1

The EPA Administrator, Lisa Jackson, signed the fol lowing notice on 8/1/2012, and EPA is submitting it for publication in the Federal Register (FR). While we have taken steps to ensure the accuracy of this version of the rule, i t is not the official version of the rule for purposes of compliance. Please refe r to the official version in a forthcoming FR publi cation, 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 Reserva tion (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 Reserv ation-specific Federal Implementation Plan in order to regulate emissions from oil and na tural 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 commu nities in and adjacent to the Fort Berthold Indian Reservation. The Federal Implementation Plan requi res owners and operators of oil and natural gas production facilities to reduce emissions of volati le organic compounds emanating from well completions, recompletions, and production and stor age operations. This Federal Implementation Plan will be implemented by EPA, or a delegated Tribal A uthority, until replaced by a Tribal Implementation Plan. EPA is proposing a Reservation-specific Fede ral 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. (ea stern 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 da te: September 12, 2012. The2

hearing will start at 1:00 p.m. local time and cont inue until 4:00 p.m. or until everyone has had a ch ance to speak. Additionally, an evening session will be held from 6:00 p.m. until 8:00 p.m. The hearing w ill 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 c omments.

• 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. Env ironmental Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop Street, Denv er, Colorado 80202-1129. • Hand Delivery: Carl Daly, Director, Air Program, U.S. Environmental Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoo p Street, Denver, Colorado 80202-1129. Such deliveries are only accepted Mond ay through Friday, 8:00 a.m. to 4:30 p.m., excluding Federal holidays. Special arr angements 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 publi c docket without change and may be made available

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

includes information claimed to be Confidential Bus iness Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwi se 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 information3

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 capture d 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 difficult ies and cannot contact you for clarification, EPA may not be able to consider your comment. Electron ic 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 n ot publicly available, e.g., CBI or other informati on whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly-ava ilable docket materials are available either electronically in http://www.regulations.gov or in hard copy at the following locations: Air Pr ogram, U.S. Environmental Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop, Denver, Colorado 80202-1129; and Environmental Division, Th ree Affiliated Tribes, 204 West Main, New Town, North Dakota 58763-9404. EPA requests that i f at all possible, you contact the individuals list ed

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 thr ough 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, 159 5 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 mea ning 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 con text 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 Hea lth 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 P rotection 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 Environment al 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 Class ification System. (xv) The initials NDDoH mean or refer to the North Dakota Department of He alth.5

(xvi) The initials NDIC mean or refer to the North Dakota Industrial Commi ssion. (xvii) The initials NESHAP mean or refer to National Emission Standards for H azardous Air

Pollutants. (xviii) The initials NMED mean or refer to New Mexico Environment Department Air Quality Bureau. (xix) The initials NO x mean or refer to nitrogen oxides. (xx) The initials NO 2 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 Environmen tal 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 deterio ration. (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 Acqu isition. (xxix) The initials SIP mean or refer to State Implementation Plan. (xxx) The initials SO 2 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 Environment al 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 Faciliti es 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 Tribes7

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 Reservatio n-specific Federal Implementation Plan (FIP or rule) to establish enforceable control requireme nts for reducing volatile organic compound (VOC) emissions from oil and natural gas production activ ities on the Fort Berthold Indian Reservation (FBIR ) in North Dakota. Specifically, we are issuing this rule to require owners and operators of oil and na tural 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 i n Section III, promulgating these Federal regulations addresses an important initial step to fill a regu latory gap with regard to controlling VOC emissions from o il and natural gas operations on the FBIR. There i s no other federal rule, including the recently final ized New Source Performance Standard (NSPS) and

National Emission Standards for Hazardous Air Pollu tants (NESHAP) for the Oil and Gas Sector (NSPS OOOO and NESHAP HH), that fills this gap for the pa rticular geologic formations that exist on the FBIR. Therefore, this rule is necessary to level t he playing field, and provide the public on the FBI R 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 and8

natural gas operations off the Reservation are prov ided by North Dakota Department of Health (NDDoH) regulations and North Dakota Industrial Com mission (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 natur al 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. (easter n daylight time) on August 3, 2012. This interim

final rule is also time-limited. It will be effect ive only until the date that EPA promulgates a fina l rule based on its proposal for a Reservation-specific FI P 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 int erim final rule. As explained in detail below, EPA finds that compelling circumstances warrant the pro mulgation of this interim final rule.

An interim final rule is effective with actual noti ce 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 ag ency rule. However, this obligation is excused, under APA section 553(b)(3)(B), “when the agency fo r good cause finds (and incorporates the finding

and a brief statement of reasons therefore in the r ules issued) that notice and public procedure there on are impracticable, unnecessary, or contrary to the public interest.” While the good cause exception i s to

1 Depending on the emissions characteristics of a par ticular well, compliance with the requirements of t he FIP may or may not limit the well’s PTE to below the major source thresholds such that the well is not subject to maj or source prevention of significant (PSD) permitting and/or to national emi ssion standards for hazardous air pollutants (NESHA P) requirements.9

be narrowly construed, Utility Solid Waste Activiti es Group v. Environmental Protection Agency , 236 F.3d 749, 754 (D.C. Cir. 2001), it is also “an impo rtant 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 otherw ise required.” Utility Solid Waste Activities Grou p , 236 F.3d at 754. Notice and comment are contrary t o the public interest where “the interest of the pu blic would be defeated by any requirement of advance not ice.” 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 i mpracticable 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 brough t 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 n atural gas production operations on the FBIR informed EPA that the emissions of regulated air po llutants, including volatile organic compounds (VOCs), from oil and natural gas production facilit ies were significantly larger than they had previou sly understood. These emissions created a public healt h and safety hazard and were sufficiently large tha t hundreds of individual facilities would potentially be required to obtain major source PSD permits unless they were able to obtain legal and practicab ly 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 restric ted emissions from the oil and natural gas producti on10

facilities subject to those agreements to below maj or 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 p rocess to develop, propose and issue permits to the hundreds of sources on the FBIR (both existi ng and proposed new wells) and to develop a FIP. A t that time, EPA lacked detailed information to devel op permits (e.g., information about the facilities, emissions, and possible emission controls) and ther efore, hosted numerous meetings from August through November 2011 to collect the necessary info rmation and develop complete permit applications and draft permit language. 2 The EPA drafted and proposed the first batch of p ermits in March 2012 3

, and explained in our April 10, 2012 letter to Chair man Hall that “[t]he comment period for these permi ts will end on April 23, 2012, at which time we will c onsider comments and finalize these permits,” notin g that “these completed permits will form the basis f or the FIP.” While we had developed an example permit to provide predictability and a framework fo r 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 enormo us resources to resolve these challenges at the Regional and Nation al 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 an d enforcement programs hosted a Fort Berthold Oil P roduction Minor NSR Permitting Process Meeting with the oil produce rs. Representatives from the MHA Nation were invit ed and attended in person and by phone. Discussions included the anti cipated permitting timeline for permit applications submitted by the oil producers. Between August 23 and September 1, 201 1, 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 S eptember 1, 2011, Region 8 hosted a permitting workshop. Representat ives from the various oil producers and the MHA Nat ion were invited and attended. Representatives of the North Dakota Dept. of Health also participated by phone. The mi nor NSR permitting process was discussed, as well as questions that th e companies submitted ahead of time. The group beg an discussions on the draft model permit and set up a workshop specifical ly to delve into the specific permit conditions for the following week. On September 7 and 8, 2011, EPA hosted a two-day follo w-up permitting workshop. All previous meeting att endees were invited, including the MHA Nation. Participants in cluded the oil producers and their consultants. No rth Dakota Department of Health representatives were also on the phone. At this meeting the group went through the draft mo del permit and discussed the proposed conditions and appropriate e dits. Also discussed was what would constitute a c omplete application (administrative and technical) and the various meth ods of PTE calculation proposed by the companies in attendance. The EPA Region 8 hosted an additional meeting on Novemb er 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 an d comment period are available online at: http://www.epa.gov/region8/air/permitting/pubcommen t.html.11

expiration date of the CAFOs. However, in May 2012 , the true extent of the significant workload associated with developing and finalizing permits f or more than 600 existing and new oil and natural g as production facilities became apparent. It became c lear that, due to the extraordinary number of permi ts that needed to be issued, the need to tailor each o f those permits to comport with the information in the permit application and the short timeframe remainin g 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 issu ing the individual permits, but determined that promulgating the FIP should be our top priority onc e we realized that we could not issue all of the necessary permits in a timely manner. Key safety provisions of the interim final rule r equire either collection and high efficiency flaring (combustion) of coproduced natural gas or t hat the well(s) be connected to a natural gas gathering line so that coproduced natural gas can b e sold or used for another beneficial purpose. Giv en the accelerated development in this area and the na ture of the oil and gas extracted, these requiremen ts are necessary for both safety and protection of pub lic health from exposure to air pollution and will avoid fire hazards and protect the public from haza rdous conditions. Specifically, the requirements further a number of important goals in that regard. First, as discussed in Section III.C., VOC emissi ons from the natural gas that is co-produced with oil e xtracted from the formations are generally greater than such emissions from activities in other oil bearing formations, due to the characteristics of the prod uced oil. The FIP requirements for owners and operators of the oil and natural gas production facilities t o reduce emissions of VOCs emanating from well comple tions, recompletions and production and storage12

operations will significantly reduce VOC emissions thereby ensuring that public health and the environment are protected. Second, the rule will r esult 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, immedi ate application of the FIP requirements to both new and existing oil and natural gas operations is necessa ry to ensure that public health and the environment, c ontinue to be protected once consent agreement fina l 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 operatio ns (including modifications), and new operations, c an 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 wit hout first complying with major source prevention of significant deterioration (PSD) new source revie w (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 re quirements that are consistent with those in the rule adopted today, have been in place since August 2011 and will expire beginning on August 26,

2012 4 , a date which is rapidly approaching. In the abse nce 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 complia nce with CAA requirements without first obtaining a permit from EPA because they will have no legally a nd practicably enforceable requirements in place controlling VOC emissions, thus significantly disru pting 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 Re servation. 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 cur rent CAA obligations that currently apply to these wells. While many sources would first need to obta in 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) wh ile those without permitting obligations would operate uncontrolled as the interim final rule requ irements 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 PT E. 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 d elay in its ability to continue to operate, constru ct or modify. The public interest would certainly be hin dered if EPA did not act now to ensure that these important public health protections are in place an d that economic progress is not impeded by a lack o f regulations controlling VOC emissions. Finally, this rule is important in that while not i dentical to, the rule is consistent with regulation s approved into North Dakota’s SIP 5 under the authority of the NDDoH and regulations u nder the

5 North Dakota Century Code (NDCC) (Chapter 23-25 Air Pollution Control); Air Pollution Control Rules (A rticle 33-15) Chapter 33-15-07 Control of Organic Compound Emissi ons, and Chapter 33-15-20-04 Control of Emissions f rom Oil and Gas Well Production Facilities. North Dakota Legisl ative Branch. Available online at: http://www.legis.nd.gov/information/acdata/html/33- 15.html. Accessed May 29, 2012. Within EPA approve d SIP.14

authority of the NDIC 6 , which were established for similar purposes. Acc ordingly, this rule ensures that consistent requirements apply to activities both in side of and within the FBIR. The good cause exception also applies here becau se of the impracticability of notice and comment. EPA initially did not recognize the sheer magnitude of the volume of permit applications tha t 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 time ly process more than 600 permit applications, specifie d 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 c omment before acting on the rule promulgated today.

While we have determined that notice and comment a re both contrary to the public interest and impracticable, we note that the public has had seve ral 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 an d we have taken those comments into consideration in developing the FIP requirements. The substantiv e requirements of the FIP are also similar to the

conditions in the CAFOs under which the oil and nat ural gas production sources have been operating for nearly a year, and the public had notice of the CAF Os, which were posted on EPA’s Internet site for public review. 7 Furthermore, the public has an additional, full o pportunity to comment on the permanent rule that EPA is concurrently proposing t oday, which mirrors, and will replace this interim

6 NDCC (Chapter 38-08 Control of Oil and Gas Resource s); 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 Regulatio n. Available online at: https://www.dmr.nd.gov/oilgas/rules/rulebook.pd f. 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 rul e, paired with a comment period on the proposal for more permanent action, EPA is providing as much opportun ity for notice and comment as possible on the issues presented by this rule. EPA will expeditiou sly and fully, consider any comments received on th e proposed rule, and once we have completed our delib erative process, will make any necessary revisions in taking final action on the proposed rule. For the reasons discussed above, EPA finds both tha t there is good cause to forego notice and comment for this interim rule, and that there is go od 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 enforcem ent. Since this is not a major rule under the Congressio nal Review Act (CRA), the 60-day delay in effective date required for major rules under the CRA does no t apply.

II. Proposed Rulemaking We are also simultaneously publishing a parallel pr oposed 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 t he parallel proposed rule.

III. Background

A. Today’s Action In today’s action, we are promulgating a Reservatio n-specific FIP to establish enforceable control requirements for reducing VOC emissions fro m 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 a nd natural gas production facilities producing from th e Bakken Pool 8 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 cru de 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, th ose types of equipment. If we determine at a later date that there is a need for legally and practicab ly enforceable control of VOC emissions from additional equipment at these oil and natural gas p roduction facilities, or for legally and practicabl y enforceable control of additional regulated NSR pol lutant emissions, we may propose additional FIPs or propose supplements to this FIP.

B. Purpose of the Rule As noted above, promulgating these Federal regulati ons addresses an important initial step to fill a regulatory gap with regard to controlling VOC emi ssions from oil and natural gas operations on the FBIR. There is no other federal rule, including th e 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 cont rast to oil and natural gas operations off the Reservation which are governed by the NDDoH regulat ions and NDIC regulations previously discussed. As a result of these regulations, oil and natural g as operators in NDDoH jurisdiction are provided mechanisms for establishing legally and practicabl y 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 tha t 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 approac h 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 prom ulgated and can be found at http://www.epa.gov/airquality/oilan dgas/actions.html, until such time that the final r ule 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 Pollutio n Control Rules (“North Dakota Rules”) at Chapter 33-15-14 (Designated Air Contaminant Sources, Permi t to Construct, Minor Source Permit to Operate, Title V Permit to Operate) and Chapter 33-15-15 (Pr evention 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 Rules for the operation of oil and natural gas production operations in the State of North Dakota. The regulations found at Chapter 33-15-07 (Contro l of Organic Compound Emissions) provide legally and practicably enforceable control requirements and VOC emission reductions when applicable. Additiona lly, 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 (Bakk en Pool Guidance) 10 do not have to obtain preconstruction permits from the NDDoH and can begi n construction in a timelier manner. Similar to the owners and operators of oil and natu ral gas operations producing from the Bakken Pool in NDDoH jurisdiction, the owners and operator s 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 5 2.21 (Prevention of Significant Deterioration of Ai r 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 practic ably 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 sto rage tanks being utilized in the Bakken Pool

10 Bakken Pool Oil and Gas Production Facilities Air P ollution Control Permitting & Compliance Guidance , NDDoH Air Quality Division, May 2, 2011. This guidance docume nt was developed by the Bakken VOC Task Force. The Bakken VOC Task Force was a collaboration between the NDDoH an d the owners and operators of oil and gas operation s 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 pro duction can begin, or if they are not obligated to obtain a permit face no control obligations whatsoe ver. This rule will fill this regulatory gap. Consisten t 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 th e extent practicable, minimize the construction permitting program implementation burdens upon us a nd the regulated community while establishing requirements that are unambiguous and legally and p racticably enforceable. However, this rule will not eliminate any potential permitting requirements for oil and natural gas production facilities, but in many cases it wil l impose legally and practicably enforceable requirements that will lower PTE to a level that wi ll allow the operators to construct without being required to obtain a PSD or federal preconstruction permit under the Federal Tribal NSR Rule for India n country. Specifically, where compliance with the r equirements 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 Federa l Tribal NSR rules, the source would not trigger perm itting requirements and therefore may avoid PSD and minor source preconstruction permitting altoget her. 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 veri fy that it is less than the threshold in the PSD an d

Federal Tribal NSR rules. While we believe that VO C is the pollutant most likely to be emitted in quantities sufficient to require permitting, the fa cility may not avoid the PSD and Federal Tribal NSR permitting requirements if its emissions of any oth er regulated NSR pollutant are high enough to trigg er 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 Thr ee Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation. As part of this consultation w e evaluated the oil and natural gas activities and sources of VOC emissions that could impact air reso urces on the Reservation and the differences in the VOC emission reduction requirements for those facil ities operating on the FBIR compared to those facilities operating in NDDoH jurisdiction. We als o held a meeting with the Three Affiliated Tribes o f 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 sign ificant 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 Pool 11

. In order to develop appropriate requirements for th e control of emissions from the production operations in the Bakken Pool, we studied the natur e 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 reservo ir has a combination of chemical and physical quali ties which makes it unique. Some crude oil types are 'h eavy' (high viscosity and gravity containing very little associated natural gas) and some 'light' (lo w viscosity and gravity containing high amounts of associated natural gas). The crude oil from the Ba kken Pool is a light crude oil. It contains a high er

11 The information reviewed was contained in syntheti c minor NSR applications submitted to EPA, which ar e included in the docket for this rule.20

amount of lighter hydrocarbon components than is se en in heavy crude oil, and therefore has greater potential to produce natural gas in addition to oil . Because of this characteristic, the production o f crude oil from the Bakken Pool wells is similar to the pr oduction of natural gas liquids from natural gas we lls. Natural gas liquids contain lighter end hydrocarbon s such as ethane, propane, butane, and pentane, and methane gas. In addition, methods used to extract the hydrocarbons from both natural gas wells and th e 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 f rom 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 pipe line can vary from one to several. These separators reduce the pressure of the oil/natural g as/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 (h eatertreater). The heater-treater reduces the pressure closer to ambient pressure and heats the leftover emulsion using a flame-arrested line heater (the he ater-treater burner). The combination of higher temperatures and lower pressures allows for additio nal 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 heate r-treater to the sales natural gas pipeline or to a n emissions control unit when a natural gas sales pip eline is not available or the pipeline has a limite d capacity. The oil is temporarily stored in these o n-site storage tanks prior to being transferred eit her to tanker trucks or to a lease automatic custody trans fer (LACT) unit for conveyance to a refining proces s21

plant. Separated water is temporarily stored in th e on-site storage tanks prior to being loaded into tanker trucks for transport and disposal. In addition to the natural gas recovered from the e xtracted wellhead fluids, low pressure natural gas is also collected from off-gassing that occurs from the storage of the produced oil and water in t he 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, util ity flare or pit flare for combustion, or is routed to a vapor recovery unit (VRU) to be injected into a nat ural gas sales pipeline for conveyance to a natural gas plant. In the event that pipeline injection of rec overable 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 produ ction 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 reserv oir

fluids which vents considerable VOC emissions to th e atmosphere. Large amounts of VOCs are also emitted during production when the reservoir fluids are separated into oil, natural gas and water unde r high pressure using heat. Finally, the transfer an d storage of the produced oil and water after separ ation

can be a source of VOC emissions if vented to the a tmosphere. In other words, the separated oil and water are both under high pressure and still contai n some dissolved natural gas. When the separated o il and water are subjected to atmospheric pressure dur ing transfer to storage tanks, the dissolved natura l 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 sourc e of VOC emissions. Due to the high levels of VOC emissions from these specific operations, we establ ished VOC control and emission reduction22

requirements in this rule for completion and recomp letion operations, heater-treater systems associate d with production operations, and storage tanks assoc iated with oil and water storage operations. Because of the experience that already existed in t he 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 practice s already in place. The practices currently in pla ce are primarily due to product recovery or safety concern s 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 p hased approach to controlling practices occurring both from well completion and recompletions, throug h production operations, and ending with storage and loading operations and an appropriate timeline for installation of the controls. Components of th is rule are based on these practices that are already in place off the FBIR. In addition, we evaluated the North Dakota regulati ons to help identify appropriate requirements for construction and operation of the regulated equ ipment and the requirements for controlling VOC emissions from this equipment. The North Dakota Ru les at Chapter 33-15-07 provide requirements for the construction and operation of units that separa te volatile organic liquids from water, and the con trol of VOC emissions from such units. Specifically, Ch apter 33-15-07 requires that any equipment processing, treating, storing or handling volatile organic liquids must be equipped with covers (in th e case of tanks), closed vent systems and control dev ices, such as VRUs, enclosed combustors, or flares. Chapter 33-15-07 refers to the Standards of Perform ance 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. Ch apter 33-15-07 requires the use of submerged pipe filling during storage operations to limit the evol ution of natural gas from the oil and water. We23

determined that the VOC emission reduction requirem ents during the separation of the oil, natural gas, and water in this rule were relevant and appropriat e as a basis for this rule. The North Dakota Rules at Chapter 33-15-20 provide requirements for the const ruction and operation of oil and natural gas production equipment and the control of VOC emissio ns 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 Bakke n Pool Guidance. The NDIC regulations

found in the Control of Oil and Gas Resources at Ch apter 38-08 require natural gas from the heatertreaters to be routed to a natural gas gathering pi peline as soon as practicable. When a pipeline is not available, heater-treater natural gas is required t o be routed to a control system or device. The Bak ken Pool Guidance details the air pollution control req uirements of oil and natural gas operations produci ng 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 Po ol 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 th e control equipment requirements and monitoring requirements in this rule were adapted from this gu idance. Control of VOC emissions from other sources such as dehydration units, pneumatic contro llers, pneumatic pumps, truck loading, etc. are als o included in this guidance; however, we did not eval uate 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 pi t flare for tank and heater-treater emissions with an assumed 90.0 percent VOC destruction efficiency; a VRU for tank emissions, designed and operated to24

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 designe d 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 gatheri ng pipeline as soon as practicable. In addition, to V OC 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 o n the FBIR, they are already voluntarily following this guidance in the FBIR. Therefore, we determine d that the VOC emission reduction requirements in this document were relevant and appropriate as a ba sis for establishing monitoring, recordkeeping and reporting requirements necessary for enforceability of this rule. We also reviewed NSPS OOOO, which provides standard s for oil and natural gas production from natural gas wells. However, with the exceptio n 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 cove red by NSPS OOOO. While this standard does not regulat e the completion, recompletion, or production operations for the operations producing from the Ba kken Pool, the common characteristics between natural gas production and the Bakken Pool producti on and the regulatory requirements specific to completion and recompletion, provided insight into feasible control requirements for these operations. In addition, the monitoring, recordkeeping and repo rting requirements for production and storage operations were reviewed, and for necessary conditi ons to ensure legal and practicable enforceability

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

this rule are derived from this standard. Although we view the most relevant regulatory analo gue 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 a re similar to North Dakota in industry, meteorology , or25

air quality concerns to ensure the proposed require ments are legally and practicably enforceable, as w ell 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 Environm ent Air Pollution Control Division (CDPHE) 14 and the Utah Department of Environmental Quality (U DEQ) 15

. We also reviewed the regulations for oil and natura l gas production facilities under the Texas Administrative Code, implemented by the Railroad Co mmission 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 Div ision (ODEQ) 18 . However, we determined that it

was not relevant to review state and local rules th at are intended to address non-VOC pollutant emissions, nonattainment area requirements or speci fic localized air quality concerns unless such

12 MDEQ. Chapter 8 Air Quality Subchapter 16 Emissio n Control Requirements for Oil and Gas Well Facilit ies Operating Prior to Issuance of a Montana Air Quality Permit. Available online at: http://www.deq.mt.gov/dir/leg al/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 Guidanc e. Available online at: http://deq.state.wy.us/aqd/Oil%20and%20G as/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 Co mmission Regulation Number 7- Control of Ozone Via Ozone Pre cursors (Emissions of Volatile Organic Compounds an d 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 Non attainment 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. Acces sed May 29, 2012. State only rule. 16 Texas Administrative Code, Title 16 Economic Regu lation, Part 1 Railroad Commission of Texas, Chapte r 3 Oil and Gas Division. Utah Texas Secretary of State. Available online at: http://www.sos.state.tx.us/tac/. Acces sed May 29, 2012. State only rule. 17 New Mexico Administrative Code, Title 20 Environm ental Protection, Chapter 2 Air Quality, Part 38 Hy drocarbon Storage Facilities and Part 61 Smoke and Visible Em issions. New Mexico Commission of Public Records, N ew Mexico Register. Available online at: http://www.nmcpr.st ate.nm.us/nmac/_title20/T20C002.htm. Accessed May 29, 2012. State only rule. 18 Oklahoma Administrative Code, Title 252 Departmen t of Environmental Quality, Chapter 100 Air Polluti on Control, Subchapter 37 Control of Volatile Organic Compounds . Oklahoma Secretary of State – Office of Administr ative Rules. Available online at: http://www.sos.ok.gov/oar/onli ne/viewCode.aspx. Accessed May 29, 2012. EPA appro ved 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 includ e: 252:100-37-2, 252:100-37-17, 252:100-37-18, 252:100-37-25, and 25 2:100-37-38[Revoked].26

concerns are also present on the FBIR or control eq uipment requirements apply to the same emission units this rule seeks to address. Copies of all th e state and local agency rules that we considered i n this process and other supporting documentation are incl uded in the docket for this rule. Regarding state regulations and guidance for VOC d estruction efficiency and monitoring of enclosed combustors and utility flares, the rule re quirements are generally consistent with all state requirements for enclosed combustors and utility fl ares. When reviewing state regulations or guidance for pr oduced 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 f or construction and emission control of produced oi l and water storage tanks are fairly consistent with all state regulations and guidance reviewed, althou gh there are varying degrees of de minimis natural gas throughput, storage capacities, or ann ual 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 wi th a PTE greater than 10 tons per year (tpy) within 60 days of the first date of production, com pared to ninety (90) days in this rule. The WDEQ also allows control equipment removal if flashing e missions 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 aft er one year after the first date of production if t he uncontrolled PTE VOCs emissions from the aggregate of all produced oil storage tanks and any produced water storage tanks interconnected with th e produced oil storage tanks declines to less than 20 tpy. D. Area & Facilities Covered by the FIP27

This rule will apply to any person who owns or oper ates an existing (constructed or modified on or after August 12, 2007), new, or modified oil and natural gas production facility 19 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; FB IR. A more detailed description of the Reservation is provided below in Section IV. This rulemaking is a step in addressing concerns th at have been raised about the potential impacts due to increasing oil and natural gas devel opment on the FBIR. If in the future, we become aware of air quality or permitting burden related t o oil and natural gas production for other Reservat ions or areas of Indian Country, using our authority des cribed 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 therefor e 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 permit ting requirements for minor sources at 40 CFR § 49.151. The purpose of this rule is to provide leg al and practical enforceability for the use of VOC emission controls that are already being used volun tarily by the industry and for VOC emissions

reductions from those controls. Provided that the facilities are in compliance with the new rule, the y may take into account the enforceable VOC emission reductions from the required controls they use when calculating their PTE for determining applicab ility of the permitting requirements, to the extent

that the effect those controls would have on VOC em issions 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 pro duction facility consists of all the air pollution emitting units and activities located on or integrally connected to one or more o il 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 oi l, produced water, and produced gas for transport off-site. Additionally, August 12, 2007 is the earliest well completion da te identified in the CAFOs.28

exceed the applicability thresholds for PSD or Fede ral Tribal NSR Rule permitting even after applying the legally and practicably enforceable emission re ductions provided in this rule. In such cases, the owners or operators of these facilities are require d 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, 201 1. Nor does this rule impose any additional registration requirements. Again, the purpose of t his rule is to provide legal and practical enforcea bility

for the use of VOC emission controls that are alrea dy 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 con trols would have on VOC emissions is legally and practica bly enforceable. If the PTE VOCs or any other regulated NSR pollutan t is less than the major source thresholds in 40 CFR § 52.21, but equal to or greater than the th resholds in the Federal Tribal NSR Rule, then registration is required of these facilities (40 CF R § 49.160). Those facilities that must obtain a P SD 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 exemp t from this registration requirement.

G. Applicability to New & Existing & Modified Faciliti es This rule applies to each owner or operator constru cting 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 oi l and natural gas wells, any one of which a well comp letion or recompletion operation is/was initiated o n or after August 12, 2007.29

For the purposes of this rule, a well completion me ans the process that allows for the flowback of oil and natural gas from newly drilled wells to exp el drilling and reservoir fluids and tests the rese rvoir flow characteristics, which may vent produced hydro carbons to the atmosphere via an open pit or tank. A well completion operation means any oil and natur al gas well completion with hydraulic fracturing occurring at an oil and natural gas production faci lity. The completion date is considered the date t hat construction at an oil and natural gas production f acility 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 recomplet ion date is considered the date that a modification has occurred at an oil and natural gas production facil ity. The reason we selected the initiation of completions operations as the date for defining a n ew facility is that owners and operators use drill rigs prior to initial completion operations and this equ ipment is not considered a stationary source. In addition, it is not certain during the drilling ope rations whether a well will be a producing well. H ence it is not known whether an oil and natural gas product ion facility will be constructed to support that we ll. The outcome of a completion operation provides the well owners and operators information necessary to determine whether an oil and gas production facilit y will be constructed. Requiring compliance with this rule upon recompletion of any one well at a fa cility 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 phys ical change occurs to the well resulting in emissions increases during the recompletion operati on (for the purposes of this rule the process of refracturing is defined as a recompletion). In determining the appropriate effective date and t he well completion dates for this rule, we evaluated the purpose of the rule, the gaps in regu lations, NSPS OOOO and the requirements and stipulations of CAFOs finalized between us and sel ect operators on the FBIR in late August 2011 and30

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 ord ers established control requirements during the lif e 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 existi ng oil and natural gas production facilities is to provide a CAA compliance mechanism for those compan ies 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 pollutan ts 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 ozone 20 and nitrogen dioxide (NO 2 ) concentrations substantially lower than the current National Ambient Air Quality Standards (NAA QS) of 75 parts per billion (ppb) for 8-hour average ozone and 100 ppb for the 1-hour average NO 2 . The state of North Dakota operates three air quality monitor sites in western North Dakota to ch aracterize 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 NO 2 NAAQS are 55 ppb and 11 ppb, respectively. We evaluated the impacts of changes in VOC and nitr ogen oxides (NO x ) 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 ana lysis for this rule. Emissions categories that are substantially controlled by this rule include VOC a nd NO x .

20 VOC and NO x are precursors to ozone.31

Expected potential emissions of sulfur dioxide (SO 2 ) 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 thresh olds, and are therefore expected to have insignificant impacts on the NAAQS for these pollut ants. Expected potential emissions of carbon monoxide (CO) from enclosed combustors and flares u sed 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 enfor ceable VOC emission reductions that reflect reductions that facilities are already routinely ac hieving through the installation and operation of c ontrol equipment for health, safety and market purposes. In addition, this rule does not exempt these facili ties from other potentially applicable regulatory or per mitting requirements. Therefore, we believe that a ir 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 res ulting from oil and natural gas production from the Bakken Pool underlying the FBIR have a hig h 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 tim e. Currently, most produced natural gas and natura l gas emissions from oil and natural gas production o perations on the FBIR are routed to a combustion device such as a pit flare, utility flare, or enclo sed combustor.32

Uncontrolled emissions of VOC from operations at a n oil and natural gas production facility consisting of a single well and associated producti on and storage operations were estimated to average approximately 2,165 tons per year (tpy). Of this t otal, approximately 1,610 tpy of VOC results from produced natural gas emissions from the heater-trea ter and 555 tpy of VOC is emitted from the produced oil and water storage tanks. This rule requires th at emissions from the heater-treater and the storag e tanks be routed to a combustion device. We estimat e that, on average, the control requirements in thi s rule will reduce VOC emissions from an oil and natu ral gas production facility by approximately 2,090 tpy per well. 21 The costs of the control equipment required by thi s rule depend, in part, on the number of wells associated with each oil and natural gas production facility. Generally, as the number of wells locat ed 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 capa city to handle the additional produced natural gas and natural gas emissions; thus, the costs of the contr ol equipment per well potentially decreases at oil and natural gas production facilities that consist of m ultiple wells. The Bureau of Land Management (BLM) has estimated that future development in the area o f 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 conducte d by the Bureau of Indian Affairs 23 , we believe a

21 The Technical Support Document includes a more d etailed 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 S cenario for Oil and Gas Activities on Bureau managed Lands in t he North Dakota Study Area”. This report was suppl emented on February 25, 2011 with the document titled “Revised Activity and Surface Disturbance Projections for t he Reasonable Foreseeable Development Scenario for Oil and Gas Ac tivities on Bureau Managed Lands in the North Dakot a Study Area”. Both documents are included in the docket for this rule and are publicly available at the following we bsite: http://www.blm.gov/mt/st/en/fo/north_dakota_field/r mp/RFD.html. 23See TSD at Section 4. Reasonably Foreseeable Deve lopment33

value of two wells per facility provides a conserva tive estimate of well density for future developmen t 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 woul d 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 th e 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 fac ility 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 thi s is a conservative estimate and that actual annual

costs would be much lower due to factors such as in creased facility well density, standard industry practice to use VOC control equipment, and anticipa ted 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 Constitut ion 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 o f the Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nations. The FBIR was establi shed pursuant to the Treaty of Fort Laramie of 185134

and addressed in subsequent agreements and Executiv e 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 th e 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 purpo ses 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 ai r resources within the exterior boundaries of their Reservations). The Three Affiliated Tribes have no t applied for TAS for the purpose of administering a Tribal Implementation Plan (TIP) under the CAA. Th ere is thus currently no EPA-approved plan implementing the functions and provisions of this F IP 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 M arch 3, 1891 (26 Statute 1032) and which includes all la nds 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), dir ects us to promulgate regulations specifying the provisions of the Act for which it is appropria te to treat Indian tribes in the same manner as sta tes. Pursuant to this statutory directive, EPA promulgat ed regulations entitled, “Indian Tribes: Air Qualit y 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 de termined such treatment was inappropriate are CAA § 110(a)(1) (State Implementation Plan (SIP) su bmittal and implementation deadlines) and CAA § 110(c)(1) (directing EPA to promulgate a Federal Im plementation Plan (FIP) "within 2 years" after we find that a state has failed to submit a required p lan, or has submitted an incomplete plan, or within 2 years after we disapproved all or a portion of a pl an). See 40 CFR §§ 49.4(a), (d); 63 FR at 7262-66 (February 12, 1998). The TAR preamble clarified that by including CAA 11 0(c)(1) on the section 49.4 list, “EPA is not relieved of its general obligation under the CA A to ensure the protection of air quality throughou t the nation, including throughout Indian country. I n 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 t he Agency will promulgate a FIP to protect tribal air quality within a reasonab le 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 articula ted in the proposed rule that, based on the “general purpose and scope of the CAA, the requirem ents 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 count ry’ by directly implementing the Act’s requirements

24 Section 49.11(a) states that the Agency, “[s]hall p romulgate without unreasonable delay such federal i mplementation plan provisions as are necessary or appropriate to prote ct air quality, consistent with the provisions of sections 301(a) a nd 301(d)(4), if a tribe does not submit a tribal impl ementation plan meeting the completeness criteria o f 40 CFR part 51, Appendix V, or does not receive EPA approval of a s ubmitted tribal implementation plan.” 40 CFR § 49. 11(a).36

in instances where tribes choose not to develop a p rogram, fail to adopt an adequate program or fail t o adequately implement an air program.’’ Id. The NDDoH, the CAA permitting authority for areas o utside of Indian country, including outside of the FBIR, has promulgated rules to contr ol emissions from oil and natural gas production facilities. Since there is not currently an approv ed 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 facilitie s operating within the exterior boundaries of the Reservation. This FIP will establish legally and p racticably 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 Dako ta on or after August 12, 2007. Specifically, this rule applies to facilities on the FBIR within the C rude Petroleum and Natural Gas Extraction Industry, North American Industry Classification System (NAIC S) 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 r ule on our internet site (http://www.epa.gov/region8/ai r/fbirfip.html) and notify the owners and operators37

and the Tribes.

C. Provisions for Delegation of Administration to the Tribes The provisions in § 49.141 establish the steps by w hich 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 T ribes the authority to assist with such

administration of this rule. As described in the r egulatory provisions, any such delegation will be accomplished through a delegation of authority agre ement between the Regional Administrator and the Tribes. This section provides for administrative d elegation of this federal rule and does not affect the eligibility criteria under CAA section 301(d) and 4 0 CFR 49.6 for TAS should the Tribes decide to seek such treatment for the purpose of administering the ir own EPA-approved program under Tribal law. Administrative delegation is a separate process fro m TAS under the TAR. Under the TAR, Indian tribes seek EPA-approval of their eligibility to run CAA p rograms 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 agreeme nt is reached, the rule would continue to operate unde r federal authority throughout the FBIR, and the

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

D. General Provisions The provisions in § 49.142 General Provisions provi de: 1) definitions that apply to this rule; 2) assurance that we will maintain its authority to re quire testing, monitoring, recordkeeping, and repor ting in addition to that already required by an applicab le requirement, in a permit to construct or permit to operate in order to ensure compliance; and 3) assur ance that nothing in the rule will preclude the use , including the exclusive use, of any credible eviden ce or information, relevant to whether a facility w ould have been in compliance with applicable requirement s if the appropriate performance or compliance test38

had been performed.

E. Construction and Operational Control Measures. The provisions in § 49.143 Construction and Operati onal 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 ass ociated with completion and recompletion operations to a utility flare or a pit flare capable of reduci ng the mass content of VOCs in the natural gas vent ed to it by at least 90.0 percent. We note that the well completion and recompletion control requirements t o use pit flares or utility flares that have the capa bility to reduce the mass content of VOC in the nat ural gas emissions routed to them by at least 90.0 perce nt by weight are the minimum level of control that would be allowed under this rule. Owners and opera tors may also choose to perform reduced emission completions and recompletions 25 , which would exceed the 90.0 percent VOC emission reduction requirement. This section also requires the contro l of production and storage operations and imposes a timeline for installation of the controls on these operations. The owner or operator is required to r educe 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 da te of production. Within ninety (90) days of the f irst date of production, we require the owner or operato r 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 in to a natural gas gathering pipeline system for sale or other beneficial purpose. For those owners or oper ators that choose to capture the natural gas as pro duct

25 U.S. Environmental Protection Agency. Lessons Lea rned from Natural Gas STAR Partners: Reduced Emissi ons Completions for Hydraulically Fractured Natural Gas Wells. Office of Air and Radiation: Natural Gas S tar Program. Washington, DC. Available at: http://epa.gov/gassta r/documents/reduced_emissions_completions.pdf. Acce ssed July 26, 2012.39

rather than a pollutant to be controlled, the natur al gas may temporarily be routed through a closed-v ent system to an enclosed combustor, utility flare or p it flare in instances where injection of the produc t into the pipeline is temporarily infeasible. In these s ituations, the pit flare is considered an emergency standby unit used for unplanned flare events such a s temporarily limited pipeline capacity, equipment breakdown and/or other upsets that are beyond a pro ducer’s control and the pit flare is used to safely burn the natural gas product that could otherwise p ose 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 50 0 hours of operation in any consecutive 12-month peri od. This limit on the hours of operation of the pi t flare in such situations provides a balance of air quality, safety and environmental protection, to ad dress public concerns expressed on the proposed synthetic minor NSR permits with the use of pit flares, and flexibility for the operators, to address claims th at continuous injection into a natural gas sales pi peline may not be possible at all times. The rule requires the owner or operator to route al l standing, working, breathing and flashing losses from the produced oil storage tanks and any produced water storage tanks interconnected with th e produced oil storage tanks through a closed vent sy stem 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 util ity flare capable of reducing the mass content of V OC in the natural gas emissions vented to the device b y at least 98.0 percent. We note that while NSPS OOOO requires 95% VOC reduction of emissions from s torage 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 committe d 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 ha s higher40

VOC content than typical natural gas production and the overall BTU value is generally higher, this sh ould result in more efficient VOC destruction. Therefore, we be lieve that a requirement of 98.0 % reduction of VOC emissions during continued production operations is appropriate. However, to prevent duplicative feder al requirements for owners and operators of storage ta nks on the FBIR subject to both this rule and NSPS OOOO,

s torage tanks subject to and controlled under the re quirements specified in 40 CFR Part 60, Subpart OOOO are considered to meet the storage tank contro l requirements of this rule. No further requirements apply for such storage tanks under thi s 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 tan ks and produced water storage tanks interconnected wit h produced oil storage tanks at an oil and natural gas production facility is less than, and reasonabl y expected to remain below, 20 tons in any consecut ive 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 combus tors, 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 u nder specific conditions as specified in § 49.144 Control Equipment Requirements and § 49.145 Monitor ing 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 approva l for a new method, the owner or operator must calc ulate potential to emit based on the new EPA-approved method. 27 Based on our consultation with the owners and opera tors producing from the Bakken Pool, in addition to these particular provisions we also identified for regulating emissi ons from well completions and recompletions. These control operations are already being performed during these operations for product recovery or safety purposes. These co nsultations, provided us not only with information on the production prac tices occurring both on and off the Reservation, bu t it also provided us with information on the existing phased approach to controlling emissions from well completion and rec ompletions, 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 bas ed on these practices that are already in place.41

The provisions in § 49.144 Control Equipment Requir ements 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 oper ational requirements for the covers and closed-vent systems. The construction and operational requirem ents of the covers and closed-vent systems are base d on the NSPS OOOO requirements and are intended to p rovide legal and practical enforceability. In addition, § 49.144 requires specific construction a nd 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 s torage tank that is interconnected with produced oi l storage tanks with a cover that ensures that natura l gas emissions are efficiently routed through a cl osedvent 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, sampli ng ports, and gauge wells) must form a continuous barrier over the entire surface area of the produce d oil and produced water in the storage tank. Each cover opening must be secured in a closed, sealed p osition (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 m aterial 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 in spect or sample the material in the unit; or to ins pect, maintain, repair, or replace equipment located insi de the unit. These requirements are consistent wit h 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-v ent systems to collect and route natural gas emissions to the respective VOC control devices. A ll vent lines, connections, fittings, valves, relie f valves, or any other appurtenance employed to conta in and collect gases, and transport them to the VOC control equipment must be maintained and operated p roperly during any time the control equipment is operating and must be designed to operate with no d etectable natural gas emissions. If a closed-vent system contains one or more bypass devices that cou ld be used to divert all or a portion of the natura l gas, from entering the VOC control devices, the own er or operator must meet one of the following options for each bypass device: 1) at the inlet to the bypass device properly install, calibrate, main tain, and operate a natural gas flow indicator capable of taking periodic readings and sounding an alarm whe n the bypass device is open such that the natural gas is being, or could be, diverted away from the cont rol device and into the atmosphere; or 2) secure the by pass device valve in the non-diverting position usi ng a car-seal or a lock-and-key type configuration. T hese 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 ma nufacturer’s written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions from each enclosed combustor or utility f lare. Each enclosed combustor must have the capacity to reduce the mass content of the VOC in t he natural gas routed to it by at least 98.0 percen t 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 manufactur er in accordance with specific requirements in the rule, or that that are designed and operated in acc ordance with applicable requirements in 40 CFR Part43

60.18(b), satisfy the requirements of performance t esting by the owner or operator. For the purposes of this rule, we require that all utility flares insta lled 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, howe ver, the owner or operators can demonstrate compliance using methods specified in this rule. We determined that certain work practice and operat ional requirements are also necessary for the practical enforceability of the VOC emission reduction requirement that the enclosed co mbustors or utility flares must achieve. Flares and combustors must be operated within specific parameters to effectively destroy VOC emissions. This was discus sed in great detail in the preamble and technical support documents to the proposed and final NSPS OO OO 15 . Therefore, each owner or operator must ensure that each enclosed combustor or utility flar e is: 1) operated at all times that natural gas is routed to it; 2) operated with a liquid knock-out system t o collect any condensable vapors (to prevent liquid s 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 malfu nction alarm and remote notification system to detect if the pilot flame fails while natural gas i s being routed through the device; 6) equipped with a continuous recording device, such as a chart record er, data logger or similar device, or connected to a Supervisory Control and Data Acquisition (SCADA) sy stem, to monitor and document proper operation of the enclosed combustor or utility flare; 7) main tained in a leak free condition; and 8) operated wi th no visible smoke emissions. These requirements are co nsistent 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 c ontrol VOC emissions in the event the natural gas44

that is being recovered for sale or other beneficia l purpose must be diverted to an emergency control device because injection into the pipeline is tempo rarily infeasible and the enclosed combustor or uti lity flare installed at the oil and natural gas producti on 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 a n oil and natural gas production facility have decl ined to less than, and are reasonably expected to stay b elow, 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 a t least 90 percent and must be operated with no visib le smoke emissions. 28 Each pit flare must be equipped with an electronically controlled automati c ignition system with malfunction alarm and remote notification system if the pilot flame fails. Each pit flare must be visually inspected for the prese nce 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 m ust be repaired or replaced before the pit flare is used again.

As North Dakota has done in the Bakken Pool Guidanc e, § 49.144 allows owners or operators of oil and natural gas production facilities to use co ntrol devices other than an enclosed combustor or u tility flare, provided they are capable of achieving at le ast a 98.0 percent VOC destruction efficiency and upon our written approval. This provision will all ow for owner or operators to take advantage of technological advances in VOC emission control for the oil and natural gas production industry and wil l provide us with valuable information on any new con trol technologies.

G. Monitoring Requirements Section 49.145 Monitoring Requirements requires eac h owner or operator conduct certain

28 Owners and operators of oil and natural gas product ion 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 th eir synthetic minor NSR applications to reduce the mass content of VOC emissions routed to a pit flare by at least 90.0% b y weight.45

monitoring that we determined is necessary for the practical enforceability of the VOC emission reduction requirements, including but not limited t o: (1) Monitoring of the hours of operation of eac h pit flare used to control VOC emissions in the even t the natural gas that is being recovered for sale or other beneficial purpose must be diverted to an eme rgency control device because injection into the pipeline is temporarily infeasible and the enclosed combustor or utility flare installed at the oil an d natural gas production facility is not operational; (2) Monitoring of the number of barrels of oil pro duced at the facility each time the oil is unloaded from the produced oil storage tanks; (3) Monitoring of t he 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 stand ing, working, breathing, and flashing losses from t he produced oil and produced water storage tanks sent to each vapor recovery system, enclosed combustor, utility flare, and pit flare at all times; (5) Dire ctly measuring, or calculating using EPA approved m odels, various parameters (i.e., product throughput, enclo sed combustor flame presence, temperature, etc.) related to the proper operation of emissions units and required control devices to assure compliance w ith the emissions reduction requirements and operationa l limitations; and (6) Visibility monitoring for detecting visible smoke from enclosed combustors, u tility 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 Bak ken Pool Guidance. Specifically, our review and determ ination that these requirements are appropriate, as well as the Bakken Pool Guidance provides the basi s for monitoring the flares and enclosed combustors. The monitoring of the covers and close d-vent systems, in addition to the recordkeeping an d reporting requirements are based on the NSPS OOOO r equirements 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 recor ds to be made available upon our request, in lieu o f voluminous reporting requirements. The records tha t must be kept include, but are not limited to, all required measurements, monitoring, and deviations o r exceedances of rule requirements and corrective actions taken, as well as any manufacturer specific ations and guarantees or engineering analyses. The se record keeping requirements were derived independen tly of the North Dakota Rules and Bakken Pool Guidance and provide legal and practical enforceabi lity 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 rul e becomes effective covering the period for the previ ous calendar year. The report must include a summary of required records identifying each oil an d natural gas production well completion or recompletion operation for each facility conducted during the reporting period, an identification of t he first date of production for each oil and natural g as production well at each facility that commenced operation during the reporting period, and a summar y of deviations or exceedances of any requirements

of the FIP and the corrective measures taken. Addi tionally, a report must be submitted for any performance test we require. We decided not to require owners or operators to re gister 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 th is rule would be redundant. These reporting requirements were derived independe ntly of the North Dakota Rules and Bakken47

Pool Guidance and provide legal and practical enfor ceability to the control and emission reduction requirements of this rule.

VII. Statutory and Executive Order

A. Executive Order 12866: Regulatory Planning and Revi ew 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 sub ject 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 collecti on 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 requ ires 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 u nless the agency certifies that the rule will not h ave a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governme ntal jurisdictions. For purposes of assessing the impacts of today's ru le on small entities, small entity is defined as: (1) a small business as defined by the Small Busine ss 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 l ess than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently ow ned 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 econom ic impact on a substantial number of small entities . In determining whether a rule has a significant econom ic impact on a substantial number of small entities , the impact of concern is any significant adverse ec onomic impact on small entities, since the primary purpose of the regulatory flexibility analyses is t o identify and address regulatory alternatives “whi ch minimize any significant economic impact of the rul e on small entities.” 5 USC 603 and 604. Thus, an agency may certify that a rule will not have a sign ificant economic impact on a substantial number of small entities if the rule relieves regulatory burd en, 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 impa ct 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 o n 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 199 5 (UMRA), Public Law 104-4, establishes requirements for federal agencies to assess the eff ects of their regulatory actions on State, local, a nd Tribal governments and the private sector. Under s ection 202 of UMRA, EPA generally must prepare a written statement, including a cost-benefit analysi s, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, and Tribal governments, in the aggregate, o r to the private sector, of $100 million or more (adjust ed for inflation) in any one year. Before promulga ting

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 regula tory alternatives and adopt the least costly, most cost-effective, or least burdensome alternative tha t achieves the objectives of the rule. The provisi ons of49

Section 205 of UMRA do not apply when they are inco nsistent with applicable law. Moreover, Section 205 of UMRA allows us to adopt an alternative other than the least costly, most cost-effective, or lea st burdensome alternative if the Administrator publish es with the final rule an explanation why that alternative was not adopted. Before we establish a ny regulatory requirements that may significantly o r uniquely affect small governments, including Tribal governments, it must have developed under Section 203 of UMRA a small government agency plan. The pl an must provide for notifying potentially affected small governments, enabling officials of a ffected small governments to have meaningful and timely input in the development of EPA regulatory p roposals with significant federal intergovernmental mandates, and informing, educating, and advising sm all governments on compliance with the regulatory requirements. Under Title II of UMRA, we determined that this rul e does not contain a federal mandate that may result in expenditures that exceed the inflatio n-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 c ontain a significant federal intergovernmental mandate as described by section 203 of UMRA nor does it contain any regulatory requirements that might sign ificantly or uniquely affect small governments.

E. Executive Order 13132: Federalism

Federalism (64 FR 43255, August 10, 1999) revokes and replace s Executive Orders 12612 (Federalism) and 12875 (Enhancing the Intergovernme ntal Partnership). Executive Order 13132 requires EPA to develop an accountable process to e nsure “meaningful and timely input by State and local officials in the development of regulatory po licies that have federalism implications.” “Polici es that have federalism implications” is defined in th e Executive Order to include regulations that have “substantial direct effects on the States, on the r elationship between the national government and the States, or on the distribution of power and respons ibilities among the various levels of government.”50

Under Executive Order 13132, we may not issue a reg ulation that has federalism implications, that imposes substantial direct compliance costs, and th at 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 off icials early in the process of developing regulatio ns. We also may not issue a regulation that has federal ism 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 distr ibution of power and responsibilities among the various levels of government, as specified in Execu tive Order 13132, because it regulates under the CAA certain stationary sources in Indian country th at 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 poli cy to promote communications between us and State and local governments, we specifically solici t comment on this rule from State and local officia ls.

F. Executive Order 13175: Consultation and Coordinati on with Indian Tribal Governments Executive Order 13175, entitled ‘‘Consultation and Coordination with Indian Tribal Governments’’ (65 FR 67249, November 6, 2000), requ ires us to develop an accountable process to ensure ‘‘meaningful and timely input by Tribal offi cials in the development of regulatory policies tha t have Tribal implications.’’ ‘‘Policies that have Tr ibal implications’’ is defined in the Executive Ord er 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 ma y not issue a regulation that has Tribal implications, that imposes substantial direct compl iance costs, and that is not required by statute, u nless51

the Federal government provides the funds necessary to pay the direct compliance costs incurred by Tribal governments, or we consult with Tribal offic ials early in the process of developing the propose d regulation. Under Section 5(c) of Executive Order 13175, we may not issue a regulation that has Triba l implications and that preempts Tribal law, unless t he Agency consults with Tribal officials early in t he 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 gover nments, 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 unde r the CAA. The gap-filling approach used in this r ule would create Federal requirements similar to those that are already in place areas adjacent to the Reservation covered by the proposal. Finally, alth ough 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 c osts on Tribal governments, nor preempt Tribal law, the requirements of Sections 5(b) and 5(c) of the E xecutive 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 a nd timely input into its development.

Tribal consultation with the Three Affiliated Trib es of the Mandan, Hidatsa, and Arikara Nation was first initiated on February 17, 2012 when we ma iled a letter inviting the Tribes to consult on the first group of synthetic minor permits being issued on th e Reservation under the Tribal NSR Rule. Then, on March 29, 2012, EPA senior management and the Chair man of the Tribes along with other government officials met via conference call to discuss the pr oposed FIP to be developed for the FBIR. We formal ly

invited the Tribes to consult about the FIP in a le tter dated April 10, 2012 to Chairman Tex Hall, of the52

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 cons ult 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 F IP 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 inform ation on our plan to prepare a FIP to ensure air quality protection while preventing delays in oil a nd natural gas production. EPA solicited the Tribe s’ 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 natur al gas production facilities in order to keep a level playing field for development and continue uninterrupted development of a key economic resourc e for the Tribe. The Council members expressed interest in the future delegation of the FIP so tha t the Tribes can implement the rule in place of EPA

. The Council members also expressed interest in prov iding 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 administr ative delegation of the Tribal NSR rule to assist u s with administration of that rule. We will continue to work with the Tribes if administrative delegati on 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, 199 7) as applying only to those regulatory actions that concern health or safety risks, such t hat the analysis required under section 5-501 of th e EO has the potential to influence the regulation. Thi s action is not subject to EO 13045 because it implements specific standards established by Congre ss in statutes. In addition, this rule requires co ntrol 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 Regulatio ns 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 a nd 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 tec hnical standards (e.g., materials specifications, t est methods, sampling procedures, and business practice s) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs us to pr ovide Congress, through OMB, explanations when the Agency decides not to use available and applica ble voluntary consensus standards. This rulemaking does not involve technical standard s. Therefore, we are not considering the use of any voluntary consensus standards.54

J. Executive Order 12898: Federal Actions to Address E nvironmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629, February 16, 199 4), establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicabl e and permitted by law, to make environmental justice par t of their mission by identifying and addressing, a s appropriate, disproportionately high and adverse hu man health or environmental effects of their programs, policies, and activities on minority popu lations and low-income populations in the United

States. We determined that this rule will not have dispropo rtionately high and adverse human health or environmental effects on minority, low income and i ndigenous 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 provide s that before a rule may take effect, the agency promulgating the rule must submit a rule report, wh ich includes a copy of the rule, to each House of t he Congress and to the Comptroller General of the Unit ed States. Section 808 allows the issuing agency to make a rule effective sooner than otherwise provide d by the CRA if the agency makes a good cause finding that notice and public procedure is impract icable, unnecessary or contrary to the public inter est. This determination must be supported by a brief sta tement. 5 U.S.C. 808(2). As stated previously, EP A has made such a good cause finding, including the r easons 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, 201 2.56

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 Pro visions Part 49-INDIAN COUNTRY: AIR QUALITY PLANNING AND M ANAGEMENT 2. Add §§ 49.140 through 49.147 and an undesignate d 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) i n EPA Region 8. § 49.140 Introduction (a) What is the purpose of this rule? This rule establishes legally and practicably enf orceable requirements to control and reduce VOC emissions fr om well completion operations, well recompletion operations, production operations, and storage oper ations at existing, new and modified oil and natura l gas production facilities. (b) Am I subject to this rule? This rule applies to each owner or operator constru cting or operating an oil and natural gas productio n 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/wer e performed on or after August 12, 2007, that is located on the Fort Berthold Indian Reservation, wh ich 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 no57

later than [ INSERT DATE 90 DAYS AFTER DATE OF PUBLICATION IN TH E 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 th e Mandan, Hidatsa and Arikara Nations the authority to assist the EPA with administration of this Federal implementation plan (FIP). This secti on 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 w ith administration of this FIP, the authorized represen tative of the Mandan, Hidatsa and Arikara Nations must submit a request to the Regional Administrator that: (1) Identifies the specific provisions for which d elegation is requested; (2) Includes a statement by the Mandan, Hidatsa an d Arikara Nations’ legal counsel (or equivalent official) that includes the following information: (i) A statement that the Mandan, Hidatsa and Arika ra Nations are an Indian Tribe recognized by the Secretary of the Interior; (ii) A descriptive statement demonstrating that th e Mandan, Hidatsa and Arikara Nations are currently carrying out substantial governmental duties and po wers 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, Hid atsa 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 Arik ara Nations have, or will have, adequate resources to carry out the aspects of the rule for which dele gation is requested.58

(c) How is the delegation of administration accomplishe d? (1) A Delegation of Authority Agreement will set f orth the terms and conditions of the delegation, wi ll specify the rule and provisions that the Mandan, Hi datsa and Arikara Nations shall be authorized to implement on behalf of the EPA, and shall be entere d 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 represent ative of the Mandan, Hidatsa and Arikara Nations have signed the Agreement. Once the delegation bec omes effective, the Mandan, Hidatsa and Arikara Nations will be responsible, to the extent specifie d in the Agreement, for assisting us with administr ation of the FIP and shall act as the Regional Administra tor 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 rema in the EPA Regional Administrator and when it is intended to refer to the “Mandan, Hidatsa and Arika ra Nations,'' instead. (2) A Delegation of Authority Agreement may be mod ified, amended, or revoked, in part or in whole, by the Regional Administrator after consultation wi th the Mandan, Hidatsa and Arikara Nations. (d) How will any delegation of authority agreement be p ublicized? (1) The Regional Administrator shall publish a not ice in the Federal Register informing the public of any delegation of authority agreement with the Mand an, Hidatsa and Arikara Nations to assist us with administration of all or a portion of the FIP and w ill identify such delegation in the FIP. The Regio nal 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 here in shall have the meaning given them in the Act, in subpart A and subpart OOOO of 40 CFR Pa rt 60, in the Prevention of Significant59

Deterioration regulations at 40 CFR 52.21, or in th e Federal Minor New Source Review Program in Indian Country at 40 CFR 49.151. The following term s shall have the specific meanings given them. (1) Bakken Pool means Oil produced from the Bakken, Three Forks, an d 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 dis solves out of reservoir fluids during well completion operations and recomp letion operations due to the pressure relief that occurs as the reservoir fluids travel up the well c asinghead. (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, f low-inducing devices that transport natural gas fro m 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 control ling fuel and combustion air. (6) Existing facility means an oil and natural gas production facility t hat begins actual construction prior to the effective date of the ``Federal Implementati on Plan for Oil and Natural Gas Production Faciliti es, Fort Berthold Indian Reservation (Mandan, Hidatsa a nd Arikara Nations)''. (7) Flashing losses means natural gas emissions resulting from the pre sence of dissolved natural gas in the produced oil and the produced water, both of wh ich are under high pressure, that occurs as the produced oil and produced water is transferred to s torage tanks or other vessels that are at atmospher ic

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 a ddition of any associated equipment necessary for production and storage operations at an existing fa cility.60

(9) New facility means an oil and natural gas production facility th at begins actual construction after the effective date of the `` Federal Implementation Pla n for Oil and Natural Gas Production Facilities, Fo rt Berthold Indian Reservation (Mandan, Hidatsa and Ar ikara 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 o il 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 reser voir fluids containing a mixture of oil, natural gas, and water. (13) Owner or operator

means any person who owns, leases, operates, contr ols, or supervises an oil and natural gas production facility. (14) Permit to construct or construction permit means a permit issued by the Regional Administrato r pursuant to 40 CFR 49.151, 52.10 or 52.21, or a per mit 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 Administrato r 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 o peration of a stationary source. (16) Pit flare means an ignition device, installed horizontally o r vertically and used in oil and natural gas production operations to combust produced natur al 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 reservo ir 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 st ructural support and is designed to contain an accumulation of produced oil. (20) Produced water

means water that is separated from extracted reser voir 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 provi des structural support and is designed to contain a n accumulation of produced water. (22) Production operations means the extraction and separation of reservoir f luids from an oil and natural gas well, using separators and heater-treat er systems. A separator is a pressurized vessel designed to separate reservoir fluids into their co nstituent components of oil, natural gas and water. A

heater-treater is a unit that heats the reservoir f luid to break oil/water emulsions and to reduce the oil viscosity. The water is then typically removed by u sing gravity to allow the water to separate from th e oil. (23) Regional Administrator means the Regional Administrator of EPA Region 8 o r 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 wat er to storage tanks, the filling of the storage tanks, the storage of the pr oduced 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) sy stem generally refers to industrial control computer systems that monitor and control industria l infrastructure or facility-based processes. (27) Utility flare means thermal oxidation system using an open (with out enclosure) flame. An

enclosed combustor as defined in this rule is not c onsidered a flare. (28) Visible Smoke emissions means a pollutant generated by thermal oxidation i n a flare or enclosed combustor and occurring immediately downstream of t he 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 fluid s and tests the reservoir flow characteristics, whi ch 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 usin g hydraulic fracturing occurring at an oil and natural gas prod uction facility. (31) Well recompletion operation means any oil and natural gas well completion using hydraulic refracturing occurring at an oil and natural gas pr oduction facility. (32) Working losses means natural gas emissions from fixed roof tanks r esulting from evaporative losses during filling and emptying operations. (b) Requirement for testing . The Regional Administrator may require that an ow ner or operator of an oil and natural gas production facility demonstrate com pliance with the requirements of the ``Federal Implementation Plan for Oil and Natural Gas Product ion Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' by performi ng a source test and submitting the test results to the Regional Administrator. Nothing in the ``Feder al Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian Reserva tion (Mandan, Hidatsa and Arikara Nations)'' limit s the authority of the Regional Administrator to requ ire, in an information request pursuant to section 11463

of the Act, an owner or operator of an oil and natu ral gas production facility subject to the ``Federa l Implementation Plan for Oil and Natural Gas Product ion Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' to demonstr ate 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 repo rting . Nothing in "Federal Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' precludes the Regional Admin istrator 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 establi shing whether or not an owner or operator of an oil and natural gas production facil ity has violated or is in violation of any requirem ent, nothing in the ``Federal Implementation Plan for Oi l and Natural Gas Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Ar ikara Nations)'' shall preclude the use, including the exclusive use, of any credible evidence or info rmation, 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 Mea sures. (a) Each owner or operator must operate and mainta in all liquid and gas collection, storage, processi ng 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 an d natural gas production facility and prior to the fi rst date of production of each oil and natural gas well, each owner or operator must, at a minimum, route al l casinghead natural gas to a utility flare or a pi t64

flare capable of reducing the mass content of VOC i n the natural gas emissions vented to it by at leas t 90.0 percent or greater and operated as specified i n § 49.144 and § 49.145. (c) Beginning with the first date of production fr om any one oil and natural gas well at an oil and natural gas production facility, each owner or oper ator must, at a minimum, route all natural gas emissions from production operations and storage op erations to a control device capable of reducing th e mass content of VOC in the natural gas emissions ve nted 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 p roduction from any oil and natural gas well at an o il and natural gas production facility, each owner or oper ator must: (1) Route the produced natural gas from the produc tion operations through a closed-vent system to: (i) An operating system designed to recover and in ject all the produced natural gas into a natural ga s gathering pipeline system for sale or other benefic ial purpose; or (ii) An utility flare or equivalent combustion dev ice capable of reducing the mass content of VOC in the produced natural gas vented to the device by at lea st 98.0 percent or greater and operated as specifie d in § 49.144 and § 49.145. (2) Route all standing, working, breathing, and fl ashing losses from the produced oil storage tanks a nd 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 in ject the natural gas emissions into a natural gas gathering pipeline system for sale or other benefic ial purpose; or (ii) An enclosed combustor or utility flare capabl e of reducing the mass content of VOC in the natura l 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 f rom the aggregate of all produced oil storage tanks and produced water storage tanks interconnected with pr oduced oil storage tanks at an oil and natural gas production facility is less than, and reasonably ex pected to remain below, 20 tons in any consecutive 12- month period, then, upon written approval by the EP A the owner or operator may use a pit flare, an enclosed combustor or a utility flare that is capab le of reducing the mass content of VOC in the natur al 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 w ater storage tanks interconnected with produced oil storage tanks subject to and controlled under the r equirements specified in 40 CFR Part 60, Subpart OOOO are considered to meet the requirements of § 4 9.143(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 pro duced oil storage tanks with a cover to ensure that all natural gas emissions are efficiently being rou ted through a closed-vent system to a vapor recover y 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 v alves (PRV), and gauge wells) shall form a continuous imp ermeable barrier over the entire surface area of th e produced oil and produced water in the storage tank

.66

(2) Each cover opening shall be secured in a close d, 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 i t is necessary to use an opening as follows: (i) To add material to, or remove material from th e unit (this includes openings necessary to equaliz e 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 equ ipment located inside the unit. (3) Each thief hatch cover shall be weighted and p roperly seated. (4) Each PRV shall be set to release at a pressure that will ensure that natural gas emissions are ro uted through the closed-vent system to the vapor recover y system, the enclosed combustor, or the utility fl are under normal operating conditions. (b) Closed-vent systems . Each owner or operator must meet the following r equirements for closed-vent systems: (1) Each closed-vent system must route all produce d natural gas and natural gas emissions from production and storage operations to the natural ga s 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 a nd transport them to a natural gas sales pipeline a nd any VOC control equipment must be maintained and op erated properly at all times. (3) Each closed-vent system must be designed to op erate 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 d ivert the natural gas emissions away from a natural gas sales pipeline or a control device and into the atm osphere, properly install, calibrate, maintain, and operate a natural gas flow indicator that is capabl e of taking continuous readings and sounding an ala rm when the bypass device is open such that natural ga s emissions are being, or could be, diverted away from a natural gas sales pipeline or a control devi ce and into the atmosphere; (ii) Secure the bypass device valve installed at t he inlet to the bypass device in the non-diverting position using a car-seal or a lock-and-key type co nfiguration; (iii) Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and safety devic es are not subject to the requirements applicable to b ypass devices. (c) Enclosed combustors and utility flares. Each owner or operator must meet the following requirements for enclosed combustors and utility fl ares: (1) For each enclosed combustor or utility flare, the owner or operator must follow the manufacturer’ s written operating instructions, procedures and main tenance schedule to ensure good air pollution contr ol practices for minimizing emissions; (2) For each enclosed combustor or utility flare, the owner or operator must ensure there is sufficie nt capacity to reduce the mass content of VOC in the p roduced natural gas and natural gas emissions routed to it by at least 98.0 percent for the minim um 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 th e produced natural gas and natural gas emissions rout ed to it by at least 98.0 percent; (4) The owner or operator must ensure that each ut ility flare is designed and operated in accordance with the requirements of 40 CFR 60.18(b) for such f lares. (5) The owner or operator must ensure that each en closed 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 CF R Part 60, Subpart OOOO at § 60.5413(d) by the due date of the first annual report as specified in § 4 9.147(b); or (B) Demonstrated to meet the VOC destruction effic iency requirements of this rule using EPA approved performance test methods specified in 40 C FR 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 O OOO is promulgated, demonstrated to meet the VOC destruction efficiency requirements of this rul e 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 pollutant s, by the due date of the first annual report as speci fied in § 49.147(b). (6) The owner or operator must ensure that each en closed combustor and utility flare is: (i) Operated properly at all times that natural ga s is routed to it; (ii) Operated with a liquid knock-out system to co llect any condensable vapors (to prevent liquids fr om 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 thermocoup le, and a malfunction alarm and remote notification system if the pilot flame fails. (B) An electronically controlled auto-ignition sys tem with a malfunction alarm and remote notificatio n system if the pilot flame fails while produced natu ral gas or natural gas emissions are flowing to the enclosed combustor or utility flare; (v) Equipped with a continuous recording device, s uch as a chart recorder, data logger or similar dev ice, or connected to a Supervisory Control and Data Acqu isition (SCADA) system, to monitor and document69

proper operation of the enclosed combustor or utili ty 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 re quirements for pit flares: (1) The owner or operator must develop written ope rating 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 flar e for the following operations: (i) To control produced natural gas and natural ga s 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 enclose d 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 ma ximum of 500 hours in any twelve (12) consecutive months during periods when pipeline injection has b ecome temporarily infeasible and no enclosed combustor or utility flare installed at the facilit y 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 p roduced oil storage tanks and produced water storage tanks interconnected with produced oil stor age tanks is less than, and reasonably expected to remain below, 20 tons in any consecutive 12-month p eriod. (3) The owner or operator must only use the pit fl are under the following conditions and limitations: (i) The pit flare is operated to reduce the mass c ontent of VOC in the produced natural gas and natur al70

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, o perating procedures, and maintenance schedules to ensure goo d air pollution control practices for minimizing emissions; (iii) The pit flare is operated with no visible sm oke emissions; (iv) The pit flare is equipped with an electronica lly controlled auto-ignition system with a malfunct ion alarm and remote notification system if the pilot f lame fails; (v) The pit flare is visually inspected for the pr esence of a pilot flame anytime produced natural ga s or natural gas emissions are being routed to it. Shou ld the pilot flame fail, the flame must be relit as soon as safely possible and the electronically controlle d 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 cau se to be deposited into a flare pit any oil field f luids or oil and natural gas wastes other than those desi gned to go to the pit flare. (e) Other Control Devices . Upon written approval by the EPA, the owner or op erator may use control devices other than those listed above that are capa ble of reducing the mass content of VOC in the natu ral 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 suff icient capacity to reduce the mass content of VOC i n 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 vol umetric flow rate and BTU content routed to

each device.71

(3) The owner or operator must operate such a contr ol device to reduce the mass content of VOC in the produced natural gas and natural gas emissions rout ed to it by at least 98.0 percent. § 49.145 Monitoring Requirements. (a) Each owner and operator must measure the barre ls of oil produced at the oil and natural gas production facility each time the oil is unloaded f rom the produced oil storage tanks using the methodologies of tank gauging or positive displacem ent metering system, as appropriate, as established by the US Department of the Interior’s Bureau of La nd Management at 43 CFR 3160, in the “Onshore Oil and Gas Operations; Federal and Indian Oil & Ga s 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 f or pipeline injection must be diverted to an emerge ncy control device because injection is temporarily inf easible and the enclosed combustor or utility flare installed at the oil and natural gas production fac ility 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 time s. 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 sto rage 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 labor atory analyses. (e) Each owner or operator must perform quarterly visual inspections of tank thief hatches, covers, s eals, PRVs, and closed vent systems to ensure proper cond ition and functioning and repair any damaged equipment. The quarterly inspections must be perfo rmed while the produced oil and produced water72

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 syste m 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 ha s resulted, or may result, in venting and possible da mage 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 operat ion of each enclosed combustor, utility flare, and pit flare to confirm proper operation as follows: (1) Continuously monitor the enclosed combustor, u tility flare, and pit flare operation, using a malfunction alarm and remote notification system fo r failures, and checking the system for proper operation whenever an operator is on site, at a min imum 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, A ppendix A, confirm that no visible smoke emissions are present, except for periods not to ex ceed 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 monitor ing equipment operation or any pilot flame failure alarm and ensure the monitoring equipment is return ed to proper operation and/or the pilot flame is re lit as soon as practicable and safely possible after an observation or an alarm sounds. (h) Where sufficient to meet the monitoring and re cord 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.73

§ 49.146 Recordkeeping Requirements. (a) Each owner or operator must maintain the follo wing records: (1) The measured barrels of oil produced at the oi l 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 eac h enclosed combustor, utility flare, and pit flare at all times; (3) The volume of natural gas emissions from the p roduced oil storage tanks and produced water storage tanks sent to each enclosed combustor, util ity flare, and pit flare at all times; (4) For each oil and natural gas well completion o peration and recompletion operation at an oil and natural gas production facility: (i) Records identifying each oil and natural gas w ell completion operation and recompletion operation for each oil and natural gas production facility; a nd (ii) The latitude and longitude location of the oi l and natural gas well; the date, time, and duratio n of flowback from the oil and natural gas well; the dat e, 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 li eu of capture or combustion. The duration must be specif ied in hours. (5) For each enclosed combustor, utility flare, an d pit flare at an oil and natural gas production fa cility: (i) Written, site-specific designs, operating inst ructions, operating procedures and maintenance schedules; (ii) Records of all required monitoring of operati ons; (iii) Records of any deviations from the operating parameters specified by the written site-specific designs, operating instructions, and operating proc edures. The records must include the enclosed combustor, utility flare, or pit flare’s total oper ating time during which a deviation occurred, the d ate,74

time and length of time that deviations occurred, a nd the corrective actions taken and any preventativ e measures adopted to operate the device within that operating parameter; (iv) Records of any instances in which the pilot f lame 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 p reventative 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 opera tional; 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 pr oduction facility, a demonstration of compliance wi th 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 tim e that the pit flare is operating. The records mus t 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 w as temporarily infeasible for the current calendar month plus the previous consecutive eleven (11) cal endar months; and (iii) Brief descriptions of the justification for e ach 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 meas ures 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 re cords must include, at a minimum, the following75

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 r equired by this section onsite at the facility or a t the location that has day-to-day operational control ov er 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 documen ts required under this section to:

U.S. Environmental Protection Agency Region 8 Office of Enforcement, Compliance & Enviro nmental 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 c over 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 g as well at each oil and natural gas production facility or 1 y ear after [INSERT DATE OF PUBLICATION IN76

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 re port 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 t he reporting period. (1) The company name and the address of the oil an d natural gas production facility or facilities. (2) An identification of each oil and natural gas production facility being included in the annual re port. (3) The beginning and ending dates of the reportin g period. (4) For each oil and natural gas production facili ty, the information in § 49.147(b)(4)(i) through (i ii). (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 produc tion for each oil and natural gas well at each oil and natural gas production facility that commenced prod uction during the reporting period; and (iii) A summary of cases where construction or ope ration 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 oi l and natural gas production facility, and the correc tive measures taken.