated that 

because the NSPS OOOO does not take 

effect for tanks for one year, the 

inconsistency results in an unnecessary 

burden. The commenters also asserted 

that since NSPS OOOO does not apply 

to heater-treaters, the requirements in 

the FIP for heater-treaters should mirror 

the requirements of the NDDoH 

regulations precisely. The commenter 

also expressed concern that the terms of 

NSPS OOOO are still subject to 

challenges that have not been resolved, 

although the commenter indicated that 

the EPA was in discussions with 

industry representatives to resolve those 

issues. 

Response: We disagree that 

differences between this FIP and NSPS 

OOOO result in an ‘‘unnecessary 

burden’’ to owners or operators affected 

by the rules. Where there are differences 

between this FIP and NSPS OOOO, 

NDDoH requirements, and NDIC 

requirements, they exist for a specific 

reason. For example the requirements in 

this FIP for produced oil and produced 

water storage tanks provide legally and 

practicably enforceable control 

requirements for facilities currently 

operating on the FBIR until applicable 

storage tank requirements become 

effective under NSPS OOOO. At that 

time, the provisions in the NSPS OOOO 

for produced oil and produced water 

storage tanks will supersede the 

produced oil and produced water 

storage tank requirements in the FIP at 

§ 49.4164(f), and owners or operators 

will never be required to comply with 

both sets of requirements since 

duplicate requirements do not apply to 

the affected equipment. In addition, we 

are addressing emissions controls for 

heater-treaters because we determined 

such controls are cost effective and have 

been demonstrated to be effective in 

light of the air quality concerns at play 

in the area. Specifically, we included 

the provision in the FIP at 

§ 49.4164(d)(2)(iii), which requires 

aggregate storage tank VOC emissions at 

any facility that are greater than 20 tpy 

to be reduced by at least 98%, and VOC 

emissions less than 20 tpy to be 

controlled by at least 90%. We 

evaluated and adopted this FIP 

provision, which is consistent with the 

requirements for the heater-treaters 

found in the NDIC requirements at 38– 

08–06.4 and the heater-treater 

requirements in the Bakken Pool 

Guidance. We acknowledge that the 

98% VOC DRE control requirement for 

heater-treaters in this FIP is at the upper 

end of the 90–98% range in the Bakken 

Pool Guidance. However, the owners 

and operators of oil and natural gas 

production facilities on the FBIR have 

indicated that a 98% VOC DRE is 

achievable and committed in their 

synthetic minor NSR applications to 

reduce the mass content of VOC 

emissions routed to the enclosed 

combustors or utility flares used for 

both produced gas from heater-treaters 

and flashing gas from storage tanks by 

at least 98%. With this reduction, the 

owners and operators demonstrated that 

for most of their facilities the potential 

emissions would not trigger the 

requirements to obtain a PSD and/or 

Part 71 permit when accounting for the 

requested federally enforceable 

restrictions. The 98% level of control is 

necessary because of the high volume of 

VOC emissions that must be controlled. 

The commenter did not specifically 

state which ‘‘challenges’’ to NSPS 

OOOO they were referring to in their 

comment. However, current petitions 

filed concerning NSPS OOOO are 

outside of the scope of this rule. 

Regardless of any future changes to 

NSPS OOOO, the primary intent of FIP 

is to provide environmental protection 

on the FBIR by creating federally 

enforceable control requirements for oil 

and natural gas operations on the FBIR. 

Additionally, as discussed above, these 

FIP requirements are consistent with the 

State’s requirements. 

Comment: Multiple commenters 

stated that completion and recompletion 

requirements should be removed from 

the FIP because completion and 

recompletion requirements in NSPS 

OOOO only apply to hydraulically 

fractured natural gas wells, and that the 

application of these activities to oil 

wells in the FIP is therefore inconsistent 

with NSPS OOOO. 

Response: This FIP requires owners or 

operators to route emissions from well 

completion and recompletion 

operations to a combustion device. This 

is similar to the requirements for 

hydraulically fractured gas wells in 

NSPS OOOO prior to January 1, 2015. 

While requirements for completions and 

recompletions in the NSPS OOOO only 

apply to natural gas wells, the FIP 

includes this requirement for the oil and 

natural gas wells on the FBIR because of 

the high amount of associated natural 

gas in the crude oil. This is a significant 

source of VOC emissions that required 

control in the FIP and we think such a 

requirement is appropriate given the 

emissions characteristics of these wells 

in the Bakken formation, regardless of 

the emissions characteristics of other oil 

and natural gas production wells 

nationwide. 

Comment: Commenter stated that the 

EPA should require recompleted oil and 

natural gas wells on the FBIR to perform 

reduced emission completions (RECs). 

The commenter asserted that many 

states including Colorado and Wyoming 

currently require RECs, and that both 

states have thriving oil and natural gas 

industries.22 The commenter also stated 

that several natural gas companies 

currently employ use of RECs despite 

the fact that they are not required. The 

commenter insisted that, if RECs are 

determined not to be economical in 

areas like the FBIR with limited natural 

gas pipeline and gathering line 

infrastructure, the EPA must find 

alternative local uses for the natural gas. 

Commenter stated that the EPA should 

at least require RECs on the FBIR in the 

near future, similar to the NSPS. 

Commenter stated that the EPA’s NSPS 

OOOO will require RECs at all new and 

modified gas wells beginning in 2015. 

Furthermore, another commenter stated 

that if the FIP were to require green 

completions, advanced notice of 

completion or recompletion as is 

included in the NSPS OOOO would be 

a critical requirement in the FIP. 

Response: RECs cannot be performed 

if there is no gathering line available to 

convey natural gas produced during the 

completion flowback. Such lines are not 

likely to be available if the well location 

has no access to a natural gas gathering 

system. Although pipeline 

infrastructure is currently being 

developed on the FBIR, we do not 

believe there is currently sufficient 

access to natural gas gathering pipelines 

in all development areas of the FBIR to 

require RECs at this time. We recognize 

the potential for VOC emissions from 

well completion and recompletion 

operations and have maintained the 

requirement in the final rule to reduce 

these emissions by at least 90%. If we 

determine at a later date that there is a 

need for additional control of VOC 

emissions from well completion and 

recompletion operations, we may 

propose additional FIPs or propose 

supplements to this FIP. 

Comment: One commenter stated that 

the emission control requirements of the 

FIP will not exceed the current NDIC 

emission control requirements, 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17847 

23The information reviewed was contained in 

synthetic minor NSR applications submitted to 

EPA, which are included in the docket for this rule 

under Docket ID: EPA–R08–OAR–2012–0479, 

which can be accessed at: http:// 

www.regulations.gov. 

24A copy of the submittal from Lisa Decker, WPX 

Energy, to Carl Daly, EPA Region 8 Air Program 

Director, on November 13, 2012 has been added to 

docket for the rule under Docket ID: EPA–R08– 

OAR–2012–0479, which can be accessed at: http:// 

www.regulations.gov. 

providing a ‘‘smooth transition’’ for the 

owners or operators. Another 

commenter requested more stringent 

emission limits be required than the 

NDIC requirements. A third commenter 

expressed concern that the regulations 

of the proposed FIP are equal to the 

NDDoH regulations and noted that the 

FBIR is its own nation, and therefore the 

FIP regulations are pertinent to the 

residents of the FBIR and not 

individuals outside the FBIR’s 

boundaries. 

Response: One of the goals of this FIP 

is to provide air quality protection for 

the residents of the FBIR, while also 

allow for continued development of 

mineral resources. The FIP requirements 

are consistent with the most relevant 

aspects of the North Dakota rules based 

on our evaluation that the level of 

control was appropriate for meeting 

these goals while ensuring the 

enforceability required by a federal rule. 

We also evaluated over 150 synthetic 

minor NSR permit applications 23 to 

identify the most significant sources of 

VOC emissions and associated control 

equipment employed by the operators to 

ensure that the control requirements in 

this FIP are based on the nature of oil 

and natural gas production and storage 

operations on the FBIR. 

Comment: Several commenters stated 

that the requirements of the FIP are too 

stringent. The commenters also noted 

that since FBIR is in attainment with all 

applicable NAAQS, highly stringent 

controls are neither appropriate nor 

necessary. The commenters stated that 

the 98% control required in the FIP is 

above the 90–98% range the EPA 

allowed in recent CAFOs. The 

commenters also stated that the 

requirements of the FIP are inconsistent 

with the requirements that currently 

apply to operators of the same type of 

facilities through NDDoH regulations, 

specifically the Bakken Pool Guidance. 

The commenters asserted that the more 

burdensome requirements of the FIP as 

compared to those outside the FBIR may 

discourage expansion of operations 

within the FBIR. 

On the other hand, other commenters 

stated their support of the EPA’s 

requirements in the FIP, and encouraged 

the EPA to retain the 98% VOC DRE 

requirement for flaring at storage tanks, 

restating the EPA’s position that this 

level is appropriate considering the 

unique geochemistry of the Bakken 

formation. 

Response: We disagree that the 

requirement to reduce VOC emissions 

from production and storage operations 

by 98% is too stringent or burdensome. 

The owners and operators of oil and 

natural gas production facilities on the 

FBIR have indicated that a 98% VOC 

DRE is achievable and have even 

committed to it in their synthetic minor 

NSR applications to reduce the mass 

content of VOC emissions routed to the 

enclosed combustors or utility flares 

used for both produced gas from heatertreaters and flashing gas from storage 

tanks by that amount. The high VOC 

content of the oil and natural gas 

produced from Bakken Pool operations 

allows for a higher DRE. Many of the 

owners and operators of oil and natural 

gas production facilities indicated that a 

DRE of 98% was imperative to limit the 

applicability of permitting requirements 

that may result if only a 90% creditable 

reduction of VOC emissions is allowed. 

We also evaluated regulations in other 

oil and natural gas producing states 

within Region 8 and note that this FIP 

is consistent with Wyoming’s 

requirements to control both storage 

tank and separation vessels by 98%. 

Comment: Multiple commenters 

expressed concern with the 

requirements in § 49.4164 which states 

that, beginning with the first date of 

production, facilities subject to the rule 

are required to route natural gas 

emissions from production operations 

and storage operations to a 90% 

emissions reduction device. Within 90 

days of the first date of production, this 

device must be either replaced with a 

98% emissions reduction device or tied 

to a gas sales line. The 90-day time 

frame listed in the rule should be 

extended to at least 180 days, to allow 

operators time to get the required 

equipment. There is added concern that 

given the number of devices that may 

need to be purchased for new facilities, 

particularly with the impending 

implementation of NSPS Subpart 

OOOO, equipment shortages will be 

expected. Further, commenters stated 

that the EPA should include a provision 

here that allows for an extension of the 

180-day time limit for upgrading to a 

sales line or 98% control device in the 

event such equipment is unavailable. 

Response: We disagree with the 

commenter that we should change the 

90-day timeframe allotted to either 

replace a 90% emissions reduction 

device with a 98% emissions reduction 

device or inject produced natural gas 

and natural gas emissions to a gas sales 

line. One of the goals of this FIP is to 

protect human health and the 

environment and the required VOC 

emission control should be achieved as 

expeditiously as possible. Furthermore, 

when evaluating the estimated 

emissions provided by the oil and 

natural gas production operators for the 

facilities covered by the August 2011 

CAFOs (77 FR 48879), we found that in 

many cases, the difference in controlled 

heater-treater emissions between only 

90% VOC DRE for 90 days or less versus 

more than 90 days is the difference 

between being a true minor source of 

VOC emissions under the Federal Tribal 

NSR regulations and being a major 

source of VOC emissions under the PSD 

regulations based on the high VOC 

emissions from these oil and natural gas 

operations on the FBIR. 

We recognize that some owners and 

operators might need time to acquire 

equipment that achieves the required 

VOC control and we believe, based on 

the information in permit applications 

provided by the owners and operators 

on the FBIR that 90 days is a reasonable 

timeframe to acquire the necessary 

control equipment. The interim final 

FIP contains a provision that the owner 

or operator may use 98% VOC DRE 

control devices other than those 

specified in the FIP upon prior written 

approval from the EPA. Based on 

information submitted to date by an 

operator requesting alternative control 

device approval, it is possible to 

economically engineer shop-built flares 

that can be demonstrated to meet the 

required VOC DRE and that can be used 

until a utility flare becomes available, if 

insertion of the produced natural gas to 

a sales pipeline or use of the produced 

natural gas for other beneficial purpose 

is demonstrated to not be feasible.24

F. Monitoring and Recordkeeping 

Requirements 

Comment: Multiple commenters 

stated that the EPA should impose less 

burdensome monitoring and 

recordkeeping requirements for minor 

sources. The commenters asserted that 

the level of detail required in the FIP is 

generally required only for major 

sources, and that it is higher than the 

detail required for minor sources by 

NDDoH regulations and the Bakken Pool 

Guidance. The commenters stated that 

the FIP should mirror NDDoH 

regulations regarding heater-treater 

control devices, meaning that 

monitoring and recordkeeping 

requirements should be eliminated. The 

commenters stated that the cost of 

monitoring and recordkeeping in the 

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25Commenter does not list the rule with which 

such a change would maintain consistency. 

26 ‘‘National Uniform Emission Standards for 

Storage Vessel and Transfer Operations, Equipment 

Leaks, and Closed Vent Systems and Control 

Devices; and Revisions to the National Uniform 

Emission Standards General Provisions,’’ 77 FR 

17,898, 17,943 and 18,009 (proposed Mar. 26, 2012) 

(proposed 40 CFR 65.429(a)). 

FIP is high compared to the benefit, and 

that these factors will create a 

disincentive to expand drilling on the 

FBIR. Although one commenter stated 

that the EPA’s monitoring and reporting 

requirements are reasonable and will 

facilitate compliance while also 

gathering pertinent information on 

operations. Yet another commenter 

stated that the EPA’s monitoring and 

reporting requirements could be even 

more stringent to include leak 

monitoring of the closed vent systems 

and advanced notification prior to 

performing a well completion or 

recompletion. 

Response: We acknowledged in the 

Federal Register notice and the TSD for 

the interim final FIP that monitoring, 

reporting, and recordkeeping (MRR) 

requirements were an area where the 

FIP would differ from the NDIC and 

NDDoH regulations, and the Bakken 

Pool Guidance. Federal regulations must 

contain requirements that are legally 

and practicably enforceable; and 

therefore this FIP contains legally and 

practicably enforceable provisions that 

are necessary to meet the requirements 

for federal regulations. Recognizing that 

this FIP regulates different oil and 

natural gas production equipment than 

NSPS OOOO, the approach we took in 

developing MRR requirements for oil 

and natural gas production emission 

control equipment is similar to the 

approach the Agency used in 

developing MRR requirements for gas 

well production emission control 

equipment. Therefore, we do not believe 

the requirements are any more 

burdensome than requirements for 

similar equipment in NSPS OOOO. 

Comment: Several commenters stated 

that the EPA should allow an operator 

to make a visual inspection only once 

per quarter, and should require that 

operator to conduct a one-hour Method 

22 evaluation only if the control device 

is actually smoking. The commenters 

asserted that the amount of time it 

would take just to conduct quarterly 

monitoring without this change could 

potentially require three full-time 

equivalent operators for that task alone. 

The commenters requested that the 

EPA make two additional changes to the 

FIP’s current requirements for 

monitoring smoking combustion 

devices, though the commenters 

ultimately stated that the resource 

burden to meet the smoke monitoring 

requirements would still be extreme 

regardless of whether the two changes 

were made. The first change is that the 

EPA increase the amount of time a 

control device can smoke before being 

considered a ‘‘smoking’’ device from 

two minutes to five minutes for 

consistency.25 The second change is that 

the EPA remove the phrase ‘‘whenever 

an operator is on site’’ from 

§ 49.4166(g)(3). The commenter stated 

that this phrase is ambiguous when read 

in conjunction with the phrase ‘‘at a 

minimum quarterly.’’ The commenters 

also stated that it would be extremely 

burdensome for an operator to observe 

a flare for an entire hour each time that 

operator was on site. The commenters 

ultimately stated that even with this 

change, the requirement would still be 

extremely burdensome. 

Response: We agree with the 

commenters that the EPA should only 

require an operator to conduct a Method 

22 evaluation if visible smoke emissions 

are observed. We also agree with the 

commenter’s request that we increase 

the amount of time a control device can 

smoke before being considered a 

‘‘smoking’’ device from two minutes to 

five minutes. This is consistent with the 

specification in NSPS OOOO at 

§ 60.5415(e)(vii)(C) and (e)(vii)(D)(3), 

and the general provisions at § 60.18(b) 

for visible emissions testing of 

combustion control devices (77 FR 

49556). However, we do not agree that 

one-hour observations are suitable, as 

both § 60.18(b) and NSPS OOOO require 

two-hour observations and we have no 

reason to conclude that a different 

approach is appropriate here. 

We have revised the applicable 

condition in this final FIP to require the 

owner or operator to monitor for visible 

smoke and to only conduct a Method 22 

evaluation if visible smoke emissions 

are observed. We have also revised the 

provision to specify that visible smoke 

emissions are present if smoke is 

observed more than five minutes in any 

2 consecutive hours. We have not 

removed the requirement to conduct on 

site inspections of the operation of the 

device when an operator is onsite, but 

not less frequently than quarterly, 

because we disagree that this 

requirement is ambiguous. In addition, 

since we changed the monitoring 

provision to require observations for 

visible smoke before triggering the 

requirement for Method 22 evaluations, 

the commenters’ concern that the 

requirements are burdensome has been 

addressed. 

Comment: Several commenters stated 

that the EPA should allow the operator 

to make frequent onsite checks or use 

other alternatives to meet the 

continuous recording device 

requirement in § 49.4165(c)(6)(v) for 

utility flares and enclosed combustors. 

The commenters asserted that there are 

significant challenges with obtaining the 

appropriate continuous monitoring 

equipment, and that operator checks 

should therefore be accepted as fully 

meeting the requirement, or at least as 

meeting the requirement in the interim. 

Response: We agree that there needs 

to be an opportunity to perform 

alternative monitoring upon prior 

written EPA approval. We have revised 

the applicable provision at § 49.4166(i) 

to reflect this in the final rule. 

Comment: One commenter stated that 

the EPA should ‘‘require regulated 

entities to regularly monitor VOC 

emissions from the components of 

closed-vent systems, using wellestablished methods and leak 

thresholds.’’ The commenter stated that 

in the preamble and proposed 

regulatory text, the EPA required proper 

maintenance and operation of vent 

lines, connections, fittings, valves, relief 

valves, or any other appurtenance 

employed to contain, collect and 

transport gases, and required that these 

components be designed to operate with 

no detectable natural gas emissions (77 

FR 48889, 48896). However, the EPA 

failed to require producers to 

demonstrate or verify that the required 

closed-vent systems are ‘‘maintained 

and operated properly’’ or ‘‘operate with 

no detectable natural gas emissions.’’ 

Commenter stated that without a 

monitoring or verification requirement, 

the requirements for closed-vent 

systems ‘‘will be unenforceable and 

largely hortatory in nature.’’ 

Commenter also stated that the lack of 

monitoring or verification requirements 

for closed-vent systems is at odds with 

the goal of the FIP, which is to establish 

emission limits at oil and natural gas 

facilities that are legal and practically 

enforceable. Commenter asserted that 

absent these verification requirements, a 

producer could not guarantee natural 

gas is controlled at 90% or 98%, and the 

EPA could not guarantee that the 

projected emission reductions have 

been achieved. Commenter stated that 

the EPA requires closed-vent monitoring 

techniques in other regulations, 

including NSPS OOOO and the 

‘‘National Uniform Emission 

Standards.’’ 26 Commenter 

recommended that, at a minimum, the 

EPA use the approach proposed by the 

agency in the National Uniform 

Emission Standards. 

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27The TSD includes a more detailed explanation 

of the cost analysis for this FIP. It can be found in 

the docket for this rule, Docket ID: EPA–R08–OAR– 

2012–0479, which can be accessed at: http:// 

www.regulations.gov. 

28 ‘‘Natural Resources Defense Council, Leaking 

Profits: The U.S. Oil and Gas Industry Can Reduce 

Pollution, Conserve Resources, and Make Money by 

Preventing Methane Waste,’’ 2012. A copy of this 

document has been included in the docket for this 

rule under Docket ID: EPA–R08–OAR–2012–0479, 

which can be accessed at: http:// 

www.regulations.gov. 

29Commenter provides several examples in 

which oil and gas development drives up ozone 

emissions. See NRDC comments in the docket for 

this rule for specific citations. 

Response: We disagree that leak 

detection and repair (LDAR) 

requirements should be included in this 

FIP. As discussed in the preamble and 

TSD for NSPS OOOO, it was determined 

that LDAR monitoring was not cost 

effective for smaller oil and natural gas 

production facilities and we have no 

information from which to conclude 

that the same is not the case here. To 

demonstrate compliance with the 

requirements for closed-vent systems, 

the final rule requires all vent lines, 

connections, fittings, valves, relief 

valves, or any other appurtenance on 

tank covers and closed-vent systems be 

maintained and operated properly at all 

times and that they are visually 

inspected at least quarterly while the 

equipment is operating. Further, each 

bypass devices on all closed-vent 

systems are required to be equipped 

with a flow meter to continuously 

monitor the volume of natural gas 

emissions that are diverted from the 

natural gas gathering pipeline, or 

required control device. The final rule 

requires that the owners and operators 

keep records of all monitoring 

parameters and report instance where 

construction and operation was not 

performed in compliance with the 

requirements specified in the final rule. 

G. Reporting Requirements 

Comment: Commenter recommended 

that the EPA require a self-certification 

mechanism, which would require a 

senior company official to certify as to 

the truth, accuracy and completeness of 

its annual report. Commenter suggested 

that the EPA draw on the example of the 

NSPS OOOO in developing this 

mechanism. 

Response: We agree that selfcertification is an important mechanism 

for assuring the public that the 

information submitted by each facility is 

accurate and have added a provision in 

the rule requiring owners or operators to 

certify as to the truth, accuracy and 

completeness of the annual reports. The 

EPA already requires a similar 

certification in the NSPS OOOO; 

therefore, we concluded that it is not 

unreasonable to require the certification 

for reports submitted under this FIP. 

H. Cost Analysis 

Comment: One commenter agreed 

with the EPA’s position that the FIP 

does not impose a significant cost on 

operators. Another commenter noted the 

benefits of the FIP, specifically citing 

the substantial and cost-effective VOC 

reductions that the EPA estimated in the 

FIP. 

Response: We acknowledge the 

support of these commenters for this 

FIP. We have included information 

regarding the cost-effectiveness of this 

FIP in the TSD for the interim final 

rule.27

Comment: Commenter stated that the 

EPA does not address the economic 

benefits of natural gas capture when 

estimating the costs and benefits of the 

FIP. The commenter stated that 

‘‘producers are very likely to derive 

substantial amounts of revenue by 

installing vapor recovery units and 

gathering lines to route excess natural 

gas that is captured by voluntary RECs 

and through other regulatory 

requirements to reduce leaks.’’ The 

commenter referenced an NRDC 

report 28 and the NSPS OOOO (77 FR 

49534, 49537) to support this point. The 

commenter also stated that the EPA 

noted this revenue opportunity in the 

FIP TSD, though it did not address it in 

the FIP itself. The commenter stated that 

it is especially important to consider 

these benefits because the EPA notes 

that its analysis already overestimates 

costs, and also generally stated that gas 

is a valuable commodity that should not 

be wasted. 

Response: We did not discuss the use 

of RECs in the cost analysis in the TSD, 

as there is not currently adequate access 

to pipeline gathering systems on the 

FBIR to require RECs from well 

completion and recompletion 

operations, thus the current 

infrastructure is not amenable to this 

technique at this time. However, if we 

determine at a later date that there is a 

need for additional control of VOC 

emissions during oil and natural gas 

production well completion and 

recompletion operations on the FBIR, 

we may propose additional FIPs or 

propose supplements to this FIP. 

Comment: Commenter stated that the 

EPA failed to quantify the economic 

benefits of protecting public health and 

ecosystems from pollution in the FIP. 

Commenter stated that increased oil and 

natural gas production leads to 

increased levels of ozone in the 

surrounding area, risking public 

health.29 Commenter stated that the EPA 

must consider the medical and other 

public health costs associated with oil 

and natural gas production and 

resulting ozone in order to provide an 

accurate economic impact assessment 

for the FIP. 

Response: Given the accelerated 

development in this area, the high VOC 

emissions associated with the oil and 

natural gas operations and the absence 

of infrastructure on the FBIR, we 

determined the FIP should be effective 

immediately upon promulgation to 

ensure the protection of public health 

and the environment from exposure to 

air pollution, avoid fire hazards and 

protect the public from hazardous 

conditions. This FIP establishes 

regulations that significantly reduce 

VOC emissions from oil and natural gas 

production facilities on the FBIR, 

thereby protecting public health and the 

environment. This FIP is not a 

significant regulatory action under 

Executive Order 12866 and therefore an 

analysis of the potential costs and 

benefits associated with this action is 

not required. While we did not 

specifically quantify the economic 

benefits of protecting public health and 

the environment in the cost analysis, the 

control equipment required by this FIP 

is already extremely cost effective at less 

than $15/ton, and any additional cost 

benefits due to possible reduced public 

health costs would only result in 

increased cost effectiveness. Therefore, 

we believe the cost analysis sufficiently 

addresses the economic impacts for this 

action. 

I. Public Notice 

Comment: A commenter stated that 

the EPA did not provide the public with 

proper notice of the hearing, and 

therefore failed to ensure public 

participation in the rulemaking process. 

The commenter stated that the notice of 

the hearing in the tribal newspapers 

mistakenly referred to the hearing as a 

‘‘meeting,’’ which the commenter noted 

is quite different than a hearing. The 

commenter also stated that information 

about the hearing should have been 

advertised on the radio, and noted that 

many residents in the FBIR have limited 

internet access. Some commenters 

blamed lack of adequate notice on what 

they observed to be a low turnout at the 

hearing(s). One commenter stated that 

the oil companies had been given 

adequate notice, but the public had not. 

One commenter urged the EPA to come 

back and host more hearings. Several 

commenters requested an extension of 

the comment period, but none specified 

a suggested length of extension. 

Response: We disagree with these 

comments. We have exceeded the CAA 

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17850 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

public notice requirements for 

rulemaking. Under Section 307, the EPA 

is required to allow any person to 

submit written comments, data, or 

documentary information, as well as 

give interested persons an opportunity 

for the oral presentation of data, views, 

or arguments. The EPA is required to 

keep a transcript of any oral 

presentations and keep the record of the 

proceeding open for 30 days after 

completion of the proceeding to provide 

an opportunity for submission of 

rebuttal and supplementary 

information. The EPA is required to 

allow a reasonable period of at least 30 

days for public participation. 

As explained earlier in this notice, in 

promulgating this rule, the EPA is 

exercising its discretionary authority 

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

the CAA to promulgate regulations as 

necessary to protect tribal air resources. 

Therefore, while the Title I planning 

requirements of the CAA applicable to 

states do not directly apply to the EPA 

in promulgating a FIP in Indian 

Country, the EPA used the public notice 

requirements found within the planning 

requirements as a guide in developing 

this FIP. For this FIP, the EPA also 

followed the public hearing and public 

notice regulations in 40 CFR 51.102 as 

a guide. According to CAA sections 

301(a) and 301(d)(4) and 40 CFR 51.102, 

notice given to the public is to be 

provided by prominent advertisement in 

the affected area announcing the date(s), 

times(s), and place(s) of such hearings. 

Each proposed plan is to be made 

available for public inspection in at 

least one location in each region that it 

will apply. 

The proposed FIP was published in 

the Federal Register on August 15, 

2012. The Federal Register notice stated 

that public hearings would be held on 

September 12, 2012 from 1–4 p.m. and 

again at 6–8 p.m. at the 4 Bears Casino 

and Lodge in New Town, ND. An 

address for the location and contact 

information was provided. The Federal 

Register notice provided for a 60-day 

comment period, which required that 

public comments be received by the 

EPA Region 8 by October 15, 2012 and 

provided instructions for submitting 

comments. Two locations for review of 

publically available supporting docket 

materials for this FIP were listed 

including one at the EPA Region 8 office 

in Denver and one at the Environmental 

Division office of the Three Affiliated 

Tribes of the Mandan, Hidatsa, and 

Arikara Nation, in New Town, ND. A 

link for publically available electronic 

docket materials was listed in the 

Federal Register notice. 

A public notice was posted in the 

following newspapers regarding the 

availability of this FIP for public 

comment on August 15 and 17, 2012: 

Bismarck Tribune, Dickinson Press, 

Minot Daily News, New Town News, 

Williston Herald, MHA Times, and 

Mountrail County Record. This public 

notice included all of the information 

about the public hearings, docket review 

locations (including internet link), 

contact information, and the 

instructions for submittal of comments 

that was contained in the Federal 

Register notice. Additionally, this 

public notice listed seven locations and 

addresses where the public could 

review copies of this FIP and all 

supporting docket materials in addition 

to the two listed in the Federal Register 

notice, including: Three Affiliated 

Tribes of the Mandan, Hidatsa, and 

Arikara Nation’s Administration Office, 

New Town, ND; Fort Berthold 

Community College Library, New Town, 

ND; Mandaree Community Center, 

Mandaree, ND; Parshall Segment Office, 

Parshall, ND; Twin Buttes Memorial 

Hall, Halliday, ND; White Shield 

Segment Office, Roseglen, ND; and Four 

Bears Community Building, Four Bears 

Village, ND. The EPA confirmed that 

this public notice was published in each 

of the seven local newspapers. We 

confirmed that copies of the FIP and 

administrative records were received on 

August 13, 2012 by each of the nine 

locations listed above. 

We also prepared a public notice and 

request for comment bulletin. A copy of 

the bulletin was provided to the 

Director of the Three Affiliated Tribes of 

the Mandan, Hidatsa, and Arikara 

Nation Environmental Programs Office 

in New Town, ND on August 10, 2012 

with a request that it be posted in 

prominent locations throughout the 

Reservation and affected area. The 

bulletin provided a summary of the 

proposed rule, the contacts, the nine 

locations where the proposed rule and 

administrative records could be viewed, 

the date, times and location of the 

public hearings and referred the public 

to a link for publically available 

electronic docket materials. 

Additionally, we prepared a Public 

Service Announcement (PSA) for the 

local radio station, KMHA 91.3 FM 

Radio, Fort Berthold, New Town, ND. A 

copy of the PSA was provided to the 

Director of the Three Affiliated Tribes of 

the Mandan, Hidatsa, and Arikara 

Nation Environmental Programs Office 

in New Town, ND on August 10, 2012 

with a request that it be provided to the 

local radio station for broadcasting 

throughout the Reservation and affected 

area. The PSA provided a brief summary 

of the proposed rule, requested public 

comment through October 15, 2012, 

provided a contact, listed the eight 

locations on the FBIR where the 

proposed rule and administrative 

records could be viewed, and provided 

date, time(s) and location information 

for the September 12, 2012 public 

hearings. One of the commenters noted 

the PSA was aired on the local radio 

station. This is documented on Page 30 

of the public hearing transcript for 

September 12, 2012 at 6 p.m. 

Transcripts for both public hearings 

held on September 12, 2012 were 

generated and placed into the docket for 

this FIP. The comment period was kept 

open for 30 days after the public 

hearing. We verified that the seven 

newspaper notices published on August 

15 and 17, 2012 referenced the public 

hearings held on September 12, 2012 as 

‘‘public hearing’’ and not as a ‘‘public 

meeting.’’ This included the New Town 

News and the MHA Times in New 

Town, ND. The commenter may have 

intended to refer to the PSA instead of 

the newspaper regarding reference to a 

‘‘public meeting’’ instead of a ‘‘public 

hearing.’’ The PSA inadvertently 

referred to the ‘‘public hearing’’ as a 

‘‘public meeting.’’ 

These opportunities for public 

participation were provided equally to 

the public and the regulated 

community. All residents and the 

regulated community were given the 

same opportunities to request and 

access information, comment and 

participate in this rule making process. 

Based on the Federal Register notice, 

newspaper notices, posting public 

notice and request for comment bulletin 

at locations on the reservation, holding 

two public hearings, making public 

hearing transcripts publically available, 

providing a 60-day public comment 

period, PSA, and links for publically 

available electronic docket materials, 

the EPA has exceeded all legal 

requirements for proper public notice of 

this FIP. We therefore decided not to 

hold additional hearings and meetings, 

or extend the public comment period. 

Comment: Another commenter stated 

that the lack of adequate public notice 

was not compliant with environmental 

justice. 

Response: We disagree with this 

comment. Environmental justice is one 

of the Agency’s highest priorities and 

we believe the process used in 

developing this rule fully complies with 

the requirements of Executive Order 

12898 (59 FR 7629, February 16, 1994), 

which establishes federal executive 

policy on environmental justice (EJ). Its 

main provision directs federal agencies, 

to the greatest extent practicable and 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17851 

30See In re Shell Gulf of Mexico, Inc. & Shell 

Offshore, Inc., 15 EAD __, OCS Appeal Nos. 11-02, 

11-03, 11-04, 11-08, slip op. at 40 n. 38 (EAB Jan. 

12, 2012) (treating evidence of compliance with 

statutory and regulatory public participation 

requirements as showing sufficiency of 

participation for purposes of compliance with EO). 

A copy of the document has placed in the docket 

for this rule under Docket ID: EPA–R08–OAR– 

2012–0479, which can be accessed at: http:// 

www.regulations.gov. 

31For the purposes of this rule, an oil and natural 

gas production facility consists of one or more oil 

and natural gas wells and the air pollution emitting 

units that are utilized for production operations and 

storage operations for those wells. This definition 

was clarified from what was proposed in the 

interim final rule. Additionally, August 12, 2007 is 

the earliest well completion date identified in the 

CAFOs. 

permitted by law, to make EJ part of 

their mission by identifying and 

addressing, as appropriate, 

disproportionately high and adverse 

human health or environmental effects 

of their programs, policies, and 

activities on minority populations and 

low-income populations in the United 

States. EPA defines environmental 

justice as providing fair treatment and 

meaningful participation in 

environmental decision making. As 

detailed above, EPA exceeded CAA 

public notice requirements for 

rulemaking, and the record reflects 

extensive efforts to ensure meaningful 

participation in this case. The EPA’s 

Action Development Process, Interim 

Guidance for Considering 

Environmental Justice during the 

Development of an Action provides 

additional guidance for implementation 

of EO 12898 related to public notice for 

actions like rulemaking. This guidance 

suggests inclusion of one or more public 

meetings or hearings in or near affected 

communities and tribes. Public 

meetings or hearings should include 

sufficient notice and should be 

scheduled at a time and place 

convenient to the affected communities 

and tribes. Successful solicitation of 

public comments from affected 

communities and tribes may incorporate 

tailored outreach materials that are 

concise, understandable, and readily 

accessible to the communities to be 

reached. For remote towns and villages, 

local radio stations, local newspapers, 

and posters at village or community 

centers may represent the most effective 

approach. We employed these methods 

to ensure that we reached the FBIR EJ 

community and allowed for meaningful 

involvement of affected communities 

and tribes. 

While we understand that many 

residents on the FBIR do not have 

internet access, we employed numerous 

prominent advertisement methods not 

relying on the internet, including 

newspaper notices, posting public 

notice and request for comment bulletin 

at locations on the FBIR, holding public 

hearings, providing a 60-day public 

comment period, providing a PSA 

broadcast on local radio, as well as 

relying on the internet by providing 

links for publically available electronic 

docket materials. 

We conclude that the public notice 

process exceeded EPA’s legal 

obligations in rulemakings of this type, 

and that there is no reason to believe 

that such public notice was inadequate 

for compliance with the Executive 

Order.30 Although we agree that turnout 

was low at the September 12, 2012 

public hearings, we do not believe that 

additional public hearings or meetings 

would have significantly increased 

turnout. We believe that low turnout at 

the public hearings was due to factors 

other than the significant public notice 

methods employed. We employed every 

reasonable effort to encourage 

attendance at public hearings and obtain 

public comments on this FIP. 

We recognize that there are EJ 

concerns in the FBIR community. We 

have determined that this rule will not 

have disproportionately high and 

adverse human health or environmental 

effects on minority, low-income, and 

indigenous populations, because it 

ensures compliance with the NAAQS, 

which provides environmental and 

public health protection for all affected 

populations. Compliance with the 

NAAQS is relevant to an EJ claim to the 

extent that the NAAQS are health-based 

standards, designed to protect public 

health with an adequate margin of 

safety, including sensitive populations 

such as children, the elderly, and 

asthmatics. 

Comment: A commenter asked if the 

annual report of FBIR facility activity 

would be accessible by the public. 

Response: These reports will be 

submitted to the EPA Region 8 office in 

Denver, Colorado and maintained on 

file and will be available to the public. 

The documents may be obtained 

through the Freedom of Information Act 

(FOIA) process. If you seek a record, you 

should address your request to the EPA 

Region 8 FOIA Office. Requests for 

records can be sent by mail to FOIA 

office at Regional Freedom of 

Information Officer; U.S. EPA, Region 8, 

Mailcode: 8–OC; 1595 Wynkoop Street; 

Denver, CO 80202–1129. Request may 

also be made by electronic mail to 

r8foia@epa.gov, by facsimile at (303) 

312–6859, or by telephone at (303) 312– 

6856. Your request should be as specific 

as possible with regard to the subject, 

time frames, and locations. You do not 

have to give a requested record’s name 

or title, but the more specific you are; 

the more likely it will be that the record 

you seek can be located. For example, 

if you are seeking records dealing with 

the FIP annual reports, request the FBIR 

FIP Annual Reports, the owner or 

operator you seek information on, and 

the calendar year(s) for the reports you 

seek. 

V. Summary of Final Rule and 

Significant Changes from the Proposed 

and Interim Final Rule 

A. Administrative Edits 

Correction: In the proposed rule we 

identified incorrect citations to the Code 

of Federal Regulations (CFR) for 

publishing the rule. The final rule has 

been promulgated at Subpart K of 40 

CFR part 49 which is specific to Region 

8 FIPs. 

§ 49.140 is now § 49.4161; 

§ 49.141 is now § 49.4162; 

§ 49.142 is now § 49.4163; 

§ 49.143 is now § 49.4164; 

§ 49.144 is now § 49.4165; 

§ 49.145 is now § 49.4166; 

§ 49.146 is now § 49.4167; and 

§ 49.147 is now § 49.4168. 

B. Introduction 

This rule applies to any person who 

owns or operates an existing 

(constructed or modified on or after 

August 12, 2007), new, or modified oil 

and natural gas production facility 31

that is located on the FBIR and 

producing from the Bakken Pool with 

one or more oil and natural gas wells, 

any one of which a well completion or 

recompletion operation is/was initiated 

on or after August 12, 2007. 

For the purposes of this rule, a well 

completion means the process that 

allows for the flowback of oil and 

natural gas from newly drilled wells to 

expel drilling and reservoir fluids and 

tests the reservoir flow characteristics, 

which may vent produced hydrocarbons 

to the atmosphere via an open pit or 

tank. A well completion operation 

means any oil and natural gas well 

completion with hydraulic fracturing 

occurring at an oil and natural gas 

production facility. The completion date 

is considered the date that construction 

at an oil and natural gas production 

facility has commenced. The 

recompletion date is considered the date 

that a modification has occurred at an 

oil and natural gas production facility. 

The reason we selected the initiation of 

completions operations as the date for 

defining a new facility is that owners 

and operators use drill rigs prior to 

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32U.S. Environmental Protection Agency. Lessons 

Learned from Natural Gas STAR Partners: Reduced 

Emissions Completions for Hydraulically Fractured 

Natural Gas Wells. Office of Air and Radiation: 

Natural Gas Star Program. Washington, DC. 

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

reduced_emissions_completions.pdf. Accessed July 

26, 2012. A copy of this document has been placed 

in the docket for this rule under Docket ID: EPA– 

R08–OAR–2012–0479, which can be accessed at: 

http://www.regulations.gov. 

initial completion operations and this 

equipment is generally not in one 

location long enough to be considered a 

stationary source. In addition, it is not 

certain during the drilling operations 

whether a well will be a producing well. 

Hence, it is not known whether an oil 

and natural gas production facility will 

be constructed to support that well. The 

outcome of a completion operation 

provides the well owners and operators 

information necessary to determine 

whether an oil and natural gas 

production facility will be constructed. 

Clarification: We have added 

language to the introduction at 

§ 49.4161(b) to clarify that, for the 

purposes of this rule, the initiation of 

well completion operations and well 

recompletion operations are the dates 

that construction and modifications 

commence, as set forth in the regulatory 

text of this final rule. 

Compliance with the rule is required 

no later than June 20, 2013 or upon 

initiation of well completion or 

recompletion operations, whichever is 

later. Upon signature by the 

Administrator, we will post this rule on 

our internet site (http://www.epa.gov/ 

region8/air/fbirfip.html) and notify the 

owners and operators and the Three 

Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nation. 

Clarification: We have changed the 

language in the introduction at 

§ 49.4161(c) to clarify that the 

compliance date is upon initiation of 

well completion operations and well 

recompletion operations, as follows: 

‘‘§ 49.4161(c) When must I comply with 

§§ 49.4161 through 49.4168? 

Compliance with §§ 49.4161 through 

49.4168 is required no later than June 

20, 2013 or upon initiation of well 

completion operations or well 

recompletion operations, whichever is 

later.’’ 

C. Provisions for Delegation of 

Administration to the Three Affiliated 

Tribes of the Mandan, Hidatsa, and 

Arikara Nation 

The provisions in § 49.4162 establish 

the steps by which the Three Affiliated 

Tribes of the Mandan, Hidatsa, and 

Arikara Nation may request delegation 

to assist us with the administration of 

this rule and the process by which the 

Regional Administrator of the EPA 

Region 8 may delegate to the Tribes the 

authority to assist with such 

administration of this rule. As described 

in the regulatory provisions, any such 

delegation will be accomplished 

through a delegation of authority 

agreement between the Regional 

Administrator and the Three Affiliated 

Tribes of the Mandan, Hidatsa, and 

Arikara Nation. This section provides 

for administrative delegation of this 

federal rule and does not affect the 

eligibility criteria under CAA section 

301(d) and 40 CFR 49.6 for TAS should 

the Tribes decide to seek such treatment 

for the purpose of administering their 

own EPA-approved program under 

tribal law. Administrative delegation is 

a separate process from TAS under the 

TAR. Under the TAR, Indian tribes seek 

EPA-approval of their eligibility to run 

CAA programs under their own laws. 

The Three Affiliated Tribes of the 

Mandan, Hidatsa, and Arikara Nation 

would not need to seek TAS under the 

TAR for purposes of requesting to assist 

us with administration of this rule 

through a delegation of authority 

agreement. In the event such an 

agreement is reached, the rule would 

continue to operate under federal 

authority throughout the FBIR, and the 

Tribes would assist us with 

administration of the rule to the extent 

specified in the agreement. 

D. General Provisions 

The provisions in § 49.4163 General 

Provisions provide: (1) Definitions that 

apply to this rule; (2) assurance that we 

will maintain its authority to require 

testing, monitoring, recordkeeping, and 

reporting in addition to that already 

required by an applicable requirement, 

in a permit to construct or permit to 

operate in order to ensure compliance; 

and (3) assurance that nothing in the 

rule will preclude the use, including the 

exclusive use, of any credible evidence 

or information, relevant to whether a 

facility would have been in compliance 

with applicable requirements if the 

appropriate performance or compliance 

test had been performed. 

E. Construction and Operational Control 

Measures 

The provisions in § 49.4164 

Construction and Operational Control 

Measures provide requirements to 

reduce VOC emissions during well 

completion and recompletion 

operations. The owner or operator must 

route all casinghead natural gas 

emissions associated with completion 

and recompletion operations to a utility 

flare or a pit flare capable of reducing 

the mass content of VOCs in the natural 

gas vented to it by at least 90.0%. We 

note that the well completion and 

recompletion control requirements to 

use pit flares or utility flares that have 

the capability to reduce the mass 

content of VOC in the natural gas 

emissions routed to them by at least 

90.0% percent by weight are the 

minimum level of control that will be 

allowed under this rule. Owners and 

operators may also choose to perform 

reduced emission completions and 

recompletions 32, which would exceed 

the 90.0% VOC emission reduction 

requirement. This section also requires 

the control of production and storage 

operations and imposes a timeline for 

installation of the controls on these 

operations. The owner or operator is 

required to reduce the mass content of 

VOC emissions from natural gas during 

oil and natural gas production and 

storage operations by at least 90.0% 

percent on the first date of production. 

Within 90 days of the first date of 

production, we require the owner or 

operator to route the natural gas from 

the production and storage operations 

through a closed-vent system to a utility 

flare or equivalent combustion device 

capable of reducing the mass content of 

VOC in the natural gas vented to the 

device by at least 98.0%. The owner or 

operator also has the option to design 

their production and storage operations 

to recover the natural gas as product and 

inject it into a natural gas gathering 

pipeline system for sale or other 

beneficial purpose. For those owners or 

operators that choose to capture the 

natural gas as product rather than a 

pollutant to be controlled, the natural 

gas may temporarily be routed through 

a closed-vent system to an enclosed 

combustor, utility flare or pit flare in 

instances where injection of the product 

into the pipeline is temporarily 

infeasible. In these situations, the pit 

flare is considered a backup standby 

unit used for unplanned flare events, 

such as during temporarily limited 

pipeline capacity, that are beyond a 

producer’s control and the pit flare is 

used to safely burn the natural gas 

product that could otherwise pose a 

potential risk to workers, the 

community, or the environment. The 

owner or operator, however, must limit 

the use of the pit flare in these instances 

to 500 hours in any consecutive 12- 

month period. 

The rule requires the owner or 

operator to route all standing, working, 

breathing and flashing losses from the 

produced oil storage tanks and any 

produced water storage tanks 

interconnected with the produced oil 

storage tanks through a closed vent 

system to either an operating system 

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33 If the owner or operator receives written 

approval for a new method from the EPA, the owner 

or operator must calculate potential to emit based 

on the new EPA-approved method. 

designed to recover and inject the 

natural gas emissions into a natural gas 

gathering pipeline system for sale or 

other beneficial use, or to an enclosed 

combustor or utility flare capable of 

reducing the mass content of VOC in the 

natural gas emissions vented to the 

device by at least 98.0%. However, to 

prevent duplicative federal 

requirements for owners and operators 

of storage tanks on the FBIR subject to 

both this rule and NSPS OOOO, storage 

tanks subject to and controlled under 

the requirements specified in 40 CFR 

part 60, subpart OOOO are considered 

to meet the storage tank control 

requirements of this rule. No further 

requirements apply for such storage 

tanks under this rule. In addition, the 

rule provides that if the uncontrolled 

PTE of VOCs from the aggregate of all 

produced oil storage tanks and 

produced water storage tanks 

interconnected with produced oil 

storage tanks at an oil and natural gas 

production facility is less than, and 

reasonably expected to remain below, 

20 tons in any consecutive 12-month 

period, then the owner or operator may 

use a utility flare or enclosed combustor 

that is capable of reducing the mass 

content of VOC in the natural gas 

emissions vented to the device by only 

90.0% upon prior written approval by 

the EPA.33

The control devices must be operated 

under specific conditions as specified in 

§ 49.4165 Control Equipment 

Requirements and § 49.4166 Monitoring 

Requirements. 

F. Control Equipment Requirements 

The provisions in § 49.4165 Control 

Equipment Requirements require the 

use of covers on all produced oil and 

water storage tanks and the use of 

closed-vent systems with all VOC 

capture and control equipment. Section 

49.4165 also specifies construction and 

operational requirements for the covers 

and closed-vent systems. In addition, 

§ 49.4165 requires specific construction 

and operational requirements of pit 

flares, enclosed combustors, and utility 

flares. 

The provisions in § 49.4165 require 

that each owner and operator equip the 

openings on each produced oil storage 

tank and each produced water storage 

tank that is interconnected with 

produced oil storage tanks with a cover 

that ensures that natural gas emissions 

are efficiently routed through a closedvent system to a vapor recovery system 

an enclosed combustor, or a utility flare. 

Each cover and all openings on the 

cover (e.g., access hatches, sampling 

ports, and gauge wells) must form a 

continuous barrier over the entire 

surface area of the produced oil and 

produced water in the storage tank. 

Each cover opening must be secured in 

a closed, sealed position (e.g., covered 

by a gasketed lid or cap) whenever 

material is in the tank on which the 

cover is installed except during those 

times when it is necessary to use an 

opening as follows: (1) To add material 

to, or remove material from the unit 

(this includes openings necessary to 

equalize or balance the internal pressure 

of the unit following changes in the 

level of the material in the unit); or (2) 

to inspect or sample the material in the 

unit; or to inspect, maintain, repair, or 

replace equipment located inside the 

unit. 

Each owner and operator is required 

to use closed-vent systems to collect and 

route natural gas emissions to the 

respective VOC control devices. All vent 

lines, connections, fittings, valves, relief 

valves, or any other appurtenance 

employed to contain and collect gases, 

and transport them to the VOC control 

equipment must be maintained and 

operated properly during any time the 

control equipment is operating and 

must be designed to operate with no 

detectable natural gas emissions. If a 

closed-vent system contains one or more 

bypass devices that could be used to 

divert all or a portion of the natural gas 

from entering the VOC control devices, 

the owner or operator must meet one of 

the following options for each bypass 

device: (1) At the inlet to the bypass 

device properly install, calibrate, 

maintain, and operate a natural gas flow 

indicator capable of taking periodic 

readings and sounding an alarm when 

the bypass device is open such that the 

natural gas is being, or could be, 

diverted away from the control device 

and into the atmosphere; or (2) secure 

the bypass device valve in the nondiverting position using a car-seal or a 

lock-and-key type configuration. 

Each owner or operator is required to 

follow the manufacturer’s written 

operating instructions, procedures and 

maintenance schedule to ensure good 

air pollution control practices for 

minimizing emissions from each 

enclosed combustor or utility flare. Each 

enclosed combustor must have the 

capacity to reduce the mass content of 

the VOC in the natural gas routed to it 

by at least 98.0% for the minimum and 

maximum natural gas volumetric flow 

rate and British Thermal Unit (BTU) 

content routed to it. For the purposes of 

this rule, we require that all utility flares 

installed per this rule meet the 

requirements in 40 CFR 60.18(b), and all 

enclosed combustors installed per this 

rule must be tested according to the 

NSPS OOOO performance testing 

requirements. Until such time that 

compliance is required with the storage 

vessel requirements in the NSPS OOOO 

standard, however, the owner or 

operators can demonstrate compliance 

using methods specified in this rule. 

We determined that certain work 

practice and operational requirements 

are also necessary for the practical 

enforceability of the VOC emission 

reduction requirement that the enclosed 

combustors or utility flares must 

achieve. Flares and combustors must be 

operated within specific parameters to 

effectively destroy VOC emissions. 

Therefore, each owner or operator must 

ensure that each enclosed combustor or 

utility flare is: (1) Operated at all times 

that produced natural gas and natural 

gas emissions are routed to it; (2) 

operated with a liquid knock-out system 

to collect any condensable vapors (to 

prevent liquids from going through the 

control device); (3) equipped with a 

flash-back flame arrestor; (4) equipped 

with a continuous burning pilot flame 

or an electronically controlled 

electronically controlled automatic 

igniter system; (5) equipped with a 

monitoring system for continuous 

recording of the parameters that indicate 

proper operation of each enclosed 

combustor, utility flare, continuous 

burning pilot flame and electronically 

controlled automatic igniter, such as a 

chart recorder, data logger, or similar 

devices; (6) maintained in a leak free 

condition; and (7) operated with no 

visible smoke emissions. 

Section 49.4165 requires that each 

owner or operator limit the use of pit 

flares to: (1) The control natural gas 

emissions during well completion 

operations; (2) the control of VOC 

emissions in the event the natural gas 

that is being recovered for sale or other 

beneficial purpose must be diverted to 

a backup control device because 

injection into the pipeline is 

temporarily infeasible and there is no 

operational enclosed combustor or 

utility flare at the oil and natural gas 

production facility, in which instances 

the owner or operator must limit use of 

the pit flare to no more than 500 hours 

in any consecutive 12-month period; or 

(3) use when total uncontrolled PTE of 

VOCs from all produced oil storage 

tanks and any produced water storage 

tanks interconnected with produced oil 

storage tanks at an oil and natural gas 

production facility have declined to less 

than, and are reasonably expected to 

stay below, 20 tons in any consecutive 

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12-month period. Each pit flare must be 

operated to reduce the mass content of 

VOC in the natural gas routed to it by 

at least 90.0% and must be operated 

with no visible smoke emissions. Each 

pit flare must be equipped with an 

electronically controlled automatic 

igniter with malfunction alarm and 

remote notification system if the pilot 

flame fails. Each pit flare must be 

visually inspected for the presence of a 

pilot flame any time natural gas is being 

routed to it and if the pilot flame fails, 

it must be relit as soon as safely possible 

and the electronically controlled 

automatic igniter must be repaired or 

replaced before the pit flare is used 

again. 

Section 49.4165 allows owners or 

operators of oil and natural gas 

production facilities to use control 

devices other than an enclosed 

combustor or utility flare, provided they 

are capable of achieving at least a 98.0% 

VOC destruction efficiency and upon 

our prior written approval by the EPA. 

This provision will allow for owner or 

operators to take advantage of 

technological advances in VOC 

emission control for the oil and natural 

gas production industry and will 

provide us with valuable information on 

any new control technologies. 

Deletion: We have deleted the testing 

requirement at § 49.4165(c)(5)(iii). This 

was a temporary enclosed combustor 

testing requirement that applied until 40 

CFR part 60 subpart OOOO-New Source 

Performance Standard for Oil and 

Natural Gas Sector (NSPS OOOO) was 

promulgated. Since NSPS OOOO was 

promulgated on August 16, 2012 and 

became effective on October 15, 2012, 

this temporary provision is no longer 

necessary. 

Correction: We have clarified control 

equipment requirements at 

§ 49.4165(c)(4). We have added language 

at § 49.4165(c)(4) to provide an 

exemption to § 60.18(c)(2) and (f)(2) for 

those utility flares operated with an 

electronically controlled automatic 

igniter as set forth in the regulatory text 

of this final rule. 

Clarification: We have clarified that 

enclosed combustors and utility flares 

must be operated properly at all times 

that produced natural gas and/or natural 

gas emissions are routed to them, rather 

than just the term natural gas. The rule 

now reads as set forth in the regulatory 

text of this final rule at 

§ 49.4165(c)(6)(i). 

Correction: We have removed the 

requirement to install equipment for the 

monitoring of continuous burning pilot 

flames and electronically controlled 

automatic igniters on flares and 

combustors. These requirements were 

already provided for at § 49.4166(g)(1). 

The rule now reads as set forth in the 

regulatory text of this final rule at 

§ 49.4165(c)(6)(iv). 

Clarification: We have clarified the 

purpose for equipping utility flares and 

enclosed combustors with a monitoring 

system. We have revised the applicable 

provisions to read as set forth in the 

regulatory text of this final rule at 

§ 49.4165(c)(6)(v). 

Correction: We removed the 

requirement to monitor a pilot flame on 

pit flares since these flares are to be 

operated with electronically controlled 

automatic igniters only. The rule now 

reads as set forth in the regulatory text 

of this final rule at § 49.4165((d)(3(iv) 

and (v). 

G. Monitoring Requirements 

Section 49.4166 Monitoring 

Requirements requires each owner or 

operator conduct certain monitoring 

that we determined is necessary for the 

practical enforceability of the VOC 

emission reduction requirements, 

including but not limited to: (1) 

Monitoring of the number of barrels of 

oil produced at the facility each time the 

oil is unloaded from the produced oil 

storage tanks; (2) Monitoring of the 

hours of operation of each pit flare used 

to control VOC emissions in the event 

the natural gas that is being recovered 

for sale or other beneficial purpose must 

be diverted to a backup control device 

because injection into the pipeline is 

temporarily infeasible and there is no 

operational enclosed combustor or 

utility flare is at the oil and natural gas 

production facility; (3) Monitoring of 

the volume of produced natural gas 

from the heater-treater sent to each 

enclosed combustor, utility flare, and 

pit flare at all times; (4) Monitoring of 

the volume of standing, working, 

breathing, and flashing losses from the 

produced oil and produced water 

storage tanks sent to each vapor 

recovery system, enclosed combustor, 

utility flare, and pit flare at all times; (5) 

Visually inspecting storage tank thief 

hatches, covers, seals, PRVs, and closedvent systems to insure proper condition 

and functioning; (6) Directly and 

continuously measuring, various 

parameters (i.e., product throughput, 

enclosed combustor flame presence, 

temperature, etc.) related to the proper 

operation of emissions units and 

required control devices to assure 

compliance with the emissions 

reduction requirements and operational 

limitations; and (7) Visually inspect all 

equipment associated with each 

enclosed combustor, utility flare, and 

pit flare at a minimum quarterly to 

ensure system integrity; (8) Visually 

monitoring for visible smoke from 

enclosed combustors, utility flares, and 

pit flares during operation. 

The monitoring, recordkeeping and 

reporting requirements for the covers, 

close-vent systems, pit flares, enclosed 

combustors, and utility flares are 

intended to provide legal and 

practicable enforceability of the 

emission control requirements. 

Correction: We have added 

monitoring requirements at § 49.4166(d) 

to describe acceptable gas volume 

measurement methods, thus making this 

provision consistent with the provision 

at § 49.4166(c). The rule now reads as 

set forth in the regulatory text of this 

final rule. 

Revision: We have included more 

flexibility in the options for monitoring 

approaches. We have revised the 

applicable provisions to read as set forth 

in the regulatory text of this final rule 

at § 49.4166(g)(1). 

Revision: We have clarified the intent 

of the provision at § 49.4166(g)(2) in the 

final FIP to read as set forth in the 

regulatory text of this final rule: 

Revision: We have revised the smoke 

monitoring provisions at § 49.4166(g)(3) 

in the final FIP to read as set forth in 

the regulatory text of this final rule. 

Revision: We have added a new 

monitoring provision at § 49.4166(i) to 

allow for other monitoring options upon 

prior written approval by the EPA, as set 

forth in the regulatory text of this final 

rule. 

H. Recordkeeping Requirements 

Section 49.4167 Recordkeeping 

Requirements requires that each owner 

or operator of an oil and natural gas 

production facility keep specific records 

to be made available upon our request, 

in lieu of voluminous reporting 

requirements. The records that must be 

kept include, but are not limited to, all 

required measurements, monitoring, 

and deviations or exceedances of rule 

requirements and corrective actions 

taken, as well as any manufacturer 

specifications and guarantees or 

engineering analyses. These 

recordkeeping requirements provide 

legal and practical enforceability to the 

control and emission reduction 

requirements of this rule. 

Clarification: We have clarified the 

recordkeeping requirements at 

§ 49.4167(a)(4)(ii) to correctly identify 

that casing head gas vented from 

producing wells should be monitored, 

not produced natural gas. The rule now 

reads as set forth in the regulatory text 

of this final rule. 

Revision: We have revised the 

recordkeeping requirements at 

§ 49.4167(a)(8) to clarify that records 

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must be maintained of the volume of 

natural gas emissions released when 

close-vent systems and control devices 

have been bypassed or were not 

operating. The rule now reads as set 

forth in the regulatory text of this final 

rule. 

Correction: We have corrected the 

recordkeeping requirements at 

49.4167(a)(5)(iv) to include the 

requirement to keep records of any 

instance in which an electronically 

controlled automatic igniter has failed. 

The rule now reads as set forth in the 

regulatory text of this final rule. 

I. Reporting Requirements 

Section 49.4168 Notification and 

Reporting Requirements requires that 

each owner or operator of an oil and 

natural gas production facility prepare 

and submit an annual report, beginning 

one year after this rule becomes 

effective covering the period for the 

previous calendar year. The report must 

include a summary of required records 

identifying each oil and natural gas 

production well completion or 

recompletion operation for each facility 

conducted during the reporting period, 

an identification of the first date of 

production for each oil and natural gas 

production well at each facility that 

commenced operation during the 

reporting period, and a summary of 

deviations or exceedances of any 

requirements of this FIP and the 

corrective measures taken. Additionally, 

a report must be submitted for any 

performance test we require. 

Clarification: Upon further review of 

the language at § 49.4168(b) regarding 

annual reporting requirements, we 

determined it was necessary to clarify 

the requirement based on our original 

intent. The provision now reads as set 

forth in the regulatory text of this final 

rule: 

We decided not to require owners or 

operators to register their oil and natural 

gas production facilities, because the 

Federal Tribal NSR Rule at 40 CFR 

49.151 already requires registration of 

existing minor sources and such a 

requirement in this rule would be 

redundant. 

These reporting requirements are part 

of providing legal and practical 

enforceability to the control and 

emission reduction requirements of this 

rule. 

Revision: As explained in the 

response to comments above, we have 

added a provision for notification and 

reporting requirements at 

§ 49.4168(b)(4)(iv) requiring owners or 

operators to certify as to the truth, 

accuracy and completeness of the 

annual reports. The new provision is 

consistent with the NSPS OOOO (40 

CFR 60.5420(b)(1)(iv)) and reads as set 

forth in the regulatory text of this final 

rule. 

J. Effect on Permitting of Facilities 

This rule is not a permitting program. 

It does not impose or exempt the 

facilities from any federal CAA 

permitting requirements, including the 

PSD preconstruction permitting 

requirements at 40 CFR 52.21, Federal 

Tribal NSR Rule permitting 

requirements for minor sources at 40 

CFR 49.151, or federal Title V operating 

permit requirements at 40 CFR part 71. 

The primary purpose of this rule is to 

address potential impacts to the public 

health and the environment. However, 

the rule does provide legal and practical 

enforceability for the use of VOC 

emission controls that are already being 

used voluntarily by the industry and for 

VOC emissions reductions from those 

controls. Provided that the facilities are 

in compliance with the new rule, they 

may take into account the enforceable 

VOC emission reductions from the 

required controls they use when 

calculating their PTE for determining 

applicability of the federal permitting 

requirements, to the extent that the 

effect those controls would have on 

VOC emissions is legally and 

practicably enforceable. 

Regardless of this rule, due to the high 

amount of associated natural gas in the 

crude oil and the absence of 

infrastructure to collect the natural gas 

on the FBIR, some FBIR facilities’ PTE 

of VOCs or any other pollutant subject 

to regulation may exceed the 

applicability thresholds for PSD, 

Federal Tribal NSR Rule, or Title V 

permitting even after accounting for the 

legally and practicably enforceable 

emission reductions provided in this 

rule. In such cases, the owners or 

operators of these facilities are required 

to apply for and obtain the appropriate 

permits in accordance with the 

regulation. 

K. Registration Requirements 

This rule does not exempt facilities 

located on the FBIR from the 

registration requirements of the Federal 

Tribal NSR Rule, promulgated on July 1, 

2011. Nor does this rule impose any 

additional registration requirements. 

The primary purpose of this rule is to 

address potential impacts to the public 

health and the environment. Provided 

that the facilities are in compliance with 

the provisions of this rule, facilities may 

include the enforceable VOC emission 

reductions resulting from the controls 

required in this rule when calculating 

their PTE, to the extent that the effect 

those controls would have on VOC 

emissions is legally and practicably 

enforceable. 

If the PTE VOCs or any other 

regulated NSR pollutant is less than the 

major source thresholds in 40 CFR 

52.21, but equal to or greater than the 

thresholds in the Federal Tribal NSR 

Rule, then registration is required of 

these facilities (40 CFR 49.160). Those 

facilities that must obtain a PSD permit 

pursuant to 40 CFR 52.21 or wish to 

obtain a preconstruction permit 

pursuant to 40 CFR 49.151 of the 

Federal Tribal NSR Rule, in addition to 

meeting the requirements of this rule, 

are exempt from this registration 

requirement. 

VII. Statutory and Executive Order 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

B. Paperwork Reduction Act 

The information collection 

requirements in this rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. An Information Collection 

Request (ICR) document has been 

prepared by us, and a copy is available 

in the docket for this action. The 

information collection requirements are 

not enforceable until OMB approves 

them. The ICR document prepared by us 

has been assigned the EPA ICR tracking 

number 2478.01. 

The information requirements are 

based on notification, recordkeeping 

and reporting requirements in this FIP 

(40 CFR part 49, subpart K). These 

requirements are mandatory for each 

owner or operator (1) Located on the 

Fort Berthold Indian Reservation; (2) 

constructing or operating an oil or 

natural gas production facility 

producing from the Bakken Pool with 

one or more oil and natural gas wells 

and (3) for which completion or 

recompletion operations are/were 

performed on or after August 12, 2007. 

See 40 CFR 49.4161. These records and 

reports are necessary for the EPA 

Administrator (or the tribal agency if 

delegated), for example, to: (1) Confirm 

compliance status of stationary sources; 

(2) identify any stationary sources not 

subject to the requirements and identify 

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17856 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

stationary sources subject to the 

regulations; and (3) ensure that the 

stationary source control requirements 

are being achieved. The information 

would be used by the EPA or tribal 

enforcement personnel to: (1) Indentify 

stationary sources subject to the rules; 

(2) ensure that appropriate control 

technology is being properly applied; 

and (3) ensure that the emission control 

devices are being properly operated and 

maintained on a continuous basis. 

Based on the reported information, the 

EPA Administrator (or the delegated 

tribe) can decide which stationary 

sources, records or processes should be 

inspected. 

Specifically, this FIP requires that 

each owner or operator conduct certain 

monitoring that we determined is 

necessary for the practical enforceability 

of the VOC emission reduction 

requirements. See 40 CFR 49.4166. The 

recordkeeping requirements in 40 CFR 

49.4167 require that each owner or 

operator keep specific records to be 

made available at the EPA’s request. The 

recordkeeping requirements require 

only the specific information needed to 

determine compliance. Finally, the rules 

contain reporting requirements in 40 

CFR 49.4168 that require each owner or 

operator to prepare and submit an 

annual report. These recordkeeping and 

reporting requirements are specifically 

authorized by CAA section 114 (42 

U.S.C. 7414). We believe these 

information collection requirements are 

appropriate because they will enable us 

to develop and maintain accurate 

records of air pollution sources and 

their emissions, will provide the 

necessary legal and practical 

enforceability, and will ensure 

appropriate records are available to 

verify compliance with this FIP. All 

information submitted to us pursuant to 

the recordkeeping and reporting 

requirements for which a claim of 

confidentiality is made is safeguarded 

according to the Agency policies set 

forth in 40 CFR part 2, subpart B. 

It is estimated that 780 oil and natural 

gas production facilities will be subject 

to this FIP over the next three years. The 

oil and natural gas production facilities 

subject to this rule will incur 

approximately 29,655 hours in annual 

monitoring, reporting, and 

recordkeeping burden (averaged over 

the first three years after the effective 

date of the rule), incurring an estimated 

$6.5 million ($2012) in burden. This 

includes an annual average of 29,655 

labor hours per year at a total labor cost 

of $1.4 million per year, average 

annualized capital costs of $2.2 million 

per year, average annual operating and 

maintenance costs of $2.9 million per 

year, and an average annual estimate of 

623 likely respondents over the next 

three years. This estimate includes the 

testing requirements, emission reports, 

developing a monitoring plan, 

notifications and recordkeeping. All 

burden estimates are in 2012 calendar 

year dollars and represent the most costeffective monitoring approach for 

affected facilities. Burden is defined at 

5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for our regulations in 40 CFR 

are listed in 40 CFR part 9. When this 

ICR is approved by OMB, we will 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

display the OMB control number for the 

approved information collection 

requirements contained in this final 

rule. 

To assist members of the public who 

would like to provide comments on the 

ICR, our need for this information, the 

accuracy of the provided burden 

estimates, and any suggested methods 

for minimizing respondent burden, we 

established a public docket for this rule, 

which includes this ICR, under Docket 

ID: EPA–R08–OAR–2012–0479. Submit 

any comments related to the ICR to the 

EPA and OMB. See ADDRESSES section 

at the beginning of this notice for 

information on submitting comments to 

the EPA. Send comments to OMB at the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget, 725 17th Street NW., 

Washington, DC 20503, Attention: Desk 

Office for EPA. Since OMB is required 

to make a decision concerning the ICR 

between 30 and 60 days after March 22, 

2013, please attempt to send comments 

to OMB by April 22, 2013. Before 

finalizing the information collection 

requirements, we will respond to any 

comments submitted to the EPA or 

OMB. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

In determining whether a rule has a 

significant economic impact on a 

substantial number of small entities, the 

impact of concern is any significant 

adverse economic impact on small 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the rule 

on small entities’’ (5 U.S.C. 603 and 

604). Thus, an agency may certify that 

a rule will not have a significant 

economic impact on a substantial 

number of small entities if the rule 

relieves regulatory burden, or otherwise 

has a positive economic effect on all of 

the small entities subject to the rule. 

This rule will not have a significant 

economic impact on a substantial 

number of small entities due to the 

reduced regulatory requirement, and 

thus the regulatory burden, to obtain 

federal CAA permits that this rule 

provides. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. As 

discussed in the TSD and preamble for 

the interim final rule, we determined 

the maximum annual cost of 

compliance with this rule on the oil and 

natural gas industry is estimated to be 

approximately $50 million. However, 

we believe this is a conservative 

estimate and that actual annual costs 

would be much lower due to factors 

such as increased facility well density, 

standard industry practice to use VOC 

control equipment, and anticipated 

pipeline infrastructure development, 

which is explained further in the TSD. 

Thus, this rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This rule does not contain a 

significant federal intergovernmental 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17857 

mandate as described by section 203 of 

UMRA. Therefore, this rule is also not 

subject to the requirements of section 

203 of UMRA because it contains no 

regulatory requirements that might 

significantly or uniquely affect small 

governments. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This rule 

regulates under the CAA certain 

stationary sources in Indian country that 

are not subject to approved CAA 

programs of the State of North Dakota. 

Thus, Executive Order 13132 does not 

apply to this action. Although section 6 

of Executive Order 13132 does not 

apply to this action, we consulted with 

the Three Affiliated Tribes of the 

Mandan, Hidatsa, and Arikara Nation in 

developing this action. A summary of 

the consultation is provided below in 

section F of this preamble. In the spirit 

of Executive Order 13132, and 

consistent with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicited comment on the proposed 

action from State and local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 6, 2000), requires us 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ ‘‘Policies that have tribal 

implications’’ is defined in the 

Executive Order to include regulations 

that have ‘‘substantial direct effects on 

one or more Indian tribes, on the 

relationship between the Federal 

Government and the Indian tribes, or on 

the distribution of power and 

responsibilities between the Federal 

Government and Indian tribes.’’ 

Under Section 5(b) of Executive Order 

13175, we may not issue a regulation 

that has tribal implications, that 

imposes substantial direct compliance 

costs, and that is not required by statute, 

unless the Federal Government provides 

the funds necessary to pay the direct 

compliance costs incurred by tribal 

governments, or we consult with tribal 

officials early in the process of 

developing the proposed regulation. 

Under Section 5(c) of Executive Order 

13175, we may not issue a regulation 

that has tribal implications and that 

preempts tribal law, unless the Agency 

consults with tribal officials early in the 

process of developing the proposed 

regulation. 

We concluded that this final rule will 

have tribal implications. However, it 

will neither impose substantial direct 

compliance costs on tribal governments, 

nor preempt tribal law. These 

regulations would affect the FBIR 

community by establishing air quality 

regulations and thus creating a level of 

air quality protection not previously 

provided under the CAA. The regulatory 

approach used in this rule would create 

federal requirements similar to those 

that are already in place areas adjacent 

to the Reservation. Finally, although 

tribal governments are encouraged to 

partner with us on the implementation 

of these regulations, they are not 

required to do so. Since this final rule 

will neither impose substantial direct 

compliance costs on tribal governments, 

nor preempt tribal law, the requirements 

of Sections 5(b) and 5(c) of the 

Executive Order do not apply to this 

rule. 

Consistent with EPA policy, the EPA 

consulted with tribal officials and 

representatives of the Three Affiliated 

Tribes of the Mandan, Hidatsa and 

Arikara Nation early in the process of 

developing this regulation to permit 

them to have meaningful and timely 

input into its development. 

Tribal consultation with the Three 

Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nation was first 

initiated on February 17, 2012 when we 

mailed a letter inviting the Tribes to 

consult on the first group of synthetic 

minor NSR permits being issued on the 

Reservation under the Federal Tribal 

NSR Rule. Then, on March 29, 2012, 

EPA senior management and the 

Chairman of the Three Affiliated Tribes 

of the Mandan, Hidatsa, and Arikara 

Nation along with other government 

officials met via conference call to 

discuss the proposed FIP to be 

developed for the FBIR. We formally 

invited the Tribes to consult about this 

FIP in a letter dated April 10, 2012 to 

Chairman Tex Hall, of the Three 

Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nation Council. 

We again met with members of the 

Three Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nation Council on 

June 13, 2012 in New Town to consult 

and receive input from the Tribes as we 

developed this FIP. In attendance from 

the Council were the vice Chairman and 

two council members. The Tribes’ legal 

counsel was also in attendance. The 

purpose of the consultation was 

twofold: (1) Update the Tribes on the 

EPA’s efforts to develop this FIP so that 

the air quality on the FBIR is protected 

and oil and natural gas development 

continues; and (2) discuss the Tribes’ 

preferences regarding involvement in 

the FIP process. We provided 

information on our plan to prepare a FIP 

to ensure air quality protection while 

preventing delays in oil and natural gas 

production. We solicited the Tribes’ 

input on the FIP development. The 

Council members present at the 

consultation meeting indicated that they 

strongly desired this FIP to be consistent 

with North Dakota’s requirements for oil 

and natural gas production facilities in 

order to keep a level playing field for 

development and continue 

uninterrupted development of a key 

economic resource for the Tribes. The 

Council members expressed interest in 

the future delegation of this FIP so that 

the Tribes can implement the rule in 

place of us. The Council members also 

expressed interest in providing the 

Tribes’ assistance in setting up a public 

hearing for the rule. 

As noted above, the Three Affiliated 

Tribes of the Mandan, Hidatsa and 

Arikara Nation have indicated 

preliminary interest in seeking 

administrative delegation of the Federal 

Tribal NSR rule to assist us with 

administration of that rule. We will 

continue to work with the Three 

Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nation if 

administrative delegation is something 

the Tribes decide to pursue. 

Information containing the 

consultation process is contained in the 

docket for this rule. 

For purposes of the final rule, we 

specifically solicited additional 

comments on the proposed action from 

tribal officials. We did not receive any 

comments on the proposed rule from 

tribal officials during the public 

comment period. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because the Agency does not 

believe the environmental or safety risks 

addressed by this action present a 

disproportionate risk to children. In 

addition, this rule requires control and 

reduction of emissions of VOCs, which 

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17858 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

34The TSD includes a more detailed explanation 

of the EJ analysis for this FIP. It can be found in 

the docket for this rule, Docket ID: EPA–R08–OAR– 

2012–0479, which can be accessed at: http:// 

www.regulations.gov. 

will have a beneficial effect on 

children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355, May 22, 

2001), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs us to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs us to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This rulemaking does not involve 

technical standards. Therefore, we did 

not consider the use of any voluntary 

consensus standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We did a demographic analysis of the 

areas closest to sources likely to be 

covered by this rule, and found 

disproportionately high concentrations 

of minority and low income 

populations. As detailed in our response 

to comments, we took substantial steps 

to ensure that such populations were 

given the opportunity for meaningful 

participation in the development of the 

rule. In addition, we conducted an EJ 

analysis that determined that this rule 

will not have disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority, lowincome, and indigenous populations, 

because it ensures compliance with the 

NAAQS, which provides environmental 

and public health protection for all 

affected populations, including 

minority, low-income, and indigenous 

populations.34

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing this rule and 

other required information to the U.S. 

Senate, the U.S. House of 

Representatives and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

‘‘major rule’’ as defined by 5 U.S.C. 

804(2). This rule will be effective 30 

days from the date of publication, i.e., 

on April 22, 2013. 

L. Judicial Review 

Under section 307(b)(1) of the Act, 

petitions for judicial review of this 

action must be filed in the United States 

Court of Appeals for the appropriate 

circuit by May 21, 2013. Any such 

judicial review is limited to only those 

objections that are raised with 

reasonable specificity in timely 

comments. Filing a petition for 

reconsideration by the Administrator of 

this final rule does not affect the finality 

of this rule for the purposes of judicial 

review nor does it extend the time 

within which a petition for judicial 

review may be filed and shall not 

postpone the effectiveness of such rule 

or action. Under section 307(b)(2) of the 

Act, the requirements of this final action 

may not be challenged later in civil or 

criminal proceedings brought by us to 

enforce these requirements. 

List of Subjects in 40 CFR Part 49 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Indians, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

Dated: March 1, 2013. 

Bob Perciasepe, 

Acting Administrator. 

40 CFR part 49 is amended as follows: 

PART 49—[AMENDED] 

■ 1. The authority citation for part 49 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

PART 49—INDIAN COUNTRY: AIR 

QUALITY PLANNING AND 

MANAGEMENT 

Subpart K—Implementation Plans for 

Tribes—Region VIII 

■ 2. Add §§ 49.4161 through 49.4168 

and an undesignated center heading to 

appear immediately before the newly 

added § 49.4161 to read as follows: 

* * * * * 

Federal Implementation Plan for Oil 

and Natural Gas Well Production 

Facilities; Fort Berthold Indian 

Reservation (Mandan, Hidatsa and 

Arikara Nation), North Dakota 

Sec. 

Subpart 

49.4161 Introduction. 

49.4162 Delegation of authority of 

administration to the tribes. 

49.4163 General provisions. 

49.4164 Construction and operational 

control measures. 

49.4165 Control equipment requirements. 

49.4166 Monitoring requirements. 

49.4167 Recordkeeping requirements. 

49.4168 Notification and reporting 

requirements. 

* * * * * 

Federal Implementation Plan for Oil 

and Natural Gas Well Production 

Facilities; Fort Berthold Indian 

Reservation (Mandan, Hidatsa and 

Arikara Nation), North Dakota 

§ 49.4161 Introduction. 

(a) What is the purpose of §§ 49.4161 

through 49.4168? Sections 49.4161 

through 49.4168 establish legally and 

practicably enforceable requirements to 

control and reduce VOC emissions from 

well completion operations, well 

recompletion operations, production 

operations, and storage operations at 

existing, new and modified oil and 

natural gas production facilities. 

(b) Am I subject to §§ 49.4161 through 

49.4168? Sections 49.4161 through 

49.4168 apply to each owner or operator 

constructing, modifying or operating an 

oil and natural gas production facility 

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producing from the Bakken Pool with 

one or more oil and natural gas wells, 

for any one of which completion or 

recompletion operations are/were 

performed on or after August 12, 2007, 

that is located on the Fort Berthold 

Indian Reservation, which is defined by 

the Act of March 3, 1891 (26 Statute 

1032) and which includes all lands 

added to the Reservation by Executive 

Order of June 17, 1892 (the ‘‘Fort 

Berthold Indian Reservation’’). For the 

purposes of this subpart, the date that 

the first well completion operation at a 

new oil and natural gas production 

facility was initiated is the date that 

initial construction has commenced. For 

the purposes of this subpart, the date 

that a new well completion operation or 

the date that an existing well 

recompletion operation at an existing oil 

and natural gas production facility is 

initiated is the date that a modification 

has commenced. 

(c) When must I comply with 

§§ 49.4161 through 49.4168? 

Compliance with §§ 49.4161 through 

49.4168 is required no later than June 

20, 2013 or upon initiation of well 

completion operations or well 

recompletion operations, whichever is 

later. 

§ 49.4162 Delegation of authority of 

administration to the tribes. 

(a) What is the purpose of this 

section? The purpose of this section is 

to establish the process by which the 

Regional Administrator may delegate to 

the Mandan, Hidatsa and Arikara Nation 

the authority to assist the EPA with 

administration of this Federal 

Implementation Plan (FIP). This section 

provides for administrative delegation 

and does not affect the eligibility criteria 

under 40 CFR 49.6 for treatment in the 

same manner as a state. 

(b) How does the Tribe request 

delegation? In order to be delegated 

authority to assist us with 

administration of this FIP, the 

authorized representative of the 

Mandan, Hidatsa and Arikara Nation 

must submit a request to the Regional 

Administrator that: 

(1) Identifies the specific provisions 

for which delegation is requested; 

(2) Includes a statement by the 

Mandan, Hidatsa and Arikara Nation’s 

legal counsel (or equivalent official) that 

includes the following information: 

(i) A statement that the Mandan, 

Hidatsa and Arikara Nation are an 

Indian Tribe recognized by the Secretary 

of the Interior; 

(ii) A descriptive statement 

demonstrating that the Mandan, Hidatsa 

and Arikara Nation are currently 

carrying out substantial governmental 

duties and powers over a defined area 

and that meets the requirements of 

§ 49.7(a)(2); and 

(iii) A description of the laws of the 

Mandan, Hidatsa and Arikara Nation 

that provide adequate authority to carry 

out the aspects of the rule for which 

delegation is requested. 

(3) Demonstrates that the Mandan, 

Hidatsa and Arikara Nation have, or will 

have, adequate resources to carry out 

the aspects of the rule for which 

delegation is requested. 

(c) How is the delegation of 

administration accomplished? (1) A 

Delegation of Authority Agreement will 

set forth the terms and conditions of the 

delegation, will specify the rule and 

provisions that the Mandan, Hidatsa 

and Arikara Nation shall be authorized 

to implement on behalf of the EPA, and 

shall be entered into by the Regional 

Administrator and the Mandan, Hidatsa 

and Arikara Nation. The Agreement will 

become effective upon the date that both 

the Regional Administrator and the 

authorized representative of the 

Mandan, Hidatsa and Arikara Nation 

have signed the Agreement. Once the 

delegation becomes effective, the 

Mandan, Hidatsa and Arikara Nation 

will be responsible, to the extent 

specified in the Agreement, for assisting 

us with administration of this FIP and 

shall act as the Regional Administrator 

as that term is used in these regulations. 

Any Delegation of Authority Agreement 

will clarify the circumstances in which 

the term ‘‘Regional Administrator’’’ 

found throughout this FIP is to remain 

the EPA Regional Administrator and 

when it is intended to refer to the 

‘‘Mandan, Hidatsa and Arikara Nation,’’ 

instead. 

(2) A Delegation of Authority 

Agreement may be modified, amended, 

or revoked, in part or in whole, by the 

Regional Administrator after 

consultation with the Mandan, Hidatsa 

and Arikara Nation. 

(d) How will any delegation of 

authority agreement be publicized? The 

Regional Administrator shall publish a 

notice in the Federal Register informing 

the public of any delegation of authority 

agreement with the Mandan, Hidatsa 

and Arikara Nation to assist us with 

administration of all or a portion of this 

FIP and will identify such delegation in 

the FIP. The Regional Administrator 

shall also publish an announcement of 

the delegation of authority agreement in 

local newspapers. 

§ 49.4163 General provisions. 

(a) Definitions. As used in §§ 49.4161 

through 49.4168, all terms not defined 

herein shall have the meaning given 

them in the Act, in subpart A and 

subpart OOOO of 40 CFR part 60, in the 

Prevention of Significant Deterioration 

regulations at 40 CFR 52.21, or in the 

Federal Minor New Source Review 

Program in Indian Country at 40 CFR 

49.151. The following terms shall have 

the specific meanings given them. 

(1) Bakken Pool means Oil produced 

from the Bakken, Three Forks, and 

Sanish Formations. 

(2) Breathing losses means natural gas 

emissions from fixed roof tanks 

resulting from evaporative losses during 

storage. 

(3) Casinghead natural gas means the 

associated natural gas that naturally 

dissolves out of reservoir fluids during 

well completion operations and 

recompletion operations due to the 

pressure relief that occurs as the 

reservoir fluids travel up the well 

casinghead. 

(4) Closed vent system means a system 

that is not open to the atmosphere and 

that is composed of hard-piping, 

ductwork, connections, and, if 

necessary, flow-inducing devices that 

transport natural gas from a piece or 

pieces of equipment to a control device 

or back to a process. 

(5) Enclosed combustor means a 

thermal oxidation system with an 

enclosed combustion chamber that 

maintains a limited constant 

temperature by controlling fuel and 

combustion air. 

(6) Existing facility means an oil and 

natural gas production facility that 

begins actual construction prior to the 

effective date of the ‘‘Federal 

Implementation Plan for Oil and Natural 

Gas Well Production Facilities; Fort 

Berthold Indian Reservation (Mandan, 

Hidatsa and Arikara Nation), North 

Dakota’’. 

(7) Flashing losses means natural gas 

emissions resulting from the presence of 

dissolved natural gas in the produced 

oil and the produced water, both of 

which are under high pressure, that 

occurs as the produced oil and 

produced water is transferred to storage 

tanks or other vessels that are at 

atmospheric pressure. 

(8) Modified facility means a facility 

which has undergone the addition, 

completion, or recompletion of one or 

more oil and natural gas wells, and/or 

the addition of any associated 

equipment necessary for production and 

storage operations at an existing facility. 

(9) New facility means an oil and 

natural gas production facility that 

begins actual construction after the 

effective date of the ‘‘Federal 

Implementation Plan for Oil and Natural 

Gas Well Production Facilities; Fort 

Berthold Indian Reservation (Mandan, 

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17860 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

Hidatsa and Arikara Nation), North 

Dakota’’. 

(10) Oil means hydrocarbon liquids. 

(11) Oil and natural gas production 

facility means all of the air pollution 

emitting units and activities located on 

or integrally connected to one or more 

oil and natural gas wells that are 

necessary for production operations and 

storage operations. 

(12) Oil and natural gas well means a 

single well that extracts subsurface 

reservoir fluids containing a mixture of 

oil, natural gas, and water. 

(13) Owner or operator means any 

person who owns, leases, operates, 

controls, or supervises an oil and 

natural gas production facility. 

(14) Permit to construct or 

construction permit means a permit 

issued by the Regional Administrator 

pursuant to 40 CFR 49.151, 52.10 or 

52.21, or a permit issued by a tribe 

pursuant to a program approved by the 

Administrator under 40 CFR part 51, 

subpart I, authorizing the construction 

or modification of a stationary source. 

(15) Permit to operate or operating 

permit means a permit issued by the 

Regional Administrator pursuant to 40 

CFR part 71, or by a tribe pursuant to 

a program approved by the 

Administrator under 40 CFR part 51 or 

40 CFR part 70, authorizing the 

operation of a stationary source. 

(16) Pit flare means an ignition 

device, installed horizontally or 

vertically and used in oil and natural 

gas production operations to combust 

produced natural gas and natural gas 

emissions. 

(17) Produced natural gas means 

natural gas that is separated from 

extracted reservoir fluids during 

production operations. 

(18) Produced oil means oil that is 

separated from extracted reservoir fluids 

during production operations. 

(19) Produced oil storage tank means 

a unit that is constructed primarily of 

non-earthen materials (such as steel, 

fiberglass, or plastic) which provides 

structural support and is designed to 

contain an accumulation of produced 

oil. 

(20) Produced water means water that 

is separated from extracted reservoir 

fluids during production operations. 

(21) Produced water storage tank 

means a unit that is constructed 

primarily of non-earthen materials (such 

as steel, fiberglass, or plastic) which 

provides structural support and is 

designed to contain an accumulation of 

produced water. 

(22) Production operations means the 

extraction and separation of reservoir 

fluids from an oil and natural gas well, 

using separators and heater-treater 

systems. A separator is a pressurized 

vessel designed to separate reservoir 

fluids into their constituent components 

of oil, natural gas and water. A heatertreater is a unit that heats the reservoir 

fluid to break oil/water emulsions and 

to reduce the oil viscosity. The water is 

then typically removed by using gravity 

to allow the water to separate from the 

oil. 

(23) Regional Administrator means 

the Regional Administrator of EPA 

Region 8 or an authorized representative 

of the Regional Administrator. 

(24) Standing losses means natural gas 

emissions from fixed roof tanks as a 

result of evaporative losses during 

storage. 

(25) Storage operations means the 

transfer of produced oil and produced 

water to storage tanks, the filling of the 

storage tanks, the storage of the 

produced oil and produced water in the 

storage tanks, and the draining of the 

produced oil and produced water from 

the storage tanks. 

(26) Supervisory Control and Data 

Acquisition (SCADA) system generally 

refers to industrial control computer 

systems that monitor and control 

industrial infrastructure or facilitybased processes. 

(27) Utility flare means thermal 

oxidation system using an open 

(without enclosure) flame. An enclosed 

combustor as defined in §§ 49.4161 

through 49.4168 is not considered a 

flare. 

(28) Visible Smoke emissions means a 

pollutant generated by thermal 

oxidation in a flare or enclosed 

combustor and occurring immediately 

downstream of the flame. Visible smoke 

occurring within, but not downstream 

of, the flame, is not considered to 

constitute visible smoke emissions. 

(29) Well completion means the 

process that allows for the flowback of 

oil and natural gas from newly drilled 

wells to expel drilling and reservoir 

fluids and tests the reservoir flow 

characteristics, which may vent 

produced hydrocarbons to the 

atmosphere via an open pit or tank. 

(30) Well completion operation means 

any oil and natural gas well completion 

using hydraulic fracturing occurring at 

an oil and natural gas production 

facility. 

(31) Well recompletion operation 

means any oil and natural gas well 

completion using hydraulic refracturing 

occurring at an oil and natural gas 

production facility. 

(32) Working losses means natural gas 

emissions from fixed roof tanks 

resulting from evaporative losses during 

filling and emptying operations. 

(b) Requirement for testing. The 

Regional Administrator may require that 

an owner or operator of an oil and 

natural gas production facility 

demonstrate compliance with the 

requirements of the ‘‘Federal 

Implementation Plan for Oil and Natural 

Gas Well Production Facilities; Fort 

Berthold Indian Reservation (Mandan, 

Hidatsa and Arikara Nation), North 

Dakota’’ by performing a source test and 

submitting the test results to the 

Regional Administrator. Nothing in the 

‘‘Federal Implementation Plan for Oil 

and Natural Gas Well Production 

Facilities; Fort Berthold Indian 

Reservation (Mandan, Hidatsa and 

Arikara Nation), North Dakota’’ limits 

the authority of the Regional 

Administrator to require, in an 

information request pursuant to section 

114 of the Act, an owner or operator of 

an oil and natural gas production 

facility subject to the ‘‘Federal 

Implementation Plan for Oil and Natural 

Gas Production Facilities, Fort Berthold 

Indian Reservation (Mandan, Hidatsa 

and Arikara Nation)’’ to demonstrate 

compliance by performing testing, even 

where the facility does not have a 

permit to construct or a permit to 

operate. 

(c) Requirement for monitoring, 

recordkeeping, and reporting. Nothing 

in ‘‘Federal Implementation Plan for Oil 

and Natural Gas Production Facilities, 

Fort Berthold Indian Reservation 

(Mandan, Hidatsa and Arikara Nation)’’ 

precludes the Regional Administrator 

from requiring monitoring, 

recordkeeping and reporting, including 

monitoring, recordkeeping and 

reporting in addition to that already 

required by an applicable requirement 

in these rules, in a permit to construct 

or permit to operate in order to ensure 

compliance. 

(d) Credible evidence. For the 

purposes of submitting reports or 

establishing whether or not an owner or 

operator of an oil and natural gas 

production facility has violated or is in 

violation of any requirement, nothing in 

the ‘‘Federal Implementation Plan for 

Oil and Natural Gas Well Production 

Facilities; Fort Berthold Indian 

Reservation (Mandan, Hidatsa and 

Arikara Nation), North Dakota’’ shall 

preclude the use, including the 

exclusive use, of any credible evidence 

or information, relevant to whether a 

facility would have been in compliance 

with applicable requirements if the 

appropriate performance or compliance 

test had been performed. 

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§ 49.4164 Construction and operational 

control measures. 

(a) Each owner or operator must 

operate and maintain all liquid and gas 

collection, storage, processing and 

handling operations, regardless of size, 

so as to minimize leakage of natural gas 

emissions to the atmosphere. 

(b) During all oil and natural gas well 

completion operations or recompletion 

operations at an oil and natural gas 

production facility and prior to the first 

date of production of each oil and 

natural gas well, each owner or operator 

must, at a minimum, route all 

casinghead natural gas to a utility flare 

or a pit flare capable of reducing the 

mass content of VOC in the natural gas 

emissions vented to it by at least 90.0 

percent or greater and operated as 

specified in §§ 49.4165 and 49.4166. 

(c) Beginning with the first date of 

production from any one oil and natural 

gas well at an oil and natural gas 

production facility, each owner or 

operator must, at a minimum, route all 

natural gas emissions from production 

operations and storage operations to a 

control device capable of reducing the 

mass content of VOC in the natural gas 

emissions vented to it by at least 90.0 

percent or greater and operated as 

specified in §§ 49.4165 and 49.4166. 

(d) Within ninety (90) days of the first 

date of production from any oil and 

natural gas well at an oil and natural gas 

production facility, each owner or 

operator must: 

(1) Route the produced natural gas 

from the production operations through 

a closed-vent system to: 

(i) An operating system designed to 

recover and inject all the produced 

natural gas into a natural gas gathering 

pipeline system for sale or other 

beneficial purpose; or 

(ii) A utility flare or equivalent 

combustion device capable of reducing 

the mass content of VOC in the 

produced natural gas vented to the 

device by at least 98.0 percent or greater 

and operated as specified in §§ 49.4165 

and 49.4166. 

(2) Route all standing, working, 

breathing, and flashing losses from the 

produced oil storage tanks and any 

produced water storage tank 

interconnected with the produced oil 

storage tanks through a closed-vent 

system to: 

(i) An operating system designed to 

recover and inject the natural gas 

emissions into a natural gas gathering 

pipeline system for sale or other 

beneficial purpose; or 

(ii) An enclosed combustor or utility 

flare capable of reducing the mass 

content of VOC in the natural gas 

emissions vented to the device by at 

least 98.0 percent or greater and 

operated as specified in §§ 49.4165(c) 

and 49.4166. 

(iii) If the uncontrolled potential to 

emit VOCs from the aggregate of all 

produced oil storage tanks and 

produced water storage tanks 

interconnected with produced oil 

storage tanks at an oil and natural gas 

production facility is less than, and 

reasonably expected to remain below, 

20 tons in any consecutive 12-month 

period, then, upon prior written 

approval by the EPA the owner or 

operator may use a pit flare, an enclosed 

combustor or a utility flare that is 

capable of reducing the mass content of 

VOC in the natural gas emissions from 

the storage tanks vented to the device by 

only 90.0 percent. 

(e) In the event that pipeline injection 

of all or part of the natural gas collected 

in an operating system designed to 

recover and inject natural gas becomes 

temporarily infeasible and there is no 

operational enclosed combustor or 

utility flare at the facility, the owner or 

operator must route the natural gas that 

cannot be injected through a closed-vent 

system to a pit flare operated as 

specified in §§ 49.4165 and 49.4166. 

(f) Produced oil storage tanks and any 

produced water storage tanks 

interconnected with produced oil 

storage tanks subject to the requirements 

specified in 40 CFR part 60, subpart 

OOOO are considered to meet the 

requirements of § 49.4164(d)(2). No 

further requirements apply for such 

storage tanks under § 49.4164(d)(2). 

§ 49.4165 Control equipment 

requirements. 

(a) Covers. Each owner or operator 

must equip all openings on each 

produced oil storage tank and produced 

water storage tank interconnected with 

produced oil storage tanks with a cover 

to ensure that all natural gas emissions 

are efficiently being routed through a 

closed-vent system to a vapor recovery 

system, an enclosed combustor, a utility 

flare, or a pit flare. 

(1) Each cover and all openings on the 

cover (e.g., access hatches, sampling 

ports, pressure relief valves (PRV), and 

gauge wells) shall form a continuous 

impermeable barrier over the entire 

surface area of the produced oil and 

produced water in the storage tank. 

(2) Each cover opening shall be 

secured in a closed, sealed position 

(e.g., covered by a gasketed lid or cap) 

whenever material is in the unit on 

which the cover is installed except 

during those times when it is necessary 

to use an opening as follows: 

(i) To add material to, or remove 

material from the unit (this includes 

openings necessary to equalize or 

balance the internal pressure of the unit 

following changes in the level of the 

material in the unit); 

(ii) To inspect or sample the material 

in the unit; or 

(iii) To inspect, maintain, repair, or 

replace equipment located inside the 

unit. 

(3) Each thief hatch cover shall be 

weighted and properly seated. 

(4) Each PRV shall be set to release at 

a pressure that will ensure that natural 

gas emissions are routed through the 

closed-vent system to the vapor 

recovery system, the enclosed 

combustor, or the utility flare under 

normal operating conditions. 

(b) Closed-vent systems. Each owner 

or operator must meet the following 

requirements for closed-vent systems: 

(1) Each closed-vent system must 

route all produced natural gas and 

natural gas emissions from production 

and storage operations to the natural gas 

sales pipeline or the control devices 

required by paragraph (a) of this section. 

(2) All vent lines, connections, 

fittings, valves, relief valves, or any 

other appurtenance employed to contain 

and collect natural gas, vapor, and 

fumes and transport them to a natural 

gas sales pipeline and any VOC control 

equipment must be maintained and 

operated properly at all times. 

(3) Each closed-vent system must be 

designed to operate with no detectable 

natural gas emissions. 

(4) If any closed-vent system contains 

one or more bypass devices, except as 

provided for in paragraph (b)(4)(iii) of 

this section, that could be used to divert 

all or a portion of the natural gas 

emissions, from entering a natural gas 

sales pipeline and/or any control 

devices, the owner or operator must 

meet the one of following requirements 

for each bypass device: 

(i) At the inlet to the bypass device 

that could divert the natural gas 

emissions away from a natural gas sales 

pipeline or a control device and into the 

atmosphere, properly install, calibrate, 

maintain, and operate a natural gas flow 

indicator that is capable of taking 

continuous readings and sounding an 

alarm when the bypass device is open 

such that natural gas emissions are 

being, or could be, diverted away from 

a natural gas sales pipeline or a control 

device and into the atmosphere; 

(ii) Secure the bypass device valve 

installed at the inlet to the bypass 

device in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration; 

(iii) Low leg drains, high point bleeds, 

analyzer vents, open-ended valves or 

lines, and safety devices are not subject 

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17862 Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 

to the requirements applicable to bypass 

devices. 

(c) Enclosed combustors and utility 

flares. Each owner or operator must 

meet the following requirements for 

enclosed combustors and utility flares: 

(1) For each enclosed combustor or 

utility flare, the owner or operator must 

follow the manufacturer’s written 

operating instructions, procedures and 

maintenance schedule to ensure good 

air pollution control practices for 

minimizing emissions; 

(2) For each enclosed combustor or 

utility flare, the owner or operator must 

ensure there is sufficient capacity to 

reduce the mass content of VOC in the 

produced natural gas and natural gas 

emissions routed to it by at least 98.0 

percent for the minimum and maximum 

natural gas volumetric flow rate and 

BTU content routed to the device; 

(3) Each enclosed combustor or utility 

flare must be operated to reduce the 

mass content of VOC in the produced 

natural gas and natural gas emissions 

routed to it by at least 98.0 percent; 

(4) The owner or operator must ensure 

that each utility flare is designed and 

operated in accordance with the 

requirements of 40 CFR 60.18(b) for 

such flares, except for § 60.18(c)(2) and 

(f)(2) for those utility flares operated 

with an electronically controlled 

automatic igniter. 

(5) The owner or operator must ensure 

that each enclosed combustor is: 

(i) A model demonstrated by a 

manufacturer to the meet the VOC 

destruction efficiency requirements of 

§§ 49.4161 through 49.4168 using the 

procedure specified in 40 CFR part 60, 

subpart OOOO at § 60.5413(d) by the 

due date of the first annual report as 

specified in § 49.4168(b); or 

(ii) Demonstrated to meet the VOC 

destruction efficiency requirements of 

§§ 49.4161 through 49.4168 using EPA 

approved performance test methods 

specified in 40 CFR part 60, subpart 

OOOO at § 60.5413(b) by the due date 

of the first annual report as specified in 

§ 49.4168(b). 

(6) The owner or operator must ensure 

that each enclosed combustor and 

utility flare is: 

(i) Operated properly at all times that 

produced natural gas and/or natural gas 

emissions are routed to it; 

(ii) Operated with a liquid knock-out 

system to collect any condensable 

vapors (to prevent liquids from going 

through the control device); 

(iii) Equipped with a flash-back flame 

arrestor; 

(iv) Equipped with one of the 

following: 

(A) A continuous burning pilot flame. 

(B) An electronically controlled 

automatic igniter; 

(v) Equipped with a monitoring 

system for continuous recording of the 

parameters that indicate proper 

operation of each enclosed combustor, 

utility flare, continuous burning pilot 

flame, and electronically controlled 

automatic igniter, such as a chart 

recorder, data logger or similar devices; 

(vi) Maintained in a leak-free 

condition; and 

(vii) Operated with no visible smoke 

emissions. 

(d) Pit Flares. Each owner or operator 

must meet the following requirements 

for pit flares: 

(1) The owner or operator must 

develop written operating instructions, 

operating procedures and maintenance 

schedules to ensure good air pollution 

control practices for minimizing 

emissions from the pit flare based on the 

site-specific design. 

(2) The owner or operator must only 

use a pit flare for the following 

operations: 

(i) To control produced natural gas 

and natural gas emissions during well 

completion operations or recompletion 

operations; 

(ii) To control produced natural gas 

and natural gas emissions in the event 

that natural gas recovered for pipeline 

injection must be diverted to a backup 

control device because injection is 

temporarily infeasible and there is no 

operational enclosed combustor or 

utility flare at the oil and natural gas 

production facility. Use of the pit flare 

for this situation is limited to a 

maximum of 500 hours in any twelve 

(12) consecutive months; or 

(iii) Control of standing, working, 

breathing, and flashing losses from the 

produced oil storage tanks and any 

produced water storage tank 

interconnected with the produced oil 

storage tanks if the uncontrolled 

potential VOC emissions from the 

aggregate of all produced oil storage 

tanks and produced water storage tanks 

interconnected with produced oil 

storage tanks is less than, and 

reasonably expected to remain below, 

20 tons in any consecutive 12-month 

period. 

(3) The owner or operator must only 

use the pit flare under the following 

conditions and limitations: 

(i) The pit flare is operated to reduce 

the mass content of VOC in the 

produced natural gas and natural gas 

emissions routed to it by at least 90.0 

percent; 

(ii) The pit flare is operated in 

accordance with the site-specific written 

operating instructions, operating 

procedures, and maintenance schedules 

to ensure good air pollution control 

practices for minimizing emissions; 

(iii) The pit flare is operated with no 

visible smoke emissions; 

(iv) The pit flare is equipped with an 

electronically controlled automatic 

igniter; 

(v) The pit flare is visually inspected 

for the presence of a flame anytime 

produced natural gas or natural gas 

emissions are being routed to it. Should 

the flame fail, the flame must be relit as 

soon as safely possible and the 

electronically controlled automatic 

igniter must be repaired or replaced 

before the pit flare is utilized again; and 

(vi) The owner or operator does not 

deposit or cause to be deposited into a 

flare pit any oil field fluids or oil and 

natural gas wastes other than those 

designed to go to the pit flare. 

(e) Other Control Devices. Upon prior 

written approval by the EPA, the owner 

or operator may use control devices 

other than those listed above that are 

determined by EPA to be capable of 

reducing the mass content of VOC in the 

natural gas routed to it by at least 98.0 

percent, provided that: 

(1) In operating such control devices, 

the owner or operator must follow the 

manufacturer’s written operating 

instructions, procedures and 

maintenance schedule to ensure good 

air pollution control practices for 

minimizing emissions; and 

(2) The owner or operator must ensure 

there is sufficient capacity to reduce the 

mass content of VOC in the produced 

natural gas and natural gas emissions 

routed to such other control devices by 

at least 98.0 percent for the minimum 

and maximum natural gas volumetric 

flow rate and BTU content routed to 

each device. 

(3) The owner or operator must 

operate such a control device to reduce 

the mass content of VOC in the 

produced natural gas and natural gas 

emissions routed to it by at least 98.0 

percent. 

§ 49.4166 Monitoring requirements. 

(a) Each owner and operator must 

measure the barrels of oil produced at 

the oil and natural gas production 

facility each time the oil is unloaded 

from the produced oil storage tanks 

using the methodologies of tank gauging 

or positive displacement metering 

system, as appropriate, as established by 

the U.S. Department of the Interior’s 

Bureau of Land Management at 43 CFR 

part 3160, in the ‘‘Onshore Oil and Gas 

Operations; Federal and Indian Oil & 

Gas Leases; Onshore Oil and Gas Order 

No. 4; Measurement of Oil’’. 

(b) Each owner or operator must 

monitor the hours that each pit flare is 

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Federal Register / Vol. 78, No. 56 / Friday, March 22, 2013 / Rules and Regulations 17863 

operated to control produced natural gas 

and natural gas emissions in the event 

that natural gas recovered for pipeline 

injection must be diverted to a backup 

control device because injection is 

temporarily infeasible and there is no 

enclosed combustor or utility flare at the 

oil and natural gas production facility. 

(c) Each owner or operator must 

monitor the volume of produced natural 

gas sent to each enclosed combustor, 

utility flare, and pit flare at all times. 

Methods to measure the volume 

include, but are not limited to, direct 

measurement and gas-to-oil ratio (GOR) 

laboratory analyses. 

(d) Each owner or operator must 

monitor the volume of standing, 

working, breathing, and flashing losses 

from the produced oil and produced 

water storage tanks sent to each vapor 

recovery system, enclosed combustor, 

utility flare, and pit flare at all times. 

Methods to measure the volume 

include, but are not limited to, direct 

measurement or GOR laboratory 

analyses. 

(e) Each owner or operator must 

perform quarterly visual inspections of 

tank thief hatches, covers, seals, PRVs, 

and closed vent systems to ensure 

proper condition and functioning and 

repair any damaged equipment. The 

quarterly inspections must be performed 

while the produced oil and produced 

water storage tanks are being filled. 

(f) Each owner or operator must 

perform quarterly visual inspections of 

the peak pressure and vacuum values in 

each closed vent system and control 

system for the produced oil and 

produced water storage tanks to ensure 

that the pressure and vacuum relief setpoints are not being exceeded in a way 

that has resulted, or may result, in 

venting and possible damage to 

equipment. The quarterly inspections 

must be performed while the produced 

oil and produced water storage tanks are 

being filled. 

(g) Each owner or operator must 

monitor the operation of each enclosed 

combustor, utility flare, and pit flare to 

confirm proper operation as follows: 

(1) Continuously monitor all variable 

operational parameters specified in the 

written operating instructions and 

procedures, including continuous 

burning pilot flame, electronically 

controlled automatic igniters, and 

monitoring system failures, using a 

malfunction alarm and remote 

notification system, where such systems 

are available, or continuously monitor 

under an equivalent alternative protocol 

upon prior written approval by the EPA; 

(2) Perform a physical inspection of 

all equipment associated with each 

enclosed combustor, utility flare, and 

pit flare each time an operator is on site, 

at a minimum quarterly, to ensure 

system integrity; 

(3) Monitor for visible smoke during 

operation of any enclosed combustor, 

utility flare or pit flare each time an 

operator is on site, at a minimum 

quarterly. Upon observation of visible 

smoke, use EPA Reference Method 22 of 

40 CFR part 60, Appendix A, to 

determine whether visible smoke 

emissions are present. The observation 

period shall be 2 hours. Visible smoke 

emissions are present if smoke is 

observed for more than 5 minutes in any 

2 consecutive hours; and 

(4) Respond to any observation of any 

continuous burning pilot flame failure, 

electronically controlled automatic 

igniter failure, or improper monitoring 

equipment operation and ensure the 

equipment is returned to proper 

operation as soon as practicable and 

safely possible after an observation or an 

alarm sounds. 

(h) Where sufficient to meet the 

monitoring and recordkeeping 

requirements in §§ 49.4166 and 49.4167, 

the owner or operator may use a 

Supervisory Control and Data 

Acquisition (SCADA) system to monitor 

and record the required data in 

§§ 49.4161 through 49.4168. 

(i) Other Monitoring Options. The 

owner or operator may use equivalent 

methods of monitoring other than those 

listed above upon prior written approval 

by the EPA. 

§ 49.4167 Recordkeeping requirements. 

(a) Each owner or operator must 

maintain the following records: 

(1) The measured barrels of oil 

produced at the oil and natural gas 

production facility each time the oil is 

unloaded from the produced oil storage 

tanks; 

(2) The volume of produced natural 

gas sent to each enclosed combustor, 

utility flare, and pit flare at all times; 

(3) The volume of natural gas 

emissions from the produced oil storage 

tanks and produced water storage tanks 

sent to each enclosed combustor, utility 

flare, and pit flare at all times; 

(4) A summary of each oil and natural 

gas well completion operation and 

recompletion operation at an oil and 

natural gas production facility. Each 

summary shall include: 

(i) The latitude and longitude location 

of the oil and natural gas well in 

decimal format; 

(ii) The date, time, and duration in 

hours of flowback from the oil and 

natural gas well; 

(iii) The date, time, and duration in 

hours of any venting of casinghead 

natural gas from the oil and natural gas 

well; and 

(iv) Specific reasons for each instance 

of venting in lieu of capture or 

combustion. 

(5) For each enclosed combustor, 

utility flare, and pit flare at an oil and 

natural gas production facility: 

(i) Written, site-specific designs, 

operating instructions, operating 

procedures and maintenance schedules; 

(ii) Records of all required monitoring 

of operations; 

(iii) Records of any deviations from 

the operating parameters specified by 

the written site-specific designs, 

operating instructions, and operating 

procedures. The records must include 

the enclosed combustor, utility flare, or 

pit flare’s total operating time during 

which a deviation occurred, the date, 

time and length of time that deviations 

occurred, and the corrective actions 

taken and any preventative measures 

adopted to operate the device within 

that operating parameter; 

(iv) Records of any instances in which 

the pilot flame is not present, 

electronically controlled automatic 

igniter is not functioning, or the 

monitoring equipment is not 

functioning in the enclosed combustor, 

the utility flare, or the pit flare, the date 

and times of the occurrence, the 

corrective actions taken, and any 

preventative measures adopted to 

prevent recurrence of the occurrence; 

(v) Records of any instances in which 

a recording device installed to record 

data from the enclosed combustor, 

utility flare, or pit flare is not 

operational; and 

(vi) Records of any time periods in 

which visible smoke emissions are 

observed emanating from the enclosed 

combustor, utility flare, or pit flare. 

(6) For each pit flare at an oil and 

natural gas production facility, a 

demonstration of compliance with the 

use restrictions set forth in 

§ 49.4165(d)(2)(ii) is made by keeping 

records in a log book, or similar 

recording system, during each period of 

time that the pit flare is operating. The 

records must contain the following 

information: 

(i) Date and time the pit flare was 

started up and subsequently shut down; 

(ii) Total hours operated when 

pipeline injection was temporarily 

infeasible for the current calendar 

month plus the previous consecutive 

eleven (11) calendar months; and 

(iii) Brief descriptions of the 

justification for each period of 

operation. 

(7) Records of any instances in which 

any closed-vent system or control 

device was bypassed or down, the 

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reason for each incident, its duration, 

the volume of natural gas emissions 

released, and the corrective actions 

taken and any preventative measures 

adopted to avoid such bypasses or 

downtimes; and 

(8) Documentation of all produced oil 

storage tank and produced water storage 

tank inspections required in 

§ 49.4166(e) and (f). All inspection 

records must include, at a minimum, 

the following information: 

(i) The date of the inspection; 

(ii) The findings of the inspection; 

(iii) Any adjustments or repairs made 

as a result of the inspections, and the 

date of the adjustment or repair; and 

(iv) The inspector’s name and 

signature. 

(b) Each owner or operator must keep 

all records required by this section 

onsite at the facility or at the location 

that has day-to-day operational control 

over the facility and must make the 

records available to the EPA upon 

request. 

(c) Each owner or operator must retain 

all records required by this section for 

a period of at least five (5) years from 

the date the record was created. 

§ 49.4168 Notification and reporting 

requirements. 

(a) Each owner or operator must 

submit any documents required under 

this section to: U.S. Environmental 

Protection Agency, Region 8 Office of 

Enforcement, Compliance & 

Environmental Justice, Air Toxics and 

Technical Enforcement Program, 8ENF– 

AT, 1595 Wynkoop Street, Denver, 

Colorado 80202. Documents may be 

submitted electronically to 

r8airreportenforcement@epa.gov. 

(b) Each owner and operator must 

submit an annual report containing the 

information specified in paragraphs 

(b)(1) through (4) of this section. Each 

annual report is due August 15th every 

year and must cover all information for 

the previous calendar year. The initial 

report must cover the cumulative 

information for that year. If you own or 

operate more than one oil and natural 

gas production facility, you may submit 

one report for multiple oil and natural 

gas production facilities provided the 

report contains all of the information 

required as specified in paragraphs 

(b)(1) through (4) of this section. Annual 

reports may coincide with title V reports 

as long as all the required elements of 

the annual report are included. The EPA 

may approve a common schedule on 

which reports required by §§ 49.4161 

through 49.4168 may be submitted as 

long as the schedule does not extend the 

reporting period. 

(1) The company name and the 

address of the oil and natural gas 

production facility or facilities. 

(2) An identification of each oil and 

natural gas production facility being 

included in the annual report. 

(3) The beginning and ending dates of 

the reporting period. 

(4) For each oil and natural gas 

production facility, the information in 

paragraphs (b)(4)(i) through (iv) of this 

section. 

(i) A summary of all required records 

identifying each oil and natural gas well 

completion or recompletion operation 

for each oil and natural gas production 

facility conducted during the reporting 

period; 

(ii) An identification of the first date 

of production for each oil and natural 

gas well at each oil and natural gas 

production facility that commenced 

production during the reporting period; 

and 

(iii) A summary of cases where 

construction or operation was not 

performed in compliance with the 

requirements specified in § 49.4164, 

§ 49.4165, or § 49.4166 for each oil and 

natural gas well at each oil and natural 

gas production facility, and the 

corrective measures taken. 

(iv) A certification by a responsible 

official of truth, accuracy and 

completeness. This certification shall 

state that, based on information and 

belief formed after reasonable inquiry, 

the statements and information in the 

document are true, accurate and 

complete. 

[FR Doc. 2013–05666 Filed 3–21–13; 8:45 am] 

BILLING CODE 6560–50–P 

mstockstill on DSK4VPTVN1PROD with RULES2