1 

The EPA Administrator, Lisa Jackson, signed the following notice on 8/1/2012, and EPA is submitting it for publication in the 

Federal Register (FR). This version of the rule serves as the official version for purposes of compliance until the interim final 

rule is published in the FR. Please refer to the published version in a forthcoming FR publication, which will appear on the 

Government Printing Office's FDsys website (http://fdsys.gpo.gov/fdsys/search/home.action) and on Regulations.gov 

(http://www.regulations.gov) in Docket No. EPA-R08-0AR-2012-0479. 

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 49

[EPA-R08-OAR-2012-0479; FRL- 9710-4] 

Approval and Promulgation of Federal Implementation Plan for Oil and Natural Gas Well 

Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nations), 

North Dakota

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Interim final rule. 

SUMMARY: 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 located 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 EPA, or a delegated Tribal Authority, until replaced by a Tribal Implementation

Plan. EPA is proposing a Reservation-specific Federal Implementation Plan concurrently with this 

interim final rule. 

DATES: This rule is effective in the CFR on [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. This rule is effective with actual notice by EPA to the owners and operators 

for purposes of enforcement beginning at 5 p.m. (eastern daylight time) on August 3, 2012. We will 

accept comments on the proposed rule until [INSERT DATE 45 DAYS FROM THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. 

Public Hearing: EPA will hold a public hearing on the following date: September 12, 2012. The
2 

hearing will start at 1:00 p.m. local time and continue until 4:00 p.m. or until everyone has had a chance 

to speak. Additionally, an evening session will be held from 6:00 p.m. until 8:00 p.m. The hearing will 

be held at the 4 Bears Casino & Lodge, 202 Frontage Rd, New Town, ND 58763, (701) 627-4018. 

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R08-OAR-2012-0479, by 

one of the following methods: 

• http://www.regulations.gov. Follow the on-line instructions for submitting comments. 

• E-mail: r8airrulemakings@epa.gov

• Fax: (303) 312-6064 (please alert the individual listed in the FOR FURTHER 

INFORMATION CONTACT if you are faxing comments). 

• Mail: Carl Daly, Director, Air Program, U.S. Environmental Protection Agency (EPA), 

Region 8, Mailcode 8P-AR, 1595 Wynkoop Street, Denver, Colorado 80202-1129. 

• Hand Delivery: Carl Daly, Director, Air Program, U.S. Environmental Protection 

Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop Street, Denver, Colorado 

80202-1129. Such deliveries are only accepted Monday through Friday, 8:00 a.m. to 

4:30 p.m., excluding Federal holidays. Special arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to Docket ID No. EPA-R08-OAR-2012-0479. EPA's policy is that 

all comments received will be included in the public docket without change and may be made available 

online at http://www.regulations.gov, including any personal information provided, unless the comment 

includes information claimed to be Confidential Business Information (CBI) or other information whose 

disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise 

protected through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site is an 

“anonymous access” system, which means EPA will not know your identity or contact information 
3 

unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA, 

without going through http://www.regulations.gov, your e-mail address will be automatically captured 

and included as part of the comment that is placed in the public docket and made available on the 

Internet. If you submit an electronic comment, EPA recommends that you include your name and other 

contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA 

cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA 

may not be able to consider your comment. Electronic files should avoid the use of special characters, 

any form of encryption, and be free of any defects or viruses. For additional information about EPA's

public docket, visit the EPA Docket Center homepage at www.epa.gov/epahome/dockets.htm.

Docket: All documents in the docket are listed in the http://www.regulations.gov index. 

Although listed in the index, some information is not publicly available, e.g., CBI or other information 

whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be 

publicly available only in hard copy. Publicly-available docket materials are available either 

electronically in http://www.regulations.gov or in hard copy at the following locations: Air Program, 

U.S. Environmental Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop, Denver, 

Colorado 80202-1129; and Environmental Division, Three Affiliated Tribes, 204 West Main, New 

Town, North Dakota 58763-9404. EPA requests that if at all possible, you contact the individuals 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, 8:00 a.m. to 4:00 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. 
4 

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. 
5 

(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. 
6 

(xxxvii)The initials WDEQ mean or refer to Wyoming Department of Environmental Quality Air 

Quality Division. 

Table of Contents 

I. Justification for this Interim Final Rule 

A. Overview 

B. Rationale for the Interim Final Rule 

II. Proposed Rulemaking 

III.Background 

A. Today’s Action 

B. Purpose of the Rule 

C. Development of the Rule 

D. Area & Facilities Covered by the FIP 

E. Effect on Permitting of Facilities 

F. Registration Requirements 

G. Applicability to New & Existing & Modified Facilities 

H. Attainment Status 

I. Benefits and Costs 

 

IV.The Fort Berthold Indian Reservation 

V. EPA’s Authority to Promulgate a FIP 

VI. Summary of FIP Provisions 

A. Applicability 

B. Compliance Schedule 

C. Provisions for Delegation of Administration to the Tribes 
7 

D. General Provisions 

E. Construction and Operational Control Measures 

F. Control Equipment Requirements 

G. Monitoring Requirements 

H. Record Keeping Requirements 

I. Reporting Requirements 

VII. Statutory and Executive Order 

I. Justification for this Interim Final Rule

A. Overview 

In today’s action, we are promulgating a Reservation-specific Federal Implementation Plan (FIP 

or rule) to establish enforceable control requirements for reducing volatile organic compound (VOC) 

emissions from oil and natural gas production activities on the Fort Berthold Indian Reservation (FBIR) 

in North Dakota. Specifically, we are issuing this rule to require owners and operators of oil and natural 

gas production facilities producing from the Bakken Pool to reduce emissions of VOCs emanating from 

well completions, recompletions, and production and storage operations. As explained in more detail in 

Section III, promulgating these Federal regulations addresses an important initial step to fill a regulatory 

gap with regard to controlling VOC emissions from oil and natural gas operations on the FBIR. There is 

no other federal rule, including the recently finalized New Source Performance Standard (NSPS) and 

National Emission Standards for Hazardous Air Pollutants (NESHAP) for the Oil and Gas Sector (NSPS 

OOOO and NESHAP HH), that fills this gap for the particular geologic formations that exist on the 

FBIR. Therefore, this rule is necessary to level the playing field, and provide the public on the FBIR the 

same air quality protections as the public outside the FBIR. In addition, owners and operators of oil and 

natural gas operations on the FBIR are provided the same benefits that owners and operators of oil and
8 

natural gas operations off the Reservation are provided by North Dakota Department of Health 

(NDDoH) regulations and North Dakota Industrial Commission (NDIC) regulations in terms of 

effectively limiting potential to emit (PTE).1

 

B. Rationale for the Interim Final Rule 

EPA is issuing this action as an interim final rule. As explained in Section III., the interim final 

rule requires owners and operators of oil and natural gas production facilities on the FBIR to reduce 

emissions of VOC for specific types of equipment. This interim final rule will take effect promptly. It 

will be effective in the CFR on [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER]. It will also be effective, with actual notice by EPA to the owners and operators, for 

purposes of enforcement beginning at 5 p.m. (eastern daylight time) on August 3, 2012. This interim 

final rule is also time-limited. It will be effective only until the date that EPA promulgates a final rule 

based on its proposal for a Reservation-specific FIP to regulate emissions from oil and natural gas 

productions facilities located on the FBIR and that final rule takes effect. EPA is proposing a 

Reservation-specific FIP concurrently with this interim final rule. As explained in detail below, EPA

finds that compelling circumstances warrant the promulgation of this interim final rule. 

An interim final rule is effective with actual notice upon signature by the EPA without an 

opportunity for public comment. Under APA section 553, a federal agency generally must provide for 

public notice and comment prior to finalizing an agency rule. However, this obligation is excused, 

under APA section 553(b)(3)(B), “when the agency for good cause finds (and incorporates the finding 

and a brief statement of reasons therefore in the rules issued) that notice and public procedure thereon 

are impracticable, unnecessary, or contrary to the public interest.” While the good cause exception is to 

 

1 Depending on the emissions characteristics of a particular well, compliance with the requirements of the FIP may or may 

not limit the well’s PTE to below the major source thresholds such that the well is not subject to major source prevention of 

significant (PSD) permitting and/or to national emission standards for hazardous air pollutants (NESHAP) requirements.
9 

be narrowly construed, Utility Solid Waste Activities Group v. Environmental Protection Agency, 236 

F.3d 749, 754 (D.C. Cir. 2001), it is also “an important safety valve to be used where delay would do 

real harm.” U.S. Steel Corp. v. U.S. Environmental Protection Agency, 595 F.2d 207, 214 (5th Cir. 

1979). Notice and comment are impracticable where “an agency finds that due and timely execution of 

its functions would be impeded by the notice otherwise required.” Utility Solid Waste Activities Group, 

236 F.3d at 754. Notice and comment are contrary to the public interest where “the interest of the public 

would be defeated by any requirement of advance notice.” Id. at 755. 

A brief explanation of the circumstances is helpful to understand why Notice and comment here 

would be both contrary to the public interest and impracticable and therefore why there is good cause to 

implement this interim final rule while the agency conducts a notice and comment rulemaking for the 

permanent rule. The need to address VOC emissions from coproduced natural gas from oil and natural 

gas production sources on the FBIR was first brought to EPA’s attention approximately 12 months ago, 

following publication of the Review of New Sources and Modifications in Indian Country or Federal 

Tribal NSR Rule, promulgated on July 1, 2011, at 40 CFR 49.151 (see 76 FR 38748). At that time, a 

significant number of entities engaged in oil and natural gas production operations on the FBIR 

informed EPA that the emissions of regulated air pollutants, including volatile organic compounds 

(VOCs), from oil and natural gas production facilities were significantly larger than they had previously 

understood. These emissions created a public health and safety hazard and were sufficiently large that 

hundreds of individual facilities would potentially be required to obtain major source PSD permits 

unless they were able to obtain legal and practicably enforceable emission limits on the facilities’ 

potential-to-emit. 

In August 2011, EPA and the operators entered into consent agreement final orders (CAFOs), 

which established control requirements that restricted emissions from the oil and natural gas production 
10 

facilities subject to those agreements to below major source thresholds and allowed the operators to 

continue to operate pending issuance of appropriate permits. 

In late August 2011, the EPA Region 8 initiated a process to develop, propose and issue permits 

to the hundreds of sources on the FBIR (both existing and proposed new wells) and to develop a FIP. At 

that time, EPA lacked detailed information to develop permits (e.g., information about the facilities,

emissions, and possible emission controls) and therefore, hosted numerous meetings from August 

through November 2011 to collect the necessary information and develop complete permit applications 

and draft permit language.2

 The EPA drafted and proposed the first batch of permits in March 20123, 

and explained in our April 10, 2012 letter to Chairman Hall that “[t]he comment period for these permits 

will end on April 23, 2012, at which time we will consider comments and finalize these permits,” noting 

that “these completed permits will form the basis for the FIP.” While we had developed an example 

permit to provide predictability and a framework for permitting, it was clear that each permit would 

need to be developed on a case-by-case basis using information submitted in each application. 

We initially planned to issue all of the necessary permits before August 26, 2012, the earliest 

 

2 Resolving the challenges on the FBIR has been a top priority for EPA. The Agency has dedicated enormous resources to 

resolve these challenges at the Regional and National offices for nearly a year and continues to do so. EPA’s efforts have 

included the following activities. 

In late August 2011, the EPA Region 8 air permit and enforcement programs hosted a Fort Berthold Oil Production Minor 

NSR Permitting Process Meeting with the oil producers. Representatives from the MHA Nation 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 model 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 MHA Nation were invited 

and attended. Representatives of the North Dakota Dept. of Health 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 model permit and set up a workshop specifically to delve into the specific permit conditions for the following week. On 

September 7 and 8, 2011, EPA hosted a two-day follow-up permitting workshop. All previous meeting attendees were 

invited, including the MHA Nation. Participants included the oil producers and their consultants. North Dakota Department 

of Health representatives were also on the phone. At this meeting the group went through the draft model 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 MHA Nation were invited and attended. 

3 The draft permits that underwent a public review and comment period are available online at: 

http://www.epa.gov/region8/air/permitting/pubcomment.html. 
11 

expiration date of the CAFOs. However, in May 2012, the true extent of the significant workload 

associated with developing and finalizing permits for more than 600 existing and new oil and natural gas 

production facilities became apparent. It became clear that, due to the extraordinary number of permits 

that needed to be issued, the need to tailor each of those permits to comport with the information in the 

permit application and the short timeframe remaining to complete those tasks, it would not be possible

to issue all, or even a significant portion of, the final permits by August 26, 2012. Moreover, given the 

rapid pace of oil and gas development on the FBIR, there are likely numerous additional sources that 

will each need a permit in addition to sources EPA is aware of at this time. We therefore determined 

that the only way to ameliorate the situation in a timely manner was through this rulemaking action. We 

contemplated developing the FIP in addition to issuing the individual permits, but determined that 

promulgating the FIP should be our top priority once we realized that we could not issue all of the 

necessary permits in a timely manner. 

 Key safety provisions of the interim final rule require either collection and high efficiency 

flaring (combustion) of coproduced natural gas or that the well(s) be connected to a natural gas 

gathering line so that coproduced natural gas can be sold or used for another beneficial purpose. Given 

the accelerated development in this area and the nature of the oil and gas extracted, these requirements 

are necessary for both safety and protection of public health from exposure to air pollution and will 

avoid fire hazards and protect the public from hazardous conditions. Specifically, the requirements 

further a number of important goals in that regard. First, as discussed in Section III.C., VOC emissions 

from the natural gas that is co-produced with oil extracted from the formations are generally greater than 

such emissions from activities in other oil bearing formations, due to the characteristics of the produced 

oil. The FIP requirements for owners and operators of the oil and natural gas production facilities to 

reduce emissions of VOCs emanating from well completions, recompletions and production and storage 
12 

operations will significantly reduce VOC emissions thereby ensuring that public health and the 

environment are protected. Second, the rule will result in immediate reductions in fire risks and 

improvements in air quality as a result of control of emissions from both new and existing oil and gas

operations. Accordingly, as a result of the unique characteristics of the formations at issue, immediate 

application of the FIP requirements to both new and existing oil and natural gas operations is necessary 

to ensure that public health and the environment, continue to be protected once consent agreement final 

orders (CAFOs) with EPA expire. 

The requirements of the FIP also serve to minimize regulatory burden in a number of ways. 

This rule ensures that ongoing oil and gas operations (including modifications), and new operations, can 

occur uninterrupted in a manner consistent with the Clean Air Act (CAA), thus protecting the economic 

interest of both the companies and Tribes involved and the local communities. The oil and natural gas

production companies operating on the FBIR entered into CAFOs with EPA which allowed them to 

continue existing operations and begin new ones without first complying with major source prevention 

of significant deterioration (PSD) new source review (NSR) requirements if applicable, which can be a 

very lengthy and resource-intensive process. These CAFOs are further discussed in Section III.G. The

CAFOs, which contain emissions control and other requirements that are consistent with those in the 

rule adopted today, have been in place since August 2011 and will expire beginning on August 26, 

20124

, a date which is rapidly approaching. In the absence of this rule, hundreds of new and existing oil 

and natural gas production sources on the FBIR that are subject to these CAFOs would be unable to 

continue to operate, construct or modify in compliance with CAA requirements without first obtaining a

permit from EPA because they will have no legally and practicably enforceable requirements in place 

controlling VOC emissions, thus significantly disrupting ongoing economic activities and the benefits 

 

4 The FBIR CAFOs are included in the docket for this rule. 
13 

those activities bring to the communities of the Reservation. 

As a result, without this interim final rule there will be a mixture of circumstances that will 

increase potential threats to human health and the environment while simultaneously impeding oil and 

gas development. This is because of the mix of current CAA obligations that currently apply to these 

wells. While many sources would first need to obtain a PSD permit to construct or would need to 

resolve ongoing violations to continue to operate, other sources could operate without obtaining a 

permit. Accordingly, sources that need to resolve permitting obligations would be delayed in 

construction or operation (impeding development) while those without permitting obligations would 

operate uncontrolled as the interim final rule requirements would not be in place. 

In summary, this rule serves the necessary function of ensuring that a regulation is in place to 

control emissions of VOCs by these sources. These provisions contain legally and practicably 

enforceable requirements to use control measures to reduce VOC emissions such that those reductions 

can then be considered in calculating a source’s PTE. In most cases, consideration of these emission 

reductions in calculating a source’s PTE VOCs will result in a PTE that is below the regulatory 

threshold so that the source will not face a long delay in its ability to continue to operate, construct or 

modify. The public interest would certainly be hindered if EPA did not act now to ensure that these 

important public health protections are in place and that economic progress is not impeded by a lack of 

regulations controlling VOC emissions. 

Finally, this rule is important in that while not identical to, the rule is consistent with regulations 

approved into North Dakota’s SIP5

 under the authority of the NDDoH and regulations under the 

 

5 North Dakota Century Code (NDCC) (Chapter 23-25 Air Pollution Control); Air Pollution Control Rules (Article 33-15) 

Chapter 33-15-07 Control of Organic Compound Emissions, and Chapter 33-15-20-04 Control of Emissions from Oil and 

Gas Well Production Facilities. North Dakota Legislative Branch. Available online at: 

http://www.legis.nd.gov/information/acdata/html/33-15.html. Accessed May 29, 2012. Within EPA approved SIP. 
14 

authority of the NDIC6, which were established for similar purposes. Accordingly, this rule ensures that 

consistent requirements apply to activities both inside of and within the FBIR. 

 The good cause exception also applies here because of the impracticability of notice and 

comment. EPA initially did not recognize the sheer magnitude of the volume of permit applications that 

it would need to process in a short time period to avoid economic disruption on the Reservation. Now 

that it fully comprehends the enormity of the task, EPA has determined that it would be unable to timely 

process more than 600 permit applications, specified to be submitted as part of the CAFOs between EPA 

and the oil and natural gas owners and operators by August 2012. Because of our inability to process 

these permits, and because of lateness at which we became fully aware of the full scope of the burden,

EPA thus has had insufficient time to seek public comment before acting on the rule promulgated today. 

 While we have determined that notice and comment are both contrary to the public interest and 

impracticable, we note that the public has had several opportunities to learn about, and even comment 

on, the substantive requirements contained in this interim rule. The substance of many provisions in the 

interim final rule are similar to the requirements contained in the six permits for individual oil and gas 

production facilities on the FBIR that EPA proposed earlier this year. We received comments from the 

public and the sources on those proposed permits and we have taken those comments into consideration 

in developing the FIP requirements. The substantive requirements of the FIP are also similar to the 

conditions in the CAFOs under which the oil and natural gas production sources have been operating for

nearly a year, and the public had notice of the CAFOs, which were posted on EPA’s Internet site for 

public review.7

 Furthermore, the public has an additional, full opportunity to comment on the 

permanent rule that EPA is concurrently proposing today, which mirrors, and will replace this interim 

 

6 NDCC (Chapter 38-08 Control of Oil and Gas Resources); Article 38-08-06.4. Flaring of Gas Restricted - Imposition of 

Tax - Payment of Royalties - Industrial Commission Authority; and Article 43-02-03-28 Safety Regulation. Available online 

at: https://www.dmr.nd.gov/oilgas/rules/rulebook.pdf. Accessed July 5, 2012. State only rule. 

7

 EPA Administrative Enforcement Dockets, available at: http://yosemite.epa.gov/oa/rhc/epaadmin.nsf. 
15 

rule. By issuing this rule as an interim final rule, paired with a comment period on the proposal for more 

permanent action, EPA is providing as much opportunity for notice and comment as possible on the 

issues presented by this rule. EPA will expeditiously and fully, consider any comments received on the 

proposed rule, and once we have completed our deliberative process, will make any necessary revisions 

in taking final action on the proposed rule. 

For the reasons discussed above, EPA finds both that there is good cause to forego notice and 

comment for this interim rule, and that there is good cause for this rule to take immediate effect and to 

take effect as described above, for those sources that receive actual notice for purposes of enforcement. 

Since this is not a major rule under the Congressional Review Act (CRA), the 60-day delay in effective

date required for major rules under the CRA does not apply. 

II. Proposed Rulemaking

We are also simultaneously publishing a parallel proposed rulemaking which seeks comment on 

information found within this interim final rule. Note that Docket Number EPA-R08-OAR-2012-0479 

is being used for both the interim final rule and the parallel proposed rule. 

III. Background

A. Today’s Action

In today’s 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. Specifically, we are issuing this rule to require owners and operators of oil and 

natural gas production facilities producing from the Bakken Pool8 to reduce emissions of VOCs 

emanating from well completions, recompletions, and production and storage operations. Oil and 

natural gas production facilities may also contain other VOC-emitting units that include, but are not 

 

8

 The Bakken Pool is defined as a compilation of crude oil formations consisting of Bakken, Sanish and Three Forks 

formations. 
16 

limited to, pumps, compressors, pneumatic devices, dehydrators, and engines. This rule does not 

contain requirements for, or otherwise apply to, those types of equipment. If we determine at a later

date that there is a need for legally and practicably enforceable control of VOC emissions from 

additional equipment at these oil and natural gas production facilities, or for legally and practicably 

enforceable control of additional regulated NSR pollutant emissions, we may propose additional FIPs or

propose supplements to this FIP.

B. Purpose of the Rule

As noted above, promulgating these Federal regulations addresses an important initial step to fill 

a regulatory gap with regard to controlling VOC emissions from oil and natural gas operations on the 

FBIR. There is no other federal rule, including the recently finalized NSPS and NESHAPs for the Oil 

and Gas Sector (NSPS OOOO and NESHAP HH)9, that fills this gap for the particular geologic 

formations that exist on the FBIR. This is in contrast to oil and natural gas operations off the 

Reservation which are governed by the NDDoH regulations and NDIC regulations previously discussed. 

As a result of these regulations, oil and natural gas operators in NDDoH jurisdiction are provided 

mechanisms for establishing legally and practicably enforceable control requirements that reduce VOC 

emissions and allow them, in most cases, to forgo time consuming and costly preconstruction 

permitting requirements before being able to start operations while helping to protect air quality and

prevent fires, thus addressing the two concerns that we noted above have justified this interim final rule. 

What we are providing in the way of regulations in the FIP, and the impact that it will have on 

permitting is generally consistent with the approach that we have approved of in the areas surrounding

the FBIR. Owners and operators of oil and natural gas operations in the NDDoH jurisdiction producing 

 

9 The requirements in NSPS OOOO and revised NESHAP HH were finalized on April 17, 2012, but not yet promulgated and 

can be found at http://www.epa.gov/airquality/oilandgas/actions.html, until such time that the final rule is published in the 

Federal Register. 
17 

from the Bakken Pool are potentially subject to the North Dakota preconstruction permitting 

requirements found in the North Dakota Air Pollution Control Rules (“North Dakota Rules”) at Chapter 

33-15-14 (Designated Air Contaminant Sources, Permit to Construct, Minor Source Permit to Operate, 

Title V Permit to Operate) and Chapter 33-15-15 (Prevention of Significant Deterioration of Air 

Quality) if uncontrolled emissions are greater than the permitting thresholds. However, all of the 

owners and operators are also subject to the North Dakota Rulesfor the operation of oil and natural gas 

production operations in the State of North Dakota. The regulations found at Chapter 33-15-07 (Control 

of Organic Compound Emissions) provide legally and practicably enforceable control requirements and 

VOC emission reductions when applicable. Additionally, all of the owners and operators are subject to

the NDIC regulations for well completions found at Chapter 38-08 Control of Oil and Gas Resources. 

In many cases, owners and operators complying with these additional North Dakota Rules and NDIC 

regulations, and following the NDDoH guidance (Bakken Pool Guidance)10 do not have to obtain 

preconstruction permits from the NDDoH and can begin construction in a timelier manner. 

Similar to the owners and operators of oil and natural gas operations producing from the Bakken 

Pool in NDDoH jurisdiction, the owners and operators of oil and natural gas operations producing from 

the Bakken Pool on the FBIR are potentially subject to the federal preconstruction permitting 

requirements found in the Federal rules at 40 CFR 52.21 (Prevention of Significant Deterioration of Air 

Quality), and 40 CFR 49.151 through 49.161 (Federal Tribal NSR Rule). However, on the FBIR only 

NSPS OOOO and NESHAP HH provide legally and practicably enforceable VOC control requirements 

outside of the federal pre-construction permitting requirements. Further, NSPS OOOO only applies to 

new and modified facilities and only to the oil storage tanks being utilized in the Bakken Pool 

 

10 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. 
18 

operations. Thus, most owners and operators of oil and natural gas activities producing in the Bakken

Pool must obtain preconstruction permits before production can begin, or if they are not obligated to 

obtain a permit face no control obligations whatsoever. 

This rule will fill this regulatory gap. Consistent with the regulatory structure that exists off the

FBIR, and NSPS OOOO, this rule requires VOC control requirements and emissions reductions, 

monitoring, recordkeeping and reporting with regard to well completions, recompletions, and production

and storage operations. This rule will also, to the extent practicable, minimize the construction 

permitting program implementation burdens upon us and the regulated community while establishing 

requirements that are unambiguous and legally and practicably enforceable. 

However, this rule will not eliminate any potential permitting requirements for oil and natural 

gas production facilities, but in many cases it will impose legally and practicably enforceable 

requirements that will lower PTE to a level that will allow the operators to construct without being 

required to obtain a PSD or federal preconstruction permit under the Federal Tribal NSR Rule for Indian 

country. Specifically, where compliance with the requirements of this rule results in PTE VOCs from 

all pollution-emitting sources at the facility that are less than the thresholds in the PSD and Federal 

Tribal NSR rules, the source would not trigger permitting requirements and therefore may avoid PSD 

and minor source preconstruction permitting altogether. To comply with the CAA and avoid PSD or 

minor source preconstruction permitting altogether, a facility must calculate its PTE VOCs from all 

pollution-emitting sources at the facility and verify that it is less than the threshold in the PSD and 

Federal Tribal NSR rules. While we believe that VOC is the pollutant most likely to be emitted in 

quantities sufficient to require permitting, the facility may not avoid the PSD and Federal Tribal NSR

permitting requirements if its emissions of any other regulated NSR pollutant are high enough to trigger 

PSD requirements. 
19 

Included in the docket for this rule are copies of the NDDoH rules and guidance and the NDIC 

regulations that we considered in this process, as well as a technical support document explaining the

requirements as compared to these requirements. 

C. Development of the Rule

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. We also held a meeting with the Three Affiliated Tribes of 

the Mandan, Hidatsa, and Arikara Nations on June 13, 2012. 

To develop this rule, we first determined that oil and natural gas production on the FBIR from 

the Bakken Pool was becoming increasingly prevalent and that information regarding the nature of the 

fluids produced from the Bakken Pool indicated significant emissions of VOC. We accomplished this 

step by reviewing information provided by the NDDoH and a host of oil and natural gas operators 

already producing in the Bakken Pool11. 

In order to develop appropriate requirements for the control of emissions from the production 

operations in the Bakken Pool, we studied the nature of the hydrocarbon liquids being produced and 

existing operations currently in practice. An oil well produces predominantly crude oil, with some 

natural gas dissolved in it. Each crude oil reservoir has a combination of chemical and physical qualities 

which makes it unique. Some crude oil types are 'heavy' (high viscosity and gravity containing very 

little associated natural gas) and some 'light' (low viscosity and gravity containing high amounts of 

associated natural gas). The crude oil from the Bakken Pool is a light crude oil. It contains a higher 

 

11 The information reviewed was contained in synthetic minor NSR applications submitted to EPA, which are included in the 

docket for this rule. 
20 

amount of lighter hydrocarbon components than is seen in heavy crude oil, and therefore has greater 

potential to produce natural gas in addition to oil. Because of this characteristic, the production of crude 

oil from the Bakken Pool wells is similar to the production of natural gas liquids from natural gas wells. 

Natural gas liquids contain lighter end hydrocarbons such as ethane, propane, butane, and pentane, and

methane gas. In addition, methods used to extract the hydrocarbons from both natural gas wells and the 

Bakken Pool wells produce hydrocarbon liquids that also contain water. Therefore, similar to natural 

gas well production, the production methods in the Bakken Pool involve the separation of the produced 

liquid into hydrocarbon liquids (oil), natural gas and water. 

The oil/natural gas/water emulsion being produced from each well is transported up the wellbore 

using an electric lifting unit, when required. The emulsion from the wells producing to this facility is 

transported through 2-phase separators (separators) which are an inherent component of the pipeline. 

The number of separators on any one production pipeline can vary from one to several. These 

separators reduce the pressure of the oil/natural gas/water emulsion to initiate the separation of the

natural gases from the liquids. The natural gases and liquids are then sent to a 3-phase separator (heatertreater). The heater-treater reduces the pressure closer to ambient pressure and heats the leftover 

emulsion using a flame-arrested line heater (the heater-treater burner). The combination of higher 

temperatures and lower pressures allows for additional separation of the natural gas/oil/water phases 

from each other because of differences in densities. 

Following the heater-treater, the produced oil and water are routed to storage tanks. The 

recovered natural gas is transferred from the heater-treater to the sales natural gas pipeline or to an 

emissions control unit when a natural gas sales pipeline is not available or the pipeline has a limited 

capacity. The oil is temporarily stored in these on-site storage tanks prior to being transferred either to 

tanker trucks or to a lease automatic custody transfer (LACT) unit for conveyance to a refining process 
21 

plant. Separated water is temporarily stored in the on-site storage tanks prior to being loaded into tanker 

trucks for transport and disposal. 

In addition to the natural gas recovered from the extracted wellhead fluids, low pressure natural 

gas is also collected from off-gassing that occurs from the storage of the produced oil and water in the 

on-site tanks at the facilities. This low pressure natural gas is collected via a vent line from the tanks 

and is either routed to an enclosed combustor, utility flare or pit flare for combustion, or is routed to a 

vapor recovery unit (VRU) to be injected into a natural gas sales pipeline for conveyance to a natural gas 

plant. In the event that pipeline injection of recoverable natural gas is temporarily infeasible and no 

enclosed combustor or utility flare is operational onsite, the natural gas may temporarily be routed 

through a closed-vent system to a pit flare. 

We further identified, in the information provided, that the most prevalent sources of VOC 

emissions associated with oil and natural gas production come from well completions, recompletions, 

and production and storage operations. During well completions and recompletions there is a period of

flowback of oil, natural gas, and water from newly drilled wells in order to expel drilling and reservoir 

fluids which vents considerable VOC emissions to the atmosphere. Large amounts of VOCs are also 

emitted during production when the reservoir fluids are separated into oil, natural gas and water under 

high pressure using heat. Finally, the transfer and storage of the produced oil and water after separation 

can be a source of VOC emissions if vented to the atmosphere. In other words, the separated oil and 

water are both under high pressure and still contain some dissolved natural gas. When the separated oil 

and water are subjected to atmospheric pressure during transfer to storage tanks, the dissolved natural 

gas comes out of the liquid. Unless a natural gas sales pipeline is available and is used to receive the 

evolved natural gas, it becomes a significant source of VOC emissions. Due to the high levels of VOC 

emissions from these specific operations, we established VOC control and emission reduction 
22 

requirements in this rule for completion and recompletion operations, heater-treater systems associated 

with production operations, and storage tanks associated with oil and water storage operations. 

Because of the experience that already existed in the Bakken Pool, we consulted with the owners 

and operators that are currently producing from the Bakken Pool on the FBIR and in NDDoH 

jurisdiction with regard to the production practices already in place. The practices currently in place are 

primarily due to product recovery or safety concerns and demonstrate compliance with the applicable 

NDIC regulations for flaring of co-produced natural gas and safety that address those concerns. These

consultations provided us not only with information on the production on and off the Reservation, but 

also provided us with information on the existing phased approach to controlling practices occurring 

both from well completion and recompletions, through production operations, and ending with storage 

and loading operations and an appropriate timeline for installation of the controls. Components of this 

rule are based on these practices that are already in place off the FBIR. 

In addition, we evaluated the North Dakota regulations to help identify appropriate requirements 

for construction and operation of the regulated equipment and the requirements for controlling VOC 

emissions from this equipment. The North Dakota Rules at Chapter 33-15-07 provide requirements for 

the construction and operation of units that separate volatile organic liquids from water, and the control 

of VOC emissions from such units. Specifically, Chapter 33-15-07 requires that any equipment 

processing, treating, storing or handling volatile organic liquids must be equipped with covers (in the 

case of tanks), closed vent systems and control devices, such as VRUs, enclosed combustors, or flares. 

Chapter 33-15-07 refers to the Standards of Performance for VOC Emissions from Petroleum Refinery 

Wastewater Systems at 40 CFR 60.690 for the control requirements and the requirements are 

appropriate to crude oil production operations. Chapter 33-15-07 requires the use of submerged pipe 

filling during storage operations to limit the evolution of natural gas from the oil and water. We 
23 

determined that the VOC emission reduction requirements during the separation of the oil, natural gas,

and water in this rule were relevant and appropriate as a basis for this rule. The North Dakota Rules at 

Chapter 33-15-20 provide requirements for the construction and operation of oil and natural gas 

production equipment and the control of VOC emissions from this equipment. Chapter 33-15-20 

includes requirements for storage tanks, separators and heater-treaters. While the North Dakota Rule 

only applies to oil or natural gas well production operations which emit sulfur or sulfur compounds to

the atmosphere, we determined that the construction and control requirements were relevant and 

appropriate as a basis for this rule. 

We also reviewed the NDIC regulations and the Bakken Pool Guidance. The NDIC regulations 

found in the Control of Oil and Gas Resources at Chapter 38-08 require natural gas from the heatertreaters to be routed to a natural gas gathering pipeline as soon as practicable. When a pipeline is not 

available, heater-treater natural gas is required to be routed to a control system or device. The Bakken 

Pool Guidance details the air pollution control requirements of oil and natural gas operations producing 

from the Bakken Pool and provides an approach that may be used by owners and operators of oil and 

natural gas operations producing from the Bakken Pool to demonstrate compliance with the applicable 

North Dakota Rules. VOC control requirements have been established within this guidance for tank 

emissions and heater-treater systems and much of the control equipment requirements and monitoring 

requirements in this rule were adapted from this guidance. Control of VOC emissions from other 

sources such as dehydration units, pneumatic controllers, pneumatic pumps, truck loading, etc. are also 

included in this guidance; however, we did not evaluate those components of oil and natural gas 

production operations. NDDoH identifies acceptable control systems that may be used by the owners 

and operators. These systems include: a ground pit flare for tank and heater-treater emissions with an 

assumed 90.0 percent VOC destruction efficiency; a VRU for tank emissions, designed and operated to 
24 

reduce the mass content of VOC emission by at least 99.0 percent; and an enclosed combustor or utility

flare for tank and heater-treater emissions designed and operated to reduce the mass content of VOC 

emission by at least 98.0 percent. Heater-treater natural gas must be routed to a natural gas gathering 

pipeline as soon as practicable. In addition, to VOC control requirements, the guidance provides 

extensive operating and monitoring requirements for the controls. According to the owners and 

operators that are producing from the Bakken Pool on the FBIR, they are already voluntarily following 

this guidance in the FBIR. Therefore, we determined that the VOC emission reduction requirements in 

this document were relevant and appropriate as a basis for establishing monitoring, recordkeeping and 

reporting requirements necessary for enforceability of this rule. 

We also reviewed NSPS OOOO, which provides standards for oil and natural gas production 

from natural gas wells. However, with the exception of storage tanks and pneumatic controls, none of 

the production operations from the oil wells in the Bakken Pool that are covered by this rule are covered 

by NSPS OOOO. While this standard does not regulate the completion, recompletion, or production 

operations for the operations producing from the Bakken Pool, the common characteristics between 

natural gas production and the Bakken Pool production and the regulatory requirements specific to 

completion and recompletion, provided insight into feasible control requirements for these operations. 

In addition, the monitoring, recordkeeping and reporting requirements for production and storage 

operations were reviewed, and for necessary conditions to ensure legal and practicable enforceability 

were included in this rule. Some of the enhancements to the enforceability of the VOC reductions in 

this rule are derived from this standard. 

Although we view the most relevant regulatory analogue to those operations that are in 

NDDoH’s jurisdiction and producing from the Bakken Pool, we also reviewed other state oil and natural 

gas production-related regulations for areas that are similar to North Dakota in industry, meteorology, or 
25 

air quality concerns to ensure the proposed requirements are legally and practicably enforceable, as well 

as reasonably achievable, because the technologies are being commonly used and regulated. 

 The other state air pollution agencies’ rules and/or guidance that we reviewed included: 

Montana Department of Environmental Quality (MDEQ)12, Wyoming Department of Environmental 

Quality Air Quality Division (WDEQ)13, Colorado Department of Public Health and Environment Air 

Pollution Control Division (CDPHE)14 and the Utah Department of Environmental Quality (UDEQ)15. 

We also reviewed the regulations for oil and natural gas production facilities under the Texas 

Administrative Code, implemented by the Railroad Commission of Texas, Oil and Gas Division 

(RCT)16, the New Mexico Environment Department Air Quality Bureau (NMED)17, and the Oklahoma 

Department of Environmental Quality Air Quality Division (ODEQ)18. However, we determined that it 

was not relevant to review state and local rules that are intended to address non-VOC pollutant 

emissions, nonattainment area requirements or specific localized air quality concerns unless such 

 

12 MDEQ. Chapter 8 Air Quality Subchapter 16 Emission Control Requirements for Oil and Gas Well Facilities Operating 

Prior to Issuance of a Montana Air Quality Permit. Available online at: http://www.deq.mt.gov/dir/legal/chapters/CH08-

16.pdf. Accessed May 29, 2012. State only rule. 

13 WDEQ Air Quality Division. Oil and Gas Production Facilities Chapter 6, Section 2 Permitting Guidance. Available 

online at: http://deq.state.wy.us/aqd/Oil%20and%20Gas/March%202010%20FINAL%20O&G%20GUIDANCE.pdf. 

Accessed May 29, 2012. State only guidance. 

14 Colorado Department of Health and Environment Air Pollution Control Division. Air Quality Control Commission 

Regulation Number 7- Control of Ozone Via Ozone Precursors (Emissions of Volatile Organic Compounds and Nitrogen 

Oxides) 5-CCR 1001-9. Available online at: http://www.cdphe.state.co.us/regulations/airregs/5CCR1001-9.pdf. Accessed 

May 29, 2012. State only rule. 

15 Utah Administrative Code, Rule R307-327 Ozone Nonattainment and Maintenance Areas – Petroleum Liquid Storage, and 

Rule R649-3 Drilling and Operating Practices. Utah Division of Administrative Rules. Available online at: 

http://www.rules.utah.gov/publicat/code.htm. Accessed May 29, 2012. State only rule. 

16 Texas Administrative Code, Title 16 Economic Regulation, Part 1 Railroad Commission of Texas, Chapter 3 Oil and Gas 

Division. Utah Texas Secretary of State. Available online at: http://www.sos.state.tx.us/tac/. Accessed May 29, 2012. State 

only rule. 

17 New Mexico Administrative Code, Title 20 Environmental Protection, Chapter 2 Air Quality, Part 38 Hydrocarbon 

Storage Facilities and Part 61 Smoke and Visible Emissions. New Mexico Commission of Public Records, New Mexico 

Register. Available online at: http://www.nmcpr.state.nm.us/nmac/_title20/T20C002.htm. Accessed May 29, 2012. State 

only rule. 

18 Oklahoma Administrative Code, Title 252 Department of Environmental Quality, Chapter 100 Air Pollution Control, 

Subchapter 37 Control of Volatile Organic Compounds. Oklahoma Secretary of State – Office of Administrative Rules. 

Available online at: http://www.sos.ok.gov/oar/online/viewCode.aspx. Accessed May 29, 2012. EPA approved SIP sections 

include: 252:100-37-1, 252:200-37-3, 252:100-37-4, 252:100-37-5, 252:100-37-15, 252:100-37-16, 252:100-37-26, 252:100-

37-35, 252:100-37-36, 252:100-37-37, 252:100-37-41, and 252:100-37-42; State only rule sections include: 252:100-37-2, 

252:100-37-17, 252:100-37-18, 252:100-37-25, and 252:100-37-38[Revoked]. 
26 

concerns are also present on the FBIR or control equipment requirements apply to the same emission 

units this rule seeks to address. Copies of all the state and local agency rules that we considered in this 

process and other supporting documentation are included in the docket for this rule. 

 Regarding state regulations and guidance for VOC destruction efficiency and monitoring of 

enclosed combustors and utility flares, the rule requirements are generally consistent with all state 

requirements for enclosed combustors and utility flares. 

When reviewing state regulations or guidance for produced oil and water storage tanks, we 

focused on those that might apply to the tank sizes that are typically constructed at oil and natural gas 

production facilities on the FBIR, primarily tanks with a storage capacity of 500 bbl each or less 

(approximately 21,000 gallons). The requirements for construction and emission control of produced oil 

and water storage tanks are fairly consistent with all state regulations and guidance reviewed, although 

there are varying degrees of de minimis natural gas throughput, storage capacities, or annual flashing 

emissions below which the requirements do not apply or the control equipment may be removed. The 

WDEQ requires 98 percent VOC reduction for tanks with a PTE greater than 10 tons per year (tpy) 

within 60 days of the first date of production, compared to ninety (90) days in this rule. The WDEQ 

also allows control equipment removal if flashing emissions decline to and are reasonably expected to 

remain below 8 tpy. We do not provide any de minimis throughput or storage capacities below which 

the requirements in this rule do not apply; however, as discussed previously, we allow owners or 

operators to use 90.0 percent control equipment after one year after the first date of production if the 

uncontrolled PTE VOCs emissions from the aggregate of all produced oil storage tanks and any 

produced water storage tanks interconnected with the produced oil storage tanks declines to less than 20 

tpy.

D. Area & Facilities Covered by the FIP
27 

This rule will apply 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 facility19 producing from the 

Bakken Pool and located on the FBIR as set forth in 40 CFR Part 49, Subpart 141 - Reservation-Specific

FIP for Oil & Natural Gas Production Facilities; FBIR. A more detailed description of the Reservation

is provided below in Section IV. 

This rulemaking is a step in addressing concerns that have been raised about the potential 

impacts due to increasing oil and natural gas development on the FBIR. If in the future, we become 

aware of air quality or permitting burden related to oil and natural gas production for other Reservations 

or areas of Indian Country, using our authority described in Section V. of this notice, we may propose

other FIPs that are deemed necessary or appropriate. 

E. Effect on Permitting of Facilities

This rule is not a permitting program. It therefore does not impose or exempt the facilities from 

any Federal CAA permitting requirements, including the PSD preconstruction permitting requirements 

at 40 CFR § 52.21 or Federal Tribal NSR Rule permitting requirements for minor sources at 40 CFR § 

49.151. The purpose of this rule is to 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 permitting requirements, to the extent

that the effect those controls would have on VOC emissions is legally and practicably enforceable. 

Regardless of this rule, some facilities’ PTE VOCs or any other regulated NSR pollutant may 

 

19 For the purposes of this rule, an oil and gas production facility consists of all the air pollution emitting units and activities 

located on or integrally connected to one or more oil and gas wells that are necessary for production and separation of 

reservoir fluids, temporary storage of produced and produced water, and preparation of the produced oil, produced water, and 

produced gas for transport off-site. Additionally, August 12, 2007 is the earliest well completion date identified in the 

CAFOs. 
28 

exceed the applicability thresholds for PSD or Federal Tribal NSR Rule permitting even after applying 

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. 

F. 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. Again, the purpose of this rule is to provide legal and practical enforceability 

for the use of VOC emission controls that are already being used as an industry standard and for VOC 

emissions reductions from those controls. 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. 

G. Applicability to New & Existing & Modified Facilities

This rule applies to each owner or operator constructing or operating an oil and natural gas 

production facility 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. 
29 

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. A well recompletion 

operation means any oil and natural gas well completion with hydraulic refracturing occurring at an oil 

and natural gas production facility. 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 initial completion operations and this equipment is not 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 gas production facility will be constructed. Requiring compliance with 

this rule upon recompletion of any one well at a facility is consistent with NSPS OOOO. According to 

the final NSPS OOOO notice, a completion operation associated with refracturing is considered a 

modification under CAA section 111(a), because physical change occurs to the well resulting in 

emissions increases during the recompletion operation (for the purposes of this rule the process of 

refracturing is defined as a recompletion). 

In determining the appropriate effective date and the well completion dates for this rule, we 

evaluated the purpose of the rule, the gaps in regulations, NSPS OOOO and the requirements and 

stipulations of CAFOs finalized between us and select operators on the FBIR in late August 2011 and 
30 

amended, in some cases, between then and July 2012. The August 12, 2007, date is the earliest well 

completion date identified in the CAFOs. These orders established control requirements during the life 

of the orders for facilities operating on the FBIR by these companies who voluntarily entered into the

agreement with us. One goal of this FIP for existing oil and natural gas production facilities is to 

provide a CAA compliance mechanism for those companies with CAFOs, prior to their expiration, 

which will occur between August 26, 2012 and August 31, 2012. Copies of all of the CAFOs can be 

found in the docket for the rule. 

H. Attainment Status

All counties in North Dakota that coincide with the FBIR are designated as 

unclassifiable/attainment for all criteria pollutants under the CAA. See 40 CFR § 81.335. 

Current air quality conditions in the region of the FBIR and in western North Dakota are good, 

with measured ambient ozone20 and nitrogen dioxide (NO2) concentrations substantially lower than the 

current National Ambient Air Quality Standards (NAAQS) of 75 parts per billion (ppb) for 8-hour 

average ozone and 100 ppb for the 1-hour average NO2. The state of North Dakota operates three air 

quality monitor sites in western North Dakota to characterize regional background air quality. At the

Dunn Center monitoring site located, approximately 20 miles southwest of the of the FBIR, the current 

design values for the ozone and NO2 NAAQS are 55 ppb and 11 ppb, respectively. 

We evaluated the impacts of changes in VOC and nitrogen oxides (NOx) emissions from 

enclosed combustors and flares used for control of VOC emissions at oil and natural gas production 

facilities on the FBIR as part of the technical analysis for this rule. Emissions categories that are

substantially controlled by this rule include VOC and NOx. 

 

20

 VOC and NOx are precursors to ozone. 
31 

Expected potential emissions of sulfur dioxide (SO2) and particulate matter (PM) pollutants from 

enclosed combustors and flares used for control of VOC emissions at well pads are estimated to be 

below the Federal Tribal NSR rule permitting thresholds, and are therefore expected to have 

insignificant impacts on the NAAQS for these pollutants. Expected potential emissions of carbon 

monoxide (CO) from enclosed combustors and flares used for control of VOC emissions at well pads are 

expected to have an insignificant impact on the CO NAAQS because of the level and form of the CO 

standard in comparison to the emissions. 

This rule establishes legally and practicably enforceable VOC emission reductions that reflect 

reductions that facilities are already routinely achieving through the installation and operation of control 

equipment for health, safety and market purposes. In addition, this rule does not exempt these facilities 

from other potentially applicable regulatory or permitting requirements. Therefore, we believe that air 

quality in this area will not be adversely impacted by this action. 

Supporting air quality information is discussed in the Technical Support Document for this rule, 

found in the rule docket. 

I. Benefits and Costs 

 Produced natural gas and natural gas emissions resulting from oil and natural gas production 

from the Bakken Pool underlying the FBIR have a high VOC content. Typically, the natural gases 

associated with the produced oil would be captured as product and injected directly into a natural gas

sales pipeline. However, this is a relatively new field and while the natural gas sales pipelines are being 

developed, they are minimally available at this time. Currently, most produced natural gas and natural 

gas emissions from oil and natural gas production operations on the FBIR are routed to a combustion 

device such as a pit flare, utility flare, or enclosed combustor. 
32 

 Uncontrolled emissions of VOC from operations at an oil and natural gas production facility 

consisting of a single well and associated production and storage operations were estimated to average

approximately 2,165 tons per year (tpy). Of this total, approximately 1,610 tpy of VOC results from 

produced natural gas emissions from the heater-treater and 555 tpy of VOC is emitted from the produced

oil and water storage tanks. This rule requires that emissions from the heater-treater and the storage 

tanks be routed to a combustion device. We estimate that, on average, the control requirements in this 

rule will reduce VOC emissions from an oil and natural gas production facility by approximately 2,090 

tpy per well.21

 The costs of the control equipment required by this rule depend, in part, on the number of wells 

associated with each oil and natural gas production facility. Generally, as the number of wells located at 

oil and natural gas production facilities increase, the volume of oil and natural gas production and 

associated emissions also increase. Multiple wells at an oil and natural gas production facility can often 

share control equipment if there is sufficient capacity to handle the additional produced natural gas and 

natural gas emissions; thus, the costs of the control equipment per well potentially decreases at oil and 

natural gas production facilities that consist of multiple wells. The Bureau of Land Management (BLM)

has estimated that future development in the area of North Dakota encompassing the FBIR is likely to 

feature an average of 1.5 wells per facility.22 Based on information from synthetic minor permit 

applications and environmental assessments conducted by the Bureau of Indian Affairs23, we believe a 

 

21 The Technical Support Document includes a more detailed explanation of benefits and costs. It can be found in the docket 

for the interim final rule, Docket ID: EPA-R08-OAR-2012-0479, which can be accessed at: http://www.regulations.gov

(hereinafter referred to as TSD). 

22 October 2, 2009 Bureau of Land Management (BLM) report titled “Reasonable Foreseeable Development Scenario for 

Oil and Gas Activities on Bureau managed Lands in the North Dakota Study Area”. This report was supplemented on 

February 25, 2011 with the document titled “Revised Activity and Surface Disturbance Projections for the Reasonable 

Foreseeable Development Scenario for Oil and Gas Activities on Bureau Managed Lands in the North Dakota Study Area”. 

Both documents are included in the docket for this rule and are publicly available at the following website: 

http://www.blm.gov/mt/st/en/fo/north_dakota_field/rmp/RFD.html. 

23See TSD at Section 4. Reasonably Foreseeable Development 
33 

value of two wells per facility provides a conservative estimate of well density for future development 

on the FBIR. 

 We calculated the total annual cost for a two-well facility utilizing a pit flare, utility flare, and

two enclosed combustors as control equipment. For this operating scenario, we have estimated that the

total annual cost of compliance with this rule would be approximately $52,000 per facility. Using the

estimated average of 4,180 tpy VOC reduction from a facility consisting of two wells and associated 

production and storage operations, we calculated the cost effectiveness of this rule as less than $15 per 

ton VOC reduced. 

 Based on the reasonably foreseeable development in the 2011 BLM supplemental report, we 

estimate that a maximum of 1,000 facilities may be developed on the FBIR by 2029. Applying a 

maximum total annual cost impact for a two-well facility of approximately $52,000, 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 technical support document for this rule. 

IV.The Fort Berthold Indian Reservation

The Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nations are a federallyrecognized Indian tribe organized under a Constitution and By-Laws ratified by the Tribes on May 15, 

1936 and approved by the Secretary of the Interior on June 29, 1936 (with relevant amendments to the 

Constitution and By-Laws approved by the Department of the Interior on March 11, 1985). See 75 FR 

60813 (October 1, 2010); Constitution and By-Laws of the Three Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nations. The FBIR was established pursuant to the Treaty of Fort Laramie of 1851
34 

and addressed in subsequent agreements and Executive Orders, including the Agreement at Fort 

Berthold, 1866, and Executive Orders in 1868, 1870 and 1880. As described in the Tribes’ Constitution

and By-Laws (and as approved by the Secretary of the Interior), the FBIR currently includes all lands 

within the exterior boundaries of the 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. 

Pursuant to CAA section 301(d), 42 U.S.C. § 7601(d), we are authorized to treat eligible Indian 

tribes in the same manner as states (TAS) for purposes of implementing CAA provisions over their 

entire Reservation and over any other areas within their jurisdiction. See 63 FR 7254-57 (February 12, 

1998) (explaining that CAA section 301(d) includes a delegation of authority from Congress to eligible

Indian tribes to implement CAA programs over all air resources within the exterior boundaries of their

Reservations). The Three Affiliated Tribes have not applied for TAS for the purpose of administering a 

Tribal Implementation Plan (TIP) under the CAA. There is thus currently no EPA-approved plan 

implementing the functions and provisions of this FIP on the FBIR. The FIP the EPA is promulgating 

today fills this regulatory gap 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, 1892. 

V. EPA’s Authority to Promulgate a FIP

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, 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 §§ 
35 

49.3, 49.4. Among those provisions for which we determined such treatment was inappropriate are 

CAA § 110(a)(1) (State Implementation Plan (SIP) submittal and implementation deadlines) and CAA § 

110(c)(1) (directing 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 at 7262-66 

(February 12, 1998). 

The TAR preamble clarified that by including CAA 110(c)(1) on the section 49.4 list, “EPA is 

not relieved of its general obligation under the CAA to ensure the protection of air quality throughout 

the nation, including throughout Indian country. In the absence of an express statutory requirement, 

EPA may act to protect air quality pursuant to its “gap-filling” authority under the Act as a whole. See,

e.g. CAA section 301(a)." 63 FR at 7265 (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 section 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).24

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 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

 

24

 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). 
36 

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 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 FIP specifically covering the reduction of VOC 

emissions related to natural gas emissions from oil and natural gas production facilities on the FBIR, a 

regulatory gap exists with regard to such facilities operating within the exterior boundaries of the 

Reservation. This FIP will establish 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 the 

FBIR. 

VI. Summary of FIP Provisions 

A. Applicability 

This rule applies to oil and natural gas facilities producing from the Bakken Pool that are 

constructed and operating on the FBIR in North Dakota on or after August 12, 2007. Specifically, this

rule applies to facilities on the FBIR within the Crude Petroleum and Natural Gas Extraction Industry,

North American Industry Classification System (NAICS) Code 211111. 

B. Compliance Schedule 

Compliance with the rule is required no later than [INSERT DATE 90 DAYS AFTER DATE 

OF PUBLICATION IN THE FEDERAL REGISTER] or upon initiation of 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
37 

and the Tribes.

C. Provisions for Delegation of Administration to the Tribes 

The provisions in § 49.141 establish the steps by which the Three Affiliated Tribes may request 

delegation to assist us with the administration of this rule and the process by which the Regional 

Administrator of 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 

Tribes. 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 would not need to seek TAS under the TAR for purposes of requesting to assist us with 

administration of this rule through a delegation of authority agreement. In the event such an agreement 

is reached, the rule would continue to operate under federal authority throughout the FBIR, and the 

Tribes would assist us with administration of the rule to the extent specified in the agreement.

D. General Provisions 

The provisions in § 49.142 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
38 

had been performed.

E. Construction and Operational Control Measures. 

The provisions in § 49.143 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 percent. 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 

would be allowed under this rule. Owners and operators may also choose to perform reduced emission 

completions and recompletions25, which would exceed the 90.0 percent VOC emission reduction 

requirement. This section also requires the control of production and storage operations and imposes a 

timeline for installation of the controls on these operations. The owner or operator is required to reduce 

the mass content of VOC emissions from natural gas during oil and natural gas production and storage 

operations by at least 90.0 percent on the first date of production. Within ninety (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 

percent. 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 

 

25 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. 
39 

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 an emergency

standby unit used for unplanned flare events such as temporarily limited pipeline capacity, equipment 

breakdown and/or other upsets 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 use of the pit flare in these instances to 500 

hours of operation in any consecutive 12-month period. This limit on the hours of operation of the pit 

flare in such situations provides a balance of air quality, safety and environmental protection, to address 

public concerns expressed on the proposed synthetic minor NSR permits with the use of pit flares, and 

flexibility for the operators, to address claims that continuous injection into a natural gas sales pipeline 

may not be possible at all times. 

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 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 percent. We note that while NSPS 

OOOO requires 95% VOC reduction of emissions from storage tanks, owners and operators of oil and 

natural gas production facilities on the FBIR have indicated that a 98% VOC destruction efficiency in 

the Bakken Pool Guidance 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 

storage tank control by at least 98.0% by weight. Since oil and natural gas production on the FBIR has higher 
40 

VOC content than typical natural gas production and the overall BTU value is generally higher, this should result 

in more efficient VOC destruction. Therefore, we believe that a requirement of 98.0 % reduction of VOC

emissions during continued production operations is appropriate. 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, like the Bakken Pool Guidance, 

the rule provides that if the uncontrolled PTE 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 percent upon written approval by the EPA.26

 

The requirements to use pit flares, enclosed combustors, and utility flares are based on 

requirements in the North Dakota Rules at Chapters 33-15-07 and 33-15-20, and the Bakken Pool 

Guidance. These control devices must be operated under specific conditions as specified in § 49.144 

Control Equipment Requirements and § 49.145 Monitoring Requirements. The VOC destruction 

efficiencies of 90.0 and 98.0 percent are the same efficiencies required in the Bakken Pool Guidance.27 

F. Control Equipment Requirements 

 

26 If the owner or operator receives written approval for a new method, the owner or operator must calculate potential to emit 

based on the new EPA-approved method. 

27 Based on our consultation with the owners and operators producing from the Bakken Pool, in addition to these particular 

provisions we also identified for regulating emissions from well completions and recompletions. These control operations 

are already being performed during these operations for product recovery or safety purposes. These consultations, provided 

us not only with information on the production practices occurring both on and off the Reservation, but it also provided us 

with information on the existing phased approach to controlling emissions from well completion and recompletions, through 

production operations, and ending with storage and loading operations and an appropriate timeline for installation of the 

controls. Those components in this section are based on these practices that are already in place.
41 

The provisions in § 49.144 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. These requirements are derived from the North Dakota Rules at Chapter 33-15-07. 

Section 49.144 also specifies construction and operational requirements for the covers and closed-vent

systems. The construction and operational requirements of the covers and closed-vent systems are based 

on the NSPS OOOO requirements and are intended to provide legal and practical enforceability. In 

addition, § 49.144 requires specific construction and operational requirements of pit flares, enclosed

combustors, and utility flares. These requirements are derived from the Bakken Pool Guidance and have

been enhanced where necessary to provide legal and practical enforceability. 

The provisions in § 49.144 require that each owner and operator equip the openings on each 

produced oil storage tank and each produced water storage tank that is interconnected with produced oil 

storage tanks with a cover that ensures that natural gas emissions are efficiently routed through a closedvent system to a vapor recovery system an enclosed combustor, or a utility flare. Each cover and all 

openings on the cover (e.g., access hatches, sampling ports, and gauge wells) must form a continuous 

barrier over the entire surface area of the produced oil and produced water in the storage tank. Each

cover opening must be secured in a closed, sealed position (e.g., covered by a gasketed lid or cap) 

whenever material is in the tank on which the cover is installed except during those times when it is 

necessary to use an opening as follows: 1) to add material to, or remove material from the unit (this 

includes openings necessary to equalize or balance the internal pressure of the unit following changes in 

the level of the material in the unit); or 2) to inspect or sample the material in the unit; or to inspect, 

maintain, repair, or replace equipment located inside the unit. These requirements are consistent with 

the requirements for storage tanks under NSPS OOOO and will ensure that the requirements apply to 

any storage tanks that are not subject to NSPS OOOO.
42 

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. These requirements are consistent with the 

requirements for storage tanks under NSPS OOOO and will ensure that the requirements apply to any 

storage tanks that are not subject to NSPS OOOO. 

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 percent for 

the minimum and maximum natural gas volumetric flow rate and British Thermal Unit (BTU) content 

routed to it. We note that the NSPS OOOO requires owners and operators to demonstrate that enclosed 

combustors and utility flares achieve the required VOC reduction by conducting performance tests. 

Those units that have been tested by the manufacturer in accordance with specific requirements in the 

rule, or that that are designed and operated in accordance with applicable requirements in 40 CFR Part
43 

60.18(b), satisfy the requirements of performance testing by the owner or operator. For the purposes of 

this rule, we require that all utility flares installed per this rule meet the requirements in 40 CFR Part 

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. This was discussed in great detail in the preamble and technical 

support documents to the proposed and final NSPS OOOO15. Therefore, each owner or operator must 

ensure that each enclosed combustor or utility flare is: 1) operated at all times that natural gas is 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 and thermocouple, or equipped with an electronically controlled 

automatic ignition system; 5) equipped with a malfunction alarm and remote notification system to 

detect if the pilot flame fails while natural gas is being routed through the device; 6) equipped with a 

continuous recording device, such as a chart recorder, data logger or similar device, or connected to a 

Supervisory Control and Data Acquisition (SCADA) system, to monitor and document proper operation 

of the enclosed combustor or utility flare; 7) maintained in a leak free condition; and 8) operated with no 

visible smoke emissions. These requirements are consistent with Bakken Pool Guidance.

§ 49.144 requires that each owner or operator limit the use of pit flares to: the control natural gas

emissions during well completion operations; the control VOC emissions in the event the natural gas 
44 

that is being recovered for sale or other beneficial purpose must be diverted to an emergency control 

device because injection into the pipeline is temporarily infeasible and the enclosed combustor or utility 

flare installed at the oil and natural gas production facility is not operational; or use when total 

uncontrolled PTE 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 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 percent and must be operated with no visible smoke emissions.28 Each pit flare must be 

equipped with an electronically controlled automatic ignition system 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 automatic ignition system must be repaired or replaced before the pit flare is used 

again. 

As North Dakota has done in the Bakken Pool Guidance, § 49.144 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 percent VOC destruction efficiency and 

upon our written approval. 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. 

G. Monitoring Requirements 

Section 49.145 Monitoring Requirements requires each owner or operator conduct certain 

 

28 Owners and operators of oil and natural gas production facilities on the FBIR have indicated that a 90.0 % VOC 

destruction efficiency in the Bakken Pool Guidance is achievable using a pit flare and committed in their synthetic minor 

NSR applications to reduce the mass content of VOC emissions routed to a pit flare by at least 90.0% by weight. 
45 

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 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 an emergency control device because injection into the 

pipeline is temporarily infeasible and the enclosed combustor or utility flare installed at the oil and 

natural gas production facility is not operational; (2) Monitoring of the number of barrels of oil produced 

at the facility each time the oil is unloaded from the produced oil storage tanks; (3) Monitoring of the 

volume of 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) Directly measuring, or calculating using EPA approved models, 

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 (6) Visibility monitoring for 

detecting visible smoke from enclosed combustors, utility flares, and pit flares. 

These requirements are derived from the Bakken Pool Guidance in conjunction with NSPS 

OOOO. The monitoring, recordkeeping and reporting requirements for the covers, close-vent systems, 

pit flares, enclosed combustors, and utility flares are based, in part, on the requirements in the Bakken 

Pool Guidance. Specifically, our review and determination that these requirements are appropriate, as

well as the Bakken Pool Guidance provides the basis for monitoring the flares and enclosed 

combustors. The monitoring of the covers and closed-vent systems, in addition to the recordkeeping and 

reporting requirements are based on the NSPS OOOO requirements for these units and are intended to 

provide legal and practical enforceability. 
46 

H. Record Keeping Requirements 

Section 49.146 Record Keeping 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 

record keeping requirements were derived independently of the North Dakota Rules and Bakken Pool 

Guidance and provide legal and practical enforceability to the control and emission reduction 

requirements of this rule.

I. Reporting Requirements 

Section 49.147 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 the FIP and the corrective measures taken. Additionally, a report must be submitted for any 

performance test we require. 

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 were derived independently of the North Dakota Rules and Bakken 
47 

Pool Guidance and provide legal and practical enforceability to the control and emission reduction 

requirements of this rule.

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 

This action does not impose an information collection burden under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. Burden is defined at 5 CFR 1320.3(b). 

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 today's 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. 
48 

 After considering the economic impacts of today’s interim 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 USC 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. We continue to be interested in the potential impacts of this rule on small 

entities and welcome comments on issues related to such impacts. 

D. Unfunded Mandates Reform Act (UMRA) 

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes 

requirements for federal agencies to assess the effects of their regulatory actions on State, local, and 

Tribal governments and the private sector. Under section 202 of UMRA, EPA generally must prepare a 

written statement, including a cost-benefit analysis, for proposed and final rules with “Federal 

mandates” that may result in expenditures to State, local, and Tribal governments, in the aggregate, or to 

the private sector, of $100 million or more (adjusted for inflation) in any one year. Before promulgating 

an EPA rule for which a written statement is needed, Section 205 of UMRA generally requires us to 

identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most 

cost-effective, or least burdensome alternative that achieves the objectives of the rule. The provisions of 
49 

Section 205 of UMRA do not apply when they are inconsistent with applicable law. Moreover, Section 

205 of UMRA allows us to adopt an alternative other than the least costly, most cost-effective, or least 

burdensome alternative if the Administrator publishes with the final rule an explanation why that 

alternative was not adopted. Before we establish any regulatory requirements that may significantly or 

uniquely affect small governments, including Tribal governments, it must have developed under Section 

203 of UMRA a small government agency plan. The plan must provide for notifying potentially 

affected small governments, enabling officials of affected small governments to have meaningful and 

timely input in the development of EPA regulatory proposals with significant federal intergovernmental

mandates, and informing, educating, and advising small governments on compliance with the regulatory 

requirements. 

Under Title II of UMRA, we determined that this rule does not contain a federal mandate that 

may result in expenditures that exceed the inflation-adjusted UMRA threshold of $100 million by State,

local, or Tribal governments or the private sector in any one year. In addition, this rule does not contain 

a significant federal intergovernmental mandate as described by section 203 of UMRA nor does it 

contain any regulatory requirements that might significantly or uniquely affect small governments. 

E. Executive Order 13132: Federalism 

Federalism (64 FR 43255, August 10, 1999) revokes and replaces Executive Orders 12612 

(Federalism) and 12875 (Enhancing the Intergovernmental Partnership). Executive Order 13132 

requires EPA to develop an accountable process to ensure “meaningful and timely input by State and 

local officials in the development of regulatory policies that have federalism implications.” “Policies 

that have federalism implications” is defined in the Executive Order to include regulations that 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.” 
50 

Under Executive Order 13132, we may not issue a regulation that has federalism 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 State and local

governments, or we consult with State and local officials early in the process of developing regulations. 

We also may not issue a regulation that has federalism implications and that preempts State law unless

the Agency consults with State and local officials early in the process of developing regulations. 

This rule 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, because it 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. In the spirit of 

Executive Order 13132, and consistent with EPA policy to promote communications between us and 

State and local governments, we specifically solicit comment on this rule 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 
51 

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 filling a gap in air quality regulations and thus creating a level of 

air quality protection not previously provided under the CAA. The gap-filling approach used in this rule 

would create Federal requirements similar to those that are already in place areas adjacent to the 

Reservation covered by the proposal. 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 Nations 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 permits being issued on the Reservation under the Tribal NSR Rule. Then, on 

March 29, 2012, EPA senior management and the Chairman of the Tribes 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 the FIP in a letter dated April 10, 2012 to Chairman Tex Hall, of the 
52 

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 the 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 EPA’s efforts to develop the 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. EPA solicited the Tribes’ 

input on the FIP development. The Council members present at the consultation meeting indicated that 

they strongly desired the FIP rule 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 Tribe. The Council members expressed 

interest in the future delegation of the FIP so that the Tribes can implement the rule in place of EPA. 

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 Nations have 

indicated preliminary interest in seeking administrative delegation of the Tribal NSR rule to assist us 

with administration of that rule. We will continue to work with the Tribes 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 proposed rule, EPA specifically solicits additional comments on the 

proposed action from tribal officials. 
53 

G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety 

Risks 

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 it 

implements specific standards established by Congress in statutes. In addition, this rule requires control 

and reduction of emissions of VOCs, which 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 No. 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 are not considering the use 

of any voluntary consensus standards. 
54 

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 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 is in compliance 

with the National Ambient Air Quality Standards and provides environmental protection for all affected

populations including any minority, low income, and indigenous populations. 

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. Section 808 allows the issuing agency to

make a rule effective sooner than otherwise provided by the CRA if the agency makes a good cause 

finding that notice and public procedure is impracticable, unnecessary or contrary to the public interest. 

This determination must be supported by a brief statement. 5 U.S.C. 808(2). As stated previously, EPA 

has made such a good cause finding, including the reasons therefore, and the rule is effective in the CFR 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. This rule is effective with 

actual notice for purposes of enforcement beginning at 5 p.m. (eastern daylight time) on August 3, 2012. 

56 

40 CFR part 49 is amended as follows: 

PART 49--[AMENDED] 

1. The authority citation for part 49 continues to read as follows: 

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

Subpart C – General Federal Implementation Plan Provisions 

Part 49-INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT 

2. Add §§ 49.140 through 49.147 and an undesignated heading to appear immediately before the newly 

added § 49.140 to read as follows: 

Federal Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian 

Reservation (Mandan, Hidatsa and Arikara Nations) in EPA Region 8.

§ 49.140 Introduction 

(a) What is the purpose of this rule? This rule establishes 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 this rule?

This rule applies to each owner or operator constructing or operating an oil and natural gas production 

facility 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”). 

(c) When must I comply with this rule? Compliance Dates. Compliance with the rule is required no 
57 

later than [INSERT DATE 90 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] or upon initiation of completion or recompletion operations, whichever is later. 

§ 49.141 Delegation of Authority of Administration to the Tribes 

(a) What is the purpose of this provision? The purpose of this provision is to establish the process by 

which the Regional Administrator may delegate to the Mandan, Hidatsa and Arikara Nations 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 Nations 

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 Nations’ legal counsel (or equivalent 

official) that includes the following information: 

(i) A statement that the Mandan, Hidatsa and Arikara Nations are an Indian Tribe recognized by the 

Secretary of the Interior; 

(ii) A descriptive statement demonstrating that the Mandan, Hidatsa and Arikara Nations 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 Nations 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 Nations have, or will have, adequate resources 

to carry out the aspects of the rule for which delegation is requested. 
58 

(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 Nations 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 Nations. The Agreement will become effective upon the date that both the 

Regional Administrator and the authorized representative of the Mandan, Hidatsa and Arikara Nations 

have signed the Agreement. Once the delegation becomes effective, the Mandan, Hidatsa and Arikara 

Nations will be responsible, to the extent specified in the Agreement, for assisting us with administration 

of the 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 the FIP is to remain the EPA Regional Administrator and when it is 

intended to refer to the “Mandan, Hidatsa and Arikara Nations,'' 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 Nations. 

(d) How will any delegation of authority agreement be publicized? 

(1) 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 Nations to assist us with 

administration of all or a portion of the FIP and will identify such delegation in the FIP. The Regional 

Administrator shall also publish an announcement of the delegation of authority agreement in local 

newspapers. 

§ 49.142 General Provisions 

(a) Definitions. As used in this rule, 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 
59 

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 hardpiping, 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 Production Facilities, 

Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)''. 

(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. 
60 

(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 Production Facilities, Fort 

Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)''. 

(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. 
61 

(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. 
62 

(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 this rule 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 Production Facilities, Fort Berthold Indian Reservation 

(Mandan, Hidatsa and Arikara Nations)'' 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 

Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' limits 

the authority of the Regional Administrator to require, in an information request pursuant to section 114 
63 

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 Nations)'' 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 Nations)'' 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 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 Production Facilities, Fort 

Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' 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. 

§ 49.143 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 
64 

flare capable of reducing the mass content of VOC in the natural gas emissions vented to it by at least 

90.0 percent or greater and operated as specified in § 49.144 and § 49.145. 

(c) Beginning with the first date of production from any one oil and natural gas well at an oil and 

natural gas production facility, each owner or operator must, at a minimum, route all natural gas 

emissions from production operations and storage operations to a control device capable of reducing the 

mass content of VOC in the natural gas emissions vented to it by at least 90.0 percent or greater and 

operated as specified in § 49.144 and § 49.145. 

(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) An utility flare or equivalent combustion device capable of reducing the mass content of VOC in the 

produced natural gas vented to the device by at least 98.0 percent or greater and operated as specified in 

§ 49.144 and § 49.145. 

(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 closedvent system to: 

(i) An operating system designed to recover and inject the natural gas emissions into a natural gas 

gathering pipeline system for sale or other beneficial purpose; or 

(ii) An enclosed combustor or utility flare capable of reducing the mass content of VOC in the natural 

gas emissions vented to the device by at least 98.0 percent or greater and operated as specified in § 

49.144(c) and § 49.145. 
65 

(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 written approval by the EPA the owner or operator may use a pit flare, an 

enclosed combustor or a utility flare that is capable of reducing the mass content of VOC in the natural 

gas emissions from the storage tanks vented to the device by only 90.0 percent. 

(e) In the event that pipeline injection of all or part of the natural gas collected in an operating system 

designed to recover and inject natural gas becomes temporarily infeasible and there is no operational 

enclosed combustor or utility flare at the facility, the owner or operator must route the natural gas that 

cannot be injected through a closed-vent system to a pit flare operated as specified in § 49.144 and §

49.145. 

 (f) Produced oil storage tanks and any produced water storage tanks interconnected with produced oil

storage tanks subject to and controlled under the requirements specified in 40 CFR Part 60, Subpart 

OOOO are considered to meet the requirements of § 49.143(d)(2). No further requirements apply for 

such storage tanks under § 49.143(d)(2). 

§ 49.144 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. 
66 

(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 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: 
67 

(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 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. 

(5) The owner or operator must ensure that each enclosed combustor is: 
68 

(A) A model demonstrated by a manufacturer to the meet the VOC destruction efficiency requirements 

of this rule using the procedure specified in 40 CFR Part 60, Subpart OOOO at § 60.5413(d) by the due 

date of the first annual report as specified in § 49.147(b); or 

(B) Demonstrated to meet the VOC destruction efficiency requirements of this rule using EPA 

approved performance test methods specified in 40 CFR Part 60, Subpart OOOO at § 60.5413(b) by the 

due date of the first annual report as specified in § 49.147(b); or 

(C) Until such time that 40 CFR Part 60, Subpart OOOO is promulgated, demonstrated to meet the 

VOC destruction efficiency requirements of this rule by using the EPA approved performance test 

methods specified in 40 CFR Part 63, Subpart HH at § 63.772 (e)(i) – (iii) for hazardous air pollutants, 

by the due date of the first annual report as specified in § 49.147(b). 

(6) The owner or operator must ensure that each enclosed combustor and utility flare is: 

(i) Operated properly at all times that natural gas is 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, a thermocouple, and a malfunction alarm and remote notification

system if the pilot flame fails. 

(B) An electronically controlled auto-ignition system with a malfunction alarm and remote notification 

system if the pilot flame fails while produced natural gas or natural gas emissions are flowing to the

enclosed combustor or utility flare; 

(v) Equipped with a continuous recording device, such as a chart recorder, data logger or similar device, 

or connected to a Supervisory Control and Data Acquisition (SCADA) system, to monitor and document 
69 

proper operation of the enclosed combustor or utility flare; 

(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 natural gas emissions in the event that natural gas recovered for pipeline injection must 

be diverted to an emergency control device because injection is temporarily infeasible and the enclosed 

combustor or utility flare installed at the oil and natural gas production facility is not operational. Use of 

the pit flare for this situation is limited to a maximum of 500 hours in any twelve (12) consecutive 

months during periods when pipeline injection has become temporarily infeasible and no enclosed 

combustor or utility flare installed at the facility is operational; 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 
70 

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 auto-ignition system with a malfunction 

alarm and remote notification system if the pilot flame fails; 

(v) The pit flare is visually inspected for the presence of a pilot flame anytime produced natural gas or 

natural gas emissions are being routed to it. Should the pilot flame fail, the flame must be relit as soon 

as safely possible and the electronically controlled auto-ignition system 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 written approval by the EPA, the owner or operator may use control 

devices other than those listed above that are 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. 
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(3) The owner or operator must operate such a control device to reduce the mass content of VOC in the 

produced natural gas and natural gas emissions routed to it by at least 98.0 percent. 

§ 49.145 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 US Department of the Interior’s Bureau of Land Management at 43 CFR 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 operated to control natural gas 

emissions in the event that natural gas recovered for pipeline injection must be diverted to an emergency 

control device because injection is temporarily infeasible and the enclosed combustor or utility flare

installed at the oil and natural gas production facility is not operational. 

(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 
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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 the enclosed combustor, utility flare, and pit flare operation, using a 

malfunction alarm and remote notification system for failures, and checking the system for proper 

operation whenever an operator is on site, at a minimum quarterly; 

(2) Continuously monitor all variable operational parameters specified in the written operating 

instructions and procedures; 

 (3) Using EPA Reference Method 22 of 40 CFR 60, Appendix A, confirm that no visible smoke 

emissions are present, except for periods not to exceed a total of 2 minutes during any hour, during 

operation of any enclosed combustor, utility flare, or pit flare whenever an operator is on site; at a

minimum quarterly. The observation period shall be 1 hour; and 

(4) Respond to any observation of improper monitoring equipment operation or any pilot flame failure 

alarm and ensure the monitoring equipment is returned to proper operation and/or the pilot flame is relit 

as soon as practicable and safely possible after an observation or an alarm sounds. 

(h) Where sufficient to meet the monitoring and record keeping requirements in § 49.145 and § 49.146,

the owner or operator may use a Supervisory Control and Data Acquisition (SCADA) system to monitor 

and record the required data in this rule. 
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§ 49.146 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) For each oil and natural gas well completion operation and recompletion operation at an oil and 

natural gas production facility: 

(i) Records identifying each oil and natural gas well completion operation and recompletion operation

for each oil and natural gas production facility; and 

(ii) The latitude and longitude location of the oil and natural gas well; the date, time, and duration of 

flowback from the oil and natural gas well; the date, time, and duration of any venting of produced 

natural gas from the oil and natural gas well; and specific reasons for each instance of venting in lieu of 

capture or combustion. The duration must be specified in hours. 

(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, 
74 

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 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 Paragraph 49.144(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 reason for each incident, its duration, and the corrective actions taken and any preventative measures 

adopted to avoid such bypasses or downtimes; and 

(8) Documentation of all produced oil storage tank and produced water storage tank inspections 

required in § 49.145(d) and (e). All inspection records must include, at a minimum, the following 
75 

information: 

(i) The date of the inspection; 

(ii) The findings of the inspection; 

(iii) Any adjustments or repairs made as a result of the inspections, and the date of the adjustment or 

repair; and 

(iv) The inspector's name and signature. 

(b) Each owner or operator must keep all records required by this section onsite at the facility or at the 

location that has day-to-day operational control over the facility and must make the records available to 

the EPA upon request. 

(c) Each owner or operator must retain all records required by this section for a period of at least five 

(5) years from the date the record was created. 

§ 49.147 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 r8airreport@epa.gov

(b) Each owner and operator must submit an annual report containing the information specified in § 

49.147(b)(1) through (4). The annual report must cover the period for the previous calendar year. The

initial annual report is due 1 year after the first date of production for the first oil and natural gas well at 

each oil and natural gas production facility or 1 year after [INSERT DATE OF PUBLICATION IN 
76 

THE FEDERAL REGISTER], whichever is later. Subsequent annual reports are due on the same date 

each year as the initial annual report. 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 § 49.147(b)(1) through (4). 

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 this rule 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 § 49.147(b)(4)(i) through (iii). 

(i) A summary of all required records identifying each oil and natural gas well completion or 

recompletion operation for each oil and natural gas production facility conducted during the reporting

period; 

(ii) An identification of the first date of production for each oil and natural gas well at each oil and 

natural gas production facility that commenced production during the reporting period; and 

(iii) A summary of cases where construction or operation was not performed in compliance with the 

requirements specified in § 49.143, § 49.144, or § 49.145 for each oil and natural gas well at each oil 

and natural gas production facility, and the corrective measures taken.