```

[Federal Register Volume 78, Number 56 (Friday, March 22, 2013)]
[Rules and Regulations]
[Pages 17835-17864]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-05666]

[[Page 17835]]

Vol. 78

Friday,

No. 56

March 22, 2013

Part III

Environmental Protection Agency

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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

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

[[Page 17836]]

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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.

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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-to-oil 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

[[Page 17837]]

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.
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    \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.
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    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.
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    \2\ The 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.
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    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

[[Page 17838]]

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.
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    \3\ Commenter 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.
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    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

[[Page 17839]]

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 co-producing 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.
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    \4\ Information on the EPA's Natural Gas STAR Program is 
available online at: http://www.epa.gov/gasstar/, Accessed November 
15, 2012.
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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 quality\5\ 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.
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    \5\ Commenter references the interim final rule at 77 FR 48886.
    \6\ The 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.
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    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

[[Page 17840]]

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 Sec.  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 Sec.  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\
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    \7\ Section 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 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 Sec.  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

[[Page 17841]]

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.
---------------------------------------------------------------------------

    \8\ The commenter is referring to the interim final rule Section 
III.E. ``Effect on Permitting of Facilities.'' (77 FR 48885).
---------------------------------------------------------------------------

    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-

[[Page 17842]]

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.
---------------------------------------------------------------------------

    \9\ Summit 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.
---------------------------------------------------------------------------

    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 case-by-case basis, applying 
the relevant regulatory criteria to the facts of the oil and natural 
gas production activities being permitted.
---------------------------------------------------------------------------

    \10\ Memo 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \11\ Commenter 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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \12\ The Bakken Pool is defined as a compilation of crude oil 
formations consisting of Bakken, Sanish and Three Forks formations.
    \13\ Bakken 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.
---------------------------------------------------------------------------

    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 reservation-specific 
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

[[Page 17843]]

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 Sec.  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 
Sec.  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 (Sec.  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 co-
produced 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.
---------------------------------------------------------------------------

    \14\ The 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.
---------------------------------------------------------------------------

    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

[[Page 17844]]

argue that heater-treater combustion devices must be considered 
inherent process equipment based on those criteria.
---------------------------------------------------------------------------

    \15\ Letter 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 ID: 
EPA-R08-OAR-2012-0479, which can be accessed at: http://www.regulations.gov.
---------------------------------------------------------------------------

    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 co-produced 
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

[[Page 17845]]

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.
---------------------------------------------------------------------------

    \17\ Memo 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.
    \18\ Consent 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.
    \19\ Consent 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.
    \20\ As 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \21\ A 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.
---------------------------------------------------------------------------

    Response: While the regulatory language at Sec.  49.4164(b) in the 
interim final rule is not specific on this point, the recordkeeping 
requirements for well completion and recompletion operations in Sec.  
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.

[[Page 17846]]

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 
Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \22\ Commenter 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.
---------------------------------------------------------------------------

    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,

[[Page 17847]]

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.
---------------------------------------------------------------------------

    \23\ The 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.
---------------------------------------------------------------------------

    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 heater-
treaters 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 Sec.  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\
---------------------------------------------------------------------------

    \24\ A 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.
---------------------------------------------------------------------------

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

[[Page 17848]]

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 Sec.  
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.
---------------------------------------------------------------------------

    \25\ Commenter does not list the rule with which such a change 
would maintain consistency.
---------------------------------------------------------------------------

    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 Sec.  
60.5415(e)(vii)(C) and (e)(vii)(D)(3), and the general provisions at 
Sec.  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 Sec.  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 Sec.  
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 Sec.  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 well-established 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.
---------------------------------------------------------------------------

    \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)).

---------------------------------------------------------------------------

[[Page 17849]]

    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 self-certification 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\
---------------------------------------------------------------------------

    \27\ The 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \29\ Commenter 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: 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

[[Page 17850]]

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

[[Page 17851]]

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.
---------------------------------------------------------------------------

    \30\ See 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.
---------------------------------------------------------------------------

    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.
    Sec.  49.140 is now Sec.  49.4161;
    Sec.  49.141 is now Sec.  49.4162;
    Sec.  49.142 is now Sec.  49.4163;
    Sec.  49.143 is now Sec.  49.4164;
    Sec.  49.144 is now Sec.  49.4165;
    Sec.  49.145 is now Sec.  49.4166;
    Sec.  49.146 is now Sec.  49.4167; and
    Sec.  49.147 is now Sec.  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.
---------------------------------------------------------------------------

    \31\ For 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.
---------------------------------------------------------------------------

    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

[[Page 17852]]

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 Sec.  
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 
Sec.  49.4161(c) to clarify that the compliance date is upon initiation 
of well completion operations and well recompletion operations, as 
follows: ``Sec.  49.4161(c) When must I comply with Sec. Sec.  49.4161 
through 49.4168? Compliance with Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \32\ U.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.
---------------------------------------------------------------------------

    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

[[Page 17853]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    The control devices must be operated under specific conditions as 
specified in Sec.  49.4165 Control Equipment Requirements and Sec.  
49.4166 Monitoring Requirements.

F. Control Equipment Requirements

    The provisions in Sec.  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, Sec.  
49.4165 requires specific construction and operational requirements of 
pit flares, enclosed combustors, and utility flares.
    The provisions in Sec.  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 closed-vent 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 non-
diverting 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

[[Page 17854]]

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 Sec.  
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 
Sec.  49.4165(c)(4). We have added language at Sec.  49.4165(c)(4) to 
provide an exemption to Sec.  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 Sec.  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 Sec.  49.4166(g)(1). 
The rule now reads as set forth in the regulatory text of this final 
rule at Sec.  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 Sec.  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 Sec.  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 closed-vent 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 Sec.  
49.4166(d) to describe acceptable gas volume measurement methods, thus 
making this provision consistent with the provision at Sec.  
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 Sec.  
49.4166(g)(1).
    Revision: We have clarified the intent of the provision at Sec.  
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 Sec.  
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 Sec.  
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 
Sec.  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 Sec.  
49.4167(a)(8) to clarify that records

[[Page 17855]]

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 Sec.  
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 Sec.  
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

[[Page 17856]]

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 cost-effective 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

[[Page 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

[[Page 17858]]

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, low-income, 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\
---------------------------------------------------------------------------

    \34\ The 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.
---------------------------------------------------------------------------

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]

0
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

0
2. Add Sec. Sec.  49.4161 through 49.4168 and an undesignated center 
heading to appear immediately before the newly added Sec.  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

Sec.  49.4161  Introduction.

    (a) What is the purpose of Sec. Sec.  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 Sec. Sec.  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

[[Page 17859]]

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 Sec. Sec.  49.4161 through 49.4168? 
Compliance with Sec. Sec.  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.

Sec.  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 Sec.  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.

Sec.  49.4163  General provisions.

    (a) Definitions. As used in Sec. Sec.  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,

[[Page 17860]]

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 heater-treater 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 facility-based processes.
    (27) Utility flare means thermal oxidation system using an open 
(without enclosure) flame. An enclosed combustor as defined in 
Sec. Sec.  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.

[[Page 17861]]

Sec.  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 Sec. Sec.  
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 Sec. Sec.  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 Sec. Sec.  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 
Sec. Sec.  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 
Sec. Sec.  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 Sec.  49.4164(d)(2). No further 
requirements apply for such storage tanks under Sec.  49.4164(d)(2).

Sec.  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

[[Page 17862]]

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 Sec.  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 Sec. Sec.  49.4161 through 
49.4168 using the procedure specified in 40 CFR part 60, subpart OOOO 
at Sec.  60.5413(d) by the due date of the first annual report as 
specified in Sec.  49.4168(b); or
    (ii) Demonstrated to meet the VOC destruction efficiency 
requirements of Sec. Sec.  49.4161 through 49.4168 using EPA approved 
performance test methods specified in 40 CFR part 60, subpart OOOO at 
Sec.  60.5413(b) by the due date of the first annual report as 
specified in Sec.  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.

Sec.  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

[[Page 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 set-points 
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 Sec. Sec.  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 Sec. Sec.  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.

Sec.  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 Sec.  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

[[Page 17864]]

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 Sec.  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.

Sec.  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 Sec. Sec.  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 Sec.  
49.4164, Sec.  49.4165, or Sec.  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
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