1 

Technical Support Document 

Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; 

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

North Dakota 

Docket Number: EPA-R08-OAR-2012-0479 

FRL-9710-4 

SAN#: 5650 

I. Introduction 

The Environmental Protection Agency Region 8 (EPA1

) proposes to promulgate a Federal 

Implementation Plan (FIP) under the Clean Air Act (CAA) for existing, new, and modified oil and 

natural gas production facilities constructing and operating on the Fort Berthold Indian Reservation 

(FBIR). This FIP proposes to establish federally enforceable requirements to control volatile organic

compound (VOC) emissions from oil and natural gas production activities. The FIP proposes to require 

owners and operators of oil and natural gas well production facilities to reduce the VOC released during 

the production and storage of hydrocarbon reservoir fluids prior to being transferred off site for sale or 

treatment. This rule will be implemented by us (or by the Mandan, Hidatsa, and Arikara Nations, if 

delegated Tribal authority) until replaced by an EPA-approved Tribal Implementation Plan (TIP). 

This rule, when promulgated, will be an important step in ensuring that basic air quality protection is in 

place to protect health and welfare on the FBIR and at the same time would allow continued and 

unhindered development of the mineral resource, which provides significant economic benefits to the 

Tribal communities through royalties and increased job opportunities. We worked with the Three 

Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nations to identify the primary oil and natural gas 

production-related sources of air pollution emissions on the FBIR, and evaluate the CAA statutory 

authorities available to regulate those facilities. Our evaluations identified concerns with unregulated 

VOC emissions from oil and natural gas production operations. 

II. Description of the Affected Equipment 

During typical oil and natural gas production operations on the FBIR, a comingled fluid stream 

(containing produced oil, natural gas and water) flows from each drilled well to a respective vertical

separator and heater/treater processing unit. In the vertical separator and heater/treater processing unit, 

the fluid is heated to a desired temperature range to aid in separation of the oil, natural gas and produced 

water. This treatment at the wellhead removes impurities and separates the phases to best meet sales 

delivery specifications for oil and natural gas. The separated produced oil and produced water then 

flows to respective storage tanks. Oil is temporarily stored in these on-site storage tanks prior to being 

transferred either to tanker trucks or to a lease automatic custody transfer (LACT) unit for conveyance to 

 

1

 Throughout this document, “we” “us” and “our” refer to the EPA.
 

2 

a refining process plant. Separated water is temporarily stored in the on-site storage tanks prior to being 

loaded into tanker trucks for transport and disposal. 

The produced natural gas stream from the vertical separator and heater/treater processing unit can be 

metered into a natural gas sales pipeline if the pipeline infrastructure is available. If a pipeline is not 

available, the FIP requires the natural gas emissions be directed to an enclosed combustor or utility flare 

for combustion with 98% destruction efficiency. During the initial well completion and well pad2

construction phase of up to 90 days, or in the event that natural gas recovered for pipeline injection must 

be diverted to an emergency control device because injection is temporarily infeasible and the enclosed 

combustor or utility flare installed at the facility is not operational, the FIP allows the natural gas 

emissions to be directed to a pit flare for combustion with 90% destruction efficiency. 

Working, breathing (or standing), and flashing losses from the produced oil storage tanks, and any 

produced water storage tanks interconnected with the produced oil storage tanks, are captured through a 

common closed-vent piping system. Working losses occur when vapors are displaced due to the 

emptying and filling of produced oil and water storage tanks. Breathing losses are the release of natural 

gas from produced oil and water storage tanks associated with daily temperature fluctuations and other

equilibrium effects. Flash losses occur when a liquid with entrained natural gases are transferred from a 

vessel with higher pressure (e.g. heater/treater) to a vessel with lower pressure (produced oil and water 

storage tanks). The FIP requires the natural gas emissions from the storage tanks be routed to a utility 

flare or enclosed combustor with 98% destruction efficiency. If the operator determines it is 

economically feasible to use a vapor recovery device capable of reducing the mass content of VOC in 

the natural gas by 98% to capture the produced natural gas for beneficial purposes, the produced natural 

gas may be directed into a natural gas sales pipeline or facility fuel line. Additionally, the FIP allows 

owners or operators to use utility flares, enclosed combustors, or pit flares that are capable of reducing 

the mass content of VOCs in the storage tank natural gas emissions by only 90.0% if the total 

uncontrolled potential VOC emissions from all produced oil storage tanks and produced water storage 

tanks interconnected with the produced oil storage tanks are less than 20 tons in any consecutive 12-

month period. 

III. Purpose of Rule 

1. Regulatory Gap: 

In 1987, the North Dakota Department of Health (NDDoH) promulgated rules for Control of Organic 

Compound Emissions and Control of Emissions from Oil and Gas Well Production Facilities requiring 

combustion of produced natural gas and natural gas emissions created during oil and natural gas well 

completion, production and storage operations.3

 Additionally, regulations under the authority of the 

 

2

 A well pad is an oil and natural gas production facility that consists of one or more wells and production and storage 

operations 

3

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

http://www.legis.nd.gov/information/acdata/html/33-15.html: EPA-Approved Regulations, Subpart JJ – North Dakota, 40 

CFR Section 52.1820 Identification of Plan, Chapter 33-15-07 Control of Organic Compound Emissions, approved and 

Chapter 33-15-20-04 Control of Emissions from Oil and Gas Well Production Facilities, June 26, 1992. 
 

3 

North Dakota Industrial Commission (NDIC)4

 were established for similar purposes and require 

combustion of produced gas during oil and natural gas well drilling and completion. These enforceable

requirements allow oil and natural gas production facilities in the NDDoH’s jurisdiction to take into 

account the emission reductions achieved from combustion of the associated produced natural gas and 

natural gas emissions when calculating their potential-to-emit (PTE) to determine the applicability of

permitting requirements. 

This has resulted in a situation where many oil and natural gas production facilities in NDDoH 

jurisdiction are not required to obtain Prevention of Significant Deterioration (PSD) permits prior to

construction or Title V permits after operations commence. In addition, rules such as the NDDoH rule 

for the control of VOC emissions from oil and natural gas production facilities provide protection of the 

air quality in their jurisdiction. However, outside of New Source Review (NSR) permitting, there are no 

permitting mechanisms or applicable federal regulations that provide similar air quality protection or

allow oil and natural gas production facilities operating on the Fort Berthold Indian Reservation to take 

into account emission controls already in use. 

One exception is that certain produced oil and water storage tanks at these facilities may be subject to 

the recently finalized New Source Performance Standards for Crude Oil and Natural Gas Production, 

Transmission, and Storage (NSPS OOOO) and revised National Emission Standards for Hazardous Air 

Pollutants from Oil and Natural Gas Production Facilities (MACT HH)5

. When calculating PTE for the 

purposes of applicability to major source PSD and Title V permitting requirements for oil and gas 

production facilities on the FBIR, owners and operators cannot generally account for combustion of the

VOC emissions from well completion, production or storage activities if there is no required enforceable 

control, even though combustion of VOC-containing produced natural gas and natural gas emissions is 

standard practice to protect the health and safety of the operator personnel. Owners or operators must, 

therefore, calculate PTE for the purposes of determining applicability to federal permitting requirements 

as if the combustion units were not installed and the VOCs were directly vented to the atmosphere. 

When calculating the PTE of VOCs from the oil and natural gas production facilities on the FBIR and 

taking into consideration the factors of enforceability discussed above, the owners and operators have

concluded that the facility-wide PTE of VOCs for many existing, new, or modified oil and natural gas 

production facilities exceed the major source PSD and/or Title V emission thresholds of 250 tpy and 

100 tpy, respectively. As a result, Consent Agreement Final Orders (CAFOs) were finalized between us 

and select operators on the FBIR in late August 2011 and amended, in some cases, between then and 

July 2012 to establish federally enforceable requirements at oil and natural gas production facilities

listed in the CAFOs. These orders established control requirements during the life of the orders for 

facilities operating on the FBIR by these companies who voluntarily entered into the agreement with us. 

One goal of this FIP for existing oil and natural gas production facilities is to provide an avenue to

 

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

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

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

5

The requirements in NSPS OOOO and revised MACT HH have been finalized but not yet promulgated and can be found at 

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

4 

compliance with the CAA to those companies prior to the expiration of the CAFOs between 

August 26, 2012 and August 31, 2012. Copies of all of the CAFOs can be found in the docket for the 

rule. 

2. Permitting Limitations: 

On August 31, 2011, a minor source preconstruction permitting program for owners and operators 

proposing to construct minor sources in Indian Country, or Federal Tribal NSR Rule6 became effective. 

In addition to providing us with the authority to regulate proposed minor sources in Indian Country, the 

rule established a permitting mechanism for major sources that wish to voluntarily limit emissions to 

become synthetic minor sources for purposes of avoiding the major source permitting requirements 

under the Clean Air Act7. 

Owners and operators of new major sources of regulated air pollutants may not commence construction 

until obtaining a permit under the Clean Air Act. As an alternative to the major source permitting 

requirements for VOC emissions, many owners and operators currently operating on the FBIR are 

opting to apply for synthetic minor NSR permits under the Federal Tribal NSR Rule to obtain the 

federally enforceable requirements that would recognize the use of the controls already being used by 

the industry. The Federal Tribal NSR rule provides a mechanism to obtain synthetic minor permits, a 

process that allows us up to one year to take a final action (issue or deny) on an application for a 

synthetic minor permits. This has caused concerns that development of oil and natural gas resources on 

the FBIR could be slowed. 

To date, we have received such a great volume of applications for oil and natural gas production 

facilities on the FBIR, with hundreds more anticipated, that the need became apparent for a federally 

enforceable mechanism for operators to take into account the emissions reductions that were actually 

occurring or would occur from the combustion of the associated produced gas and natural gas emissions.

3. Identification of Sources of VOC Emissions 

The EPA has received more than 350 synthetic minor permit applications for proposed major oil and 

natural gas production facilities on the FBIR since the effective date of the Federal Tribal NSR Rule. A 

review of these applications showed that owners and operators are primarily producing reservoir fluids

from the Bakken and Three Forks formation on the FBIR. There is an unusually high concentration of 

natural gases containing VOCs being produced in conjunction with crude oil production operations on 

the FBIR. This is due to the high volatility of the reservoir fluids of the Bakken Pool8 from which the 

operators on the FBIR are extracting the crude oil. 

 

6

40 CFR Parts 49 and 51 Review of New Sources and Modifications in Indian Country; 76 FR 38748 (July 1, 2011).

7

 The requirement to obtain major source preconstruction permits under the Prevention of Significant Deterioration (PSD) 

regulations at 40 CFR Part 52; and the requirement to obtain major source operating permits under the Title V permitting 

programs at 40 CFR Part 71. 

8

 Oil from Bakken, Three Forks, and Sanish Formations. 
 

5 

Summarized below, we reviewed information compiled by the NDDoH in development of their Bakken 

Pool Oil and Gas Production Facilities Air Pollution Control Permitting and Compliance Guidance, 

effective May 2, 20119 (Bakken Pool Guidance) to further evaluate VOC emissions from oil and natural 

gas production facilities on the FBIR. According to the Bakken Pool Guidance, crude oil from the 

Bakken Pool typically contains a high amount of lighter end VOC components which have the potential 

to produce increased volumes of flash emissions compared to typical oil production wells. Because of 

this, customary correlations such as API’s E&P Tanks and Vasquez-Beggs do not work well for 

estimating flash vapors in the Bakken Pool, potentially overestimating and underestimating emissions. 

The NDDoH recognized the need to predict tank natural gas emissions from Bakken Pool oil and natural 

gas production facilities to determine applicability to air pollution control permitting programs. The 

NDDoH collaborated with owners and operators of oil and gas production operations and formed the 

Bakken VOC Task Force. The Goals of the Bakken VOC Task Force were to: (1) gather direct 

measurement data collected by various owners/operators within the Bakken Pool; (2) establish an 

emission factor that could be used to predict tank natural gas emissions from producing Bakken Pool 

formation wells; (3) to evaluate available emission control technologies; and (4) to recommend the best 

emission control for different emission scenarios. 

Typically, the natural gases associated with the produced oil would be captured as product and injected 

directly into a natural gas sales pipeline, thus alleviating the emission of VOCs that are in the natural 

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

developed, they are minimally available at this time. 

We reviewed information provided in 154 of the applications for synthetic minor NSR permits. 10 Based 

on these applications, we were able to determine that the most significant source of the VOC emissions

is from the equipment that handles natural gases produced along with the crude oil during well 

completions, phase separation of the extracted reservoir fluids (production), and the temporary storage 

of the crude oil. Due to the high VOC content of the produced natural gas and natural gas emissions 

from the Bakken Pool, uncontrolled emissions of VOCs on the FBIR may have a potentially significant 

impact on the environment. We determined that on average, the emissions from production equipment 

related to each individual oil and natural gas well has the PTE approximately 2,165 tons per year (tpy) 

of VOC where there are no natural gas sales pipelines for the associated natural gases and no federally 

enforceable requirements to control VOC in the natural gas. This is what led to the influx of synthetic 

minor NSR permit applications to us. Of this total, approximately 1,611 tpy of VOC results from 

produced natural gas emissions from the heater/treater and 554 tpy of VOC is emitted from the produced

oil and water storage tanks. 

We believe that it is appropriate to focus initially on the oil and natural gas production operations that 

have been identified as having the greatest potential to impact future air quality on the FBIR and in 

shared airsheds of North Dakota. Based on a review of the air quality status on the FBIR, we 

 

9 Bakken Pool Oil and Gas Production Facilities Air Pollution Control Permitting & Compliance Guidance, North Dakota 

Department of Health Air Quality Division, May 2, 2011. 

10 The applications 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. 
 

6 

determined that VOC emission control requirements for well completions and production and storage 

operations are appropriate for this FIP. 

4. Reasonably Foreseeable Development 

In an effort to determine future development likely to occur on the FBIR, we evaluated the October 2, 

2009 Bureau of Land Management (BLM) report titled “Reasonable Foreseeable Development Scenario 

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

supplemented on February 25, 2011 with the document titled “Revised Activity and Surface Disturbance 

Projections for the Reasonable Foreseeable Development Scenario for Oil and Gas Activities on Bureau 

Managed Lands in the North Dakota Study Area”. Both documents are included in the docket for this 

rule and are publicly available at the following website: 

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

The FBIR is located entirely within the North Dakota study area that was evaluated by BLM in the 

reports. Therefore, it was possible to obtain the oil and natural gas development potential for projected 

pad densities and associated wells for the FBIR from information in the reports. Based on the projected 

pad densities in the 2011 supplemental report, we determined the potential for oil and natural gas 

development on the FBIR was approximately 990 well pads during the report planning period of 2010 to 

2029. Although the BLM report estimated an average well density of 1.5 wells per pad, we used a value

of two wells per pad to provide a conservative estimate of well pad density in future development. We

believe the average of two wells per pad to be representative of typical operations on FBIR, based on 

information from synthetic minor permit applications and environmental assessments conducted by the 

Bureau of Indian Affairs11. Thus, we concluded that reasonably foreseeable development on the FBIR 

would consist of approximately 2,000 wells or 1,000 well pads between 2010 and 2029. 

5. Development of Requirements 

a. Review of Comparable State Air Agencies’ Rules or Guidance

In order to determine what level of control would effectively fill the regulatory and air quality protection 

gap between our CAA jurisdiction on the FBIR and the NDDoH’s CAA jurisdiction elsewhere in North 

Dakota, we reviewed the regulations under the North Dakota State Implementation Plan (SIP) for Air 

Pollution control12. We also reviewed the NDDoH Bakken Pool Guidance and NDIC regulations13. 

 

11 A document containing our analysis of well pad densities from multiple environmental assessments 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. 

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

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

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

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

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

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

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

7 

Lastly, we reviewed other state oil and natural gas production-related regulations in Region 8 for areas 

that are similar to North Dakota in industry, meteorology, or air quality concerns to ensure the proposed 

requirements are reasonably achievable, because the control technologies are being commonly used and 

regulated. 

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

Department of Environmental Quality (MDEQ)14, Wyoming Department of Environmental Quality Air 

Quality Division (WDEQ)15, Colorado Department of Public Health and Environment Air Pollution 

Control Division (CDPHE)16 and the Utah Department of Environmental Quality (UDEQ)17. We also 

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

Code, implemented by the Railroad Commission of Texas, Oil and Gas Division (RCT)18, the New 

Mexico Environment Department Air Quality Bureau (NMED)19, and the Oklahoma Department of 

Environmental Quality Air Quality Division (ODEQ)20. However, we determined that it was not 

relevant to review state rules that are intended to address non-VOC pollutant emissions, nonattainment

area requirements, or specific localized air quality concerns unless such concerns are also present on the 

FBIR or control equipment requirements apply to the same emission units this FIP seeks to address. 

Copies of all the state and local agency rules that we considered in this process and other supporting

documentation are included in the docket for this rule. 

 

14 Montana Department of Environmental Quality. Chapter 8 Air Quality Subchapter 16 Emission Control Requirements for 

Oil and Gas Well Facilities Operating Prior to Issuance of a Montana Air Quality Permit. Available online at: 

http://www.deq.mt.gov/dir/legal/chapters/CH08-16.pdf. Accessed May 29, 2012. State only rule. 

15 Wyoming Department of Environmental Quality Air Quality Division. Oil and Gas Production Facilities Chapter 6, 

Section 2 Permitting Guidance, March 2010. Available online at: 

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

29, 2012. State only guidance. 

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

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

Oxides) 5-CCR 1001-9, Section XII – Volatile Organic Compound Emissions from Oil and Gas Operations. Available online 

at: http://www.cdphe.state.co.us/regulations/airregs/5CCR1001-9.pdf. Accessed May 29, 2012. State only rule. 

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

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

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

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

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

only rule. 

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

Facilities. New Mexico Commission of Public Records, New Mexico Register. Available online at: 

http://www.nmcpr.state.nm.us/nmac/_title20/T20C002.htm. Accessed May 29, 2012. State only rule. 

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

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

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

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

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

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

8 

Table 1: Summary of VOC Limitations in Comparable State Rules or Guidance

Rule or Guidance VOC Limitations for Oil and Natural Gas Production 

Operations 

NDDoH - ND Century Code (SIP) – 

Chapter 23-25 Air Pollution Control, Air 

Pollution Control Rules, Article 33-15, 

Chapter 33-15-07 Control of Organic 

Compounds Emissions and Chapter 33-15-

20 Control of Emissions from Oil and Gas 

Well Production Facilities 

Except for emergency vapor blowdown or relief systems, VOC 

emissions must be burned by flares or an equally efficient control 

device before being released to the ambient air. Each flare must be 

equipped with automatic ignition system or continuous burning 

pilot. Each water separator of petroleum products must be equipped 

with a closed-vent system and combustion device as specified by 40 

CFR 60.691 (subpart QQQ). 

NMED New Mexico Administrative Code 

Title 20, Chapter 2, Part 38 Hydrocarbon 

Storage Facilities 

If total tank battery storage for a petroleum production facility 

exceeds 65,000 gallons, each hydrocarbon liquid tank must be 

equipped with: 

(1) a floating roof, consisting of an external floating roof, internal 

floating cover or covered floating roof, which is equipped with a 

closure seal or seals maintained in good repair to close the space 

between the roof or cover edge and tank wall; or 

(2) a well-maintained vapor-recovery system consisting of a vaporgathering system capable of collecting the organic compound vapors 

and natural gases 

Discharged and a vapor-disposal system capable of collecting the 

organic vapor and natural gases so as to minimize their 

emission to the atmosphere; or 

(3) any other device which is at least as effective to minimize vapor 

or natural gas loss to the atmosphere. 

CDPHE AQPD Air Quality Control 

Commission Regulation Number 7, 

Section XII – Volatile Organic Compound 

Emissions from Oil and Gas Operations 

If actual uncontrolled VOC emissions from oil and condensate 

storage tanks is predicted for the first 12 months based on data from 

the first 90 days after the first date of production are predicted to be 

100 tpy or greater, control for the first 90 days after the first date of 

production after the tank was newly installed, or after the well was 

newly drilled, re-completed, re-fractured or otherwise stimulated, 

using enclosed combustors that achieve 95% VOC destruction. 

Enclosed combustors must be equipped with auto-ignitor, and 

operated in smokeless mode by first date of production, and contain 

a surveillance system to document presence of pilot flame. Operate 

control equipment according to manufacturer recommendations and 

conduct weekly tank and control device inspections.
 

9 

Rule or Guidance VOC Limitations for Oil and Natural Gas Production 

Operations 

North Dakota Industrial Commission 

(NDIC) – ND Century Code Chapter 38-08 

Control of Oil and Gas Resources: Article 

38-08-06.4. Flaring of Gas Restricted - 

Imposition of Tax - Payment of 

Royalties - Industrial Commission 

Authority; and Article 43-02-03-28 

Safety Regulation.

NDDoH - Bakken Pool Oil and Gas 

Production Facilities Air Pollution Control 

Permitting & Compliance Guidance (pages 

39-43) 

Control Requirements for Heater-Treater Gas 

Heater-treater natural gas must be routed to a natural gas gathering 

pipeline as soon as practicable in accordance with the NDIC 

requirements. When a pipeline is not available, heater-treater 

natural gas is required to be routed to a control system or device. 

Control Requirements for Storage Tanks 

VOC and HAP emissions from all active produced water tanks VOC 

and HAP emissions shall be controlled by at least 90% within 60-

days after the first date of production. Produced oil and water tanks 

must be controlled by at least 90 percent if combined PTE declines 

to < 20tpy. If combined VOC PTE > 20tpy, tank VOC and HAP 

emissions must be controlled by at least 98% by weight. 

Acceptable VOC Control Systems or Devices: 

Pit flare or other 90% DRE or greater device, equipped with auto 

ignior, at a minimum; 

VRU or oil stabilizer on storage tanks capable of reducing VOC and 

HAP emissions by at least 99% by weight; 

Enclosed smokeless combustion device or utility flare designed and 

operated to reduce the mass content of VOC and HAP by at least 

98% by weight. Must be equipped with auto ignitor or continuous 

burning pilot with thermocouple. Daily checks for proper operation 

or flame presence. 

Operate all air pollution control equipment in accordance with 

manufacturer recommendations and good air pollution control 

practice for minimizing emissions. 

MDEQ Chapter 8 Air Quality, Subchapter 

16 Emission Control Requirements for Oil 

and Gas Production Facilities Operating 

Prior to Issuance of a Montana Air Quality 

Permit 

VOC vapors greater than 500 BTU/scf from oil and natural gas 

wellhead equipment must be routed to a natural gas pipeline, or, if a 

natural gas pipeline is not located within a 1/2 mile of the oil and 

natural gas well facility, VOC vapors greater than 500 BTU/scf 

must be captured and routed to emissions minimizing technology or 

to a smokeless combustion device equipped with an electronic 

ignition device or a continuous burning pilot system; 

VOC vapors greater than 500 BTU/scf from oil and condensate 

storage tanks with the PTE of 15 TPY or greater must be captured 

and routed to a natural gas pipeline, or if a natural gas pipeline is not 

located within a 1/2 mile of the oil and natural gas well facility, 

VOC vapors greater than 500 BTU/scf from storage tanks with the 

PTE of 15 TPY must be captured and routed to emissions 

minimizing technology, or to a smokeless combustion device 

equipped with an electronic ignition device or a continuous burning 

pilot system; 
 

10 

Rule or Guidance VOC Limitations for Oil and Natural Gas Production 

Operations 

WDEQ Oil and Gas Production Facilities, 

Chapter 6, Section 2 Permitting Guidance 

New Facilities 

Within 60-days of the First Date of Production (FDOP), flashing 

emissions containing greater than or equal to 10 TPY VOC shall be 

controlled by at least 98%. 

Modified Facilities 

Within 60-days of modification, new and existing flashing 

emissions containing greater than or equal to 10 TPY VOC shall be 

controlled by at least 98%. 

New and Modified Facilities 

Condensate and oil tanks that are on site for use during emergency 

or upset conditions, such as spare tanks at facilities connected to 

liquids gathering systems, are not subject to the 98% control 

requirements. 

The removal of flashing emissions control devices may be allowed 

upon approval after one year if VOC flashing emissions have 

declined to less than, and are reasonably expected to remain below 8 

TPY.

ODEQ Title 252 Chapter 100 Air Pollution 

Control, Subchapter 37 Control of 

Emission of Volatile Organic Compounds 

VOC vessels of 400 gallons or greater shall be equipped with 

permanent submerged fill piping or a vapor recovery system. 

Texas Administrative Code, Title 16 

Economic Regulation, Part I Railroad 

Commission of Texas, Chapter 3 Oil and 

Gas Division. 

All natural gas releases greater than 24 hours duration burned by 

flare if safe. 
 

11 

Rule or Guidance VOC Limitations for Oil and Natural Gas Production 

Operations 

UDEQ Utah Administrative Code, Rule R649-3 Drilling and Operating Practices (-

20 Gas Flaring or Venting) 

Produced natural gas from oil wells may be flared or vented only 

in the following amounts: 

• Up to 1,800 MCF from an individual well on a monthly 

basis at any time without approval. 

• During the period of time allowed for conducting the 

stabilized production test or other approved test, the 

operator may vent or flare all produced oil well natural 

gas as needed for conducting the test. 

• During the first calendar month immediately following 

the time allowed for conducting the initial stabilized 

production test operator may vent or flare up to 3,000 

MCF of oil well natural gas without approval. 

• Unavoidable or short-term oil well natural gas venting 

or flaring may occur without approval. 

Upon well completion and first date of production, unavoidable 

or short-term gas venting or flaring is allowed without approval 

only in the following cases: 

• Anytime unless the division determines that the 

recovery of such vapors is warranted. 

• During emergencies if shutting in or restricting 

production from the well would cause waste or create 

adverse impact on the well or producing reservoir. 

• During periods of well purging or evaluation tests not 

exceeding a period of 24 hours or a maximum of 144 

hours per month. 

Greater amounts of produced natural gas may be flared upon 

written approval. 

b. Comparison of Proposed Rule Requirements to State Rules and Guidance

We drafted requirements that mirror to the greatest extent practicable the most relevant aspects of the 

state rules and guidance reviewed for oil and natural gas production facilities and determined a level of 

control that equalizes requirements and air quality protections across jurisdictional borders yet ensures 

the enforceability required for a federal rule. Therefore, the proposed rule focuses primarily on 

mirroring NDDoH requirements for oil and natural gas production facilities. The proposed rule is not as 

restrictive as some of the most stringent state and local rules for the same class of sources or activities; 

likewise, it is not as lenient as some of the least stringent of the state and local rules. Nor does the 

proposed rule look like state or local rules because it uses the federal regulatory structure and is written 

in a “plain language” format in accordance with the Plain Writing Act of 201021

. 

 

21 Plain Writing Act of 2010, Pub. L. No. 111-274, § 105, 124 Stat. 2861 (2010). 
 

12 

It is important to note that this FIP is analogous to, but different from, the rules for oil and natural gas 

production facilities within the jurisdiction of the NDDoH. The rule proposed today is somewhat more 

stringent than North Dakota’s SIP rules for oil and natural gas production sources with regard to 

monitoring, recordkeeping and reporting required by the CAA. However, while this is a Federal CAA 

rule, it does not change the minimum criteria in 40 CFR Part 51, the CAA, or the TAR for approval of 

rules in either a SIP or a TIP.22 We encourage the Three Affiliated Tribes of the Mandan, Hidatsa, and 

Arikara Nations to develop an individual TIP and will work with the Three Affiliated Tribes of the 

Mandan, Hidatsa, and Arikara Nations if they seek to replace this rule with a TIP. This regulation will 

apply until it is replaced by Tribal regulations in an approved TIP. 

c. Applicability

Applicability of this proposed rule is in Section 49.140 – Introduction. This rule is intended to regulate 

VOC emissions in natural gases released during the completion and recompletion of oil and natural gas 

wells, and the production and storage of crude oil on the FBIR. Specifically, VOC-containing produced

natural gas released from the casing head of each well during completions and all recompletions, VOCcontaining produced natural gas released from each separator and heater-treater in the production 

process, and VOC-containing natural gas emissions released from each produced oil and each produced 

water storage tank due to breathing (standing), working, and flashing loss emissions. 

The proposed rule applies to: 

(1) Each owner or operator constructing or operating an oil and natural gas production facility 

producing from the Bakken Pool with one or more oil and natural gas wells, for any one of 

which completion operations are/were performed on or after August 12, 2007, that is located on 

the FBIR which is defined by the Act of March 3, 1891 (26 Statute 1032) and which includes all 

lands added to the Reservation by Executive Order of June 17, 1892 (the “Fort Berthold Indian 

Reservation”); and 

(2) Each owner or operator constructing or operating an oil and natural gas production facility with 

one or more oil and natural gas wells, for any one of which recompletion operations are 

performed after the date of publication in the code of federal regulations or after August 3, 2012 

for owners or operators that were provided actual notice by EPA, that is located on the FBIR. 

For the purposes of this rule, a well completion means the process that allows for the flowback of oil and 

natural gas from newly drilled wells in order to expel drilling and reservoir fluids and test the reservoir 

flow characteristics, which may vent VOC to the atmosphere via an open pit or tank. A well completion

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

and natural gas production facility. The completion date is considered the date that construction at an oil 

and natural gas production facility has commenced. A well recompletion operation means any oil and 

natural gas well completion with hydraulic refracturing occurring at an oil and natural gas production

facility. The recompletion date is considered the date that a modification has occurred at an oil and

 

22 EPA has used the planning requirements applicable to States as a guide in developing this FIP.
 

13 

natural gas production facility. The reason we selected the initiation of completions operations as the 

date for defining a new facility is that owners and operators use drill rigs prior to initial completion 

operations and this equipment is not considered a stationary source. In addition, it is not certain during 

the drilling operations whether a well will be a producing well. Hence it is not known whether an oil

and natural gas production facility will be constructed to support that well. The outcome of a 

completion operation provides the well owners and operators information necessary to determine 

whether an oil and gas production facility will be constructed. Requiring compliance with this rule upon 

recompletion of any one well at a facility is consistent with NSPS OOOO. According to the final NSPS 

OOOO notice, a completion operation associated with refracturing is considered a modification under 

CAA section 111(a), because physical change occurs to the well resulting in emissions increases during

the recompletion operation (for the purposes of this rule the process of refracturing is defined as a 

recompletion). 

In deciding the effective date and the well completion dates for applicability, we evaluated the purpose 

of the rule, the gaps in regulations, NSPS OOOO and the requirements and stipulations of the CAFOs. 

The August 12, 2007, date is the earliest well completion date identified in the CAFOs. 

d. VOC Emission Reduction Requirements

Section 49.143 – Construction and Operational Control Measures would restrict VOC emissions from 

oil and natural gas production well completion operations by at least 90% at all times. We note that the 

well completion and recompletion control requirements to use pit flares or utility flares that have the 

capability to reduce the mass content of VOC in the natural gas emissions routed to them by at least 90.0 

percent by weight are the minimum level of control that would be allowed under this rule. Owners and 

operators may also choose to perform reduced emission completions and recompletions23, which would 

exceed the 90.0 percent VOC emission reduction requirement. 

Section 49.143 would also restrict VOC emissions from phase separation of the reservoir fluids and 

from working, standing, breathing and flashing loss natural gas emissions from temporary on-site 

produced oil and water storage by at least 98.0 % at all times within 90 days after production 

commences, with the exception that at least 90.0 % control is allowed in the event the natural gas that is 

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

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

not operational, or if total uncontrolled potential emissions of VOC from all produced oil storage tanks 

and any produced water storage tanks interconnected with produced oil storage tanks have declined to 

less than, and are reasonably expected to stay below, 20 tons in any consecutive 12-month period. We 

developed the provision for the last exception for consistency with the NDDoH Bakken Pool Guidance. 

In comparison, once promulgated, NSPS OOOO will require 95% VOC emission reduction from storage 

tanks emitting greater than or equal to 6 tpy each of VOCs. Tanks emitting less than 6 tpy VOC will not 

 

23 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners: Reduced Emissions 

Completions for Hydraulically Fractured Natural Gas Wells. Office of Air and Radiation: Natural Gas Star Program. 

Washington, DC. Available at: http://epa.gov/gasstar/documents/reduced_emissions_completions.pdf. Accessed July 26, 

2012. 
 

14 

require controls. We justified the 20 tpy threshold for storage tanks in aggregate based on information 

we contained in the synthetic minor NSR applications we received which indicates a typical oil and 

natural gas facility requires an average of 4 tanks per well. Therefore, the storage tanks at a one well 

facility, would need to emit less than 6 tpy VOCs each in order to take advantage of the provision. 

Consequently, each tank at a multi-well facility would need to emit even less than 6 tpy in order to take 

advantage of the provision. 

We determined that certain operational requirements are necessary for the practical enforceability of the 

VOC emission reduction requirements. We propose work practice and operational requirements that 

include, but are not limited to: 

(1) On the first date of production from any oil and natural gas production well, at a minimum, route 

all produced natural gas and natural gas emissions from that well to a control device capable of 

at least 90.0% VOC destruction efficiency, based on the site-specific design, written operating 

instructions, and operating procedures of the pit flare; 

(2) Within ninety (90) days of the first date of production from any oil and natural gas production 

well, use of a closed-vent vapor recovery system designed to recover and route the produced 

natural gas from the separator and heater/treater processing unit to one of the following: 

i. Operating equipment designed to inject it into the pipeline system for sale or other 

beneficial purpose; or 

ii. An enclosed combustor or utility flare with VOC emission destruction efficiency of at 

least 98%, based on the typical manufacturer specifications or engineering design of 

enclosed combustors or utility flares. 

(3) Use of a closed-vent vapor recovery system and enclosed combustor or utility flare with VOC 

emission destruction efficiency of at least 98.0% for natural gas emissions from each produced 

oil storage tank and any produced water storage tank interconnected with the produced oil 

storage tanks, based on the typical manufacturer specifications or engineering design of 

enclosed combustors or utility flares. If the actual uncontrolled VOC emissions from the 

aggregate of all produced oil storage tanks and any produced water storage tanks interconnected 

with produced oil storage tanks at an oil and natural gas production facility is less than, and 

reasonably expected to remain below, 20 tons in any consecutive 12-month period, then the 

owner or operator may use a utility flare or enclosed combustor that is capable of reducing the 

mass content of VOC in the natural gas emissions vented to the device by only 90.0% upon 

written approval by us. 

(4) In the event the natural gas that is being recovered for sale or other beneficial purpose must be 

diverted to an emergency control device because injection into the pipeline is temporarily 

infeasible and the enclosed combustor or utility flare installed at the oil and natural gas 

production facility is not operational, route all produced natural gas emissions from the separator 

and heater/treater processing unit or natural gas emissions from the produced oil storage tanks to 
 

15 

a pit flare capable of at least 90.0% destruction efficiency based on the site-specific design, 

written operating instructions, and operating procedures of the pit flare. 

We note that owners and operators of oil and natural gas production facilities on the FBIR have 

indicated that a 90.0 % VOC destruction efficiency in the Bakken Pool Guidance is achievable using a 

pit flare and committed in their synthetic minor NSR applications to reduce the mass content of VOC 

emissions routed to a pit flare by at least 90.0% by weight. We also note that while NSPS OOOO 

requires 95% VOC reduction of emissions from storage tanks emitting at least 6 tpy VOCs, owners and 

operators of oil and natural gas production facilities on the FBIR have indicated that a 98% VOC 

destruction efficiency in the Bakken Pool Guidance is achievable and committed in their synthetic minor 

NSR applications to reduce the mass content of VOC emissions routed to the enclosed combustors or 

utility flares used for both produced gas and storage tank control of at least 98.0% by weight. The 20 

tpy VOC storage tank total emissions threshold for allowing 90.0 % VOC emission reduction instead of 

98.0% is consistent with the NDDoH’s Bakken Pool Guidance, except that we require the operator to 

develop written operating instructions, operating procedures and maintenance schedules for any pit flare 

used under this provision based on the site-specific design of the pit flare. 

Regarding state regulations and guidance other than NDDoH, the NDIC, WDEQ, MDEQ, UDEQ and 

RCT also require or at least allow flaring or combustion of casinghead natural gas, produced natural gas, 

and produced oil and water storage tank loss natural gas emissions when a vapor recovery system and 

sales pipeline are not feasible. The NDIC requires heater-treater natural gas to be routed to a natural gas 

gathering pipeline as soon as practicable. When a pipeline is not available, heater-treater natural gas is 

required to be routed to a control system or device. The MDEQ specifically requires injection of 

produced natural gas and/or storage tank natural gas emissions into a sales pipeline if there is one within 

1⁄2 mile of the facility. The WDEQ requires 98% reduction of VOC flashing emissions from all storage 

tanks and separation vessels. 

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

those that might apply to the size tanks 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 proposed for construction and emission control of produced oil and 

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

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

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

requires 98% VOC reduction for tanks with a PTE greater than 10 tpy within 60 days of the first date of 

production, compared to 90 days in the proposed FIP. The WDEQ also allows control equipment 

removal if flashing emissions decline to and are reasonably expected to remain below 8 tpy. 

e. Monitoring Requirements

We determined that certain monitoring requirements are necessary for the practical enforceability of the 

VOC emission reduction requirements, including but not limited to: 
 

16 

(1) Monitoring of the barrels of oil produced at the facility each time the oil is unloaded from the 

produced oil storage tanks; 

(2) Monitoring of the volume of produced natural gas sent to an enclosed combustor, utility flare, or 

pit flare at all times; 

(3) Monitoring of the volume of working, breathing (or standing), and flashing natural gas 

emissions from the produced oil and produced water storage tanks sent to vapor recovery system, 

enclosed combustor, utility flare, or pit flare at all times; and 

(4) Directly measuring, or calculating using our approved models, various parameters (i.e., product 

throughput, enclosed combustor flame presence, temperature, etc.) related to the proper 

operation of emissions units and required control devices to assure compliance with the 

emissions and operational limitations. 

(5) Visibility monitoring for detecting visible smoke from enclosed combustors, utility flares, and pit 

flares. 

The Bakken Pool Guidance is intended to address a wider range of pollutant emissions from oil and 

natural gas production facilities. The proposed FIP intends only to address VOC emissions at this time, 

which we determined are the reason many of these facilities exceed the major source PSD and/or Title V

permitting applicability thresholds. 

Regarding other state regulations and guidance reviewed for VOC destruction efficiency and monitoring 

of enclosed combustors and utility flares, the proposed FIP requirements are mostly consistent with all 

that specifically address those control equipment. Although CDPHE only requires 95.0 % VOC 

emission reduction from produced oil or water storage tanks, we chose a destruction efficiency of 98.0% 

in accordance with NDDoH regulations. 

f. Record Keeping Requirements

We propose that the applicant keep extensive records to be made available upon us request, in lieu of 

voluminous reporting requirements. The records to be kept include, but are not limited to, all required 

measurements, monitoring, and deviations or exceedances of rule requirements and corrective actions 

taken, as well as any manufacturer specifications and guarantees or engineering analyses. 

g. Reporting Requirements

We propose that the owner or operator of an oil and natural gas production facility subject to the FIP

submit an annual report each year covering the period for the previous calendar year. The report must

include a summary of all required records identifying each oil and natural gas production well 

completion or recompletion operation for each facility conducted during the reporting period, an 

identification of the first date of production for each oil and natural gas production well at each facility 

that commenced operation during the reporting period, and a summary of deviations or exceedances of 

any requirements of the FIP and the corrective measures taken. Additionally, a report shall be submitted 

for any required performance test. 

 
 

17 

IV. Cost of the rule 

We evaluated the cost impact of this rule for the control technologies required under the FIP. Copies of 

the synthetic minor permit applications, cost information, and associated supporting documentation that 

we considered in this process are included in the docket for this rule. 

1. Emissions Data 

We evaluated data from 154 synthetic minor permit applications containing 533 production wells among 

five of the main operators on the FBIR. From the applications, we were able to obtain the uncontrolled 

and controlled VOC emissions for each of the 154 facilities. Additionally, the data was analyzed to 

determine average emission rates for an individual well basis. Due to the variability in the production 

rates and product composition among the operators, we believe the mean value per well is an 

appropriate method for obtaining annual emissions. Average VOC emissions per well were evaluated 

against operating scenarios to determine cost impacts associated with the FIP. 

Generally, the provisions in the FIP provide operators with the ability to control produced natural gas 

emissions from the heater/treater during the initial phase of production (up to 90 days) with a pit flare 

capable of a 90% destruction efficiency. After 90 days, the FIP requires produced natural gas emissions 

be controlled with an enclosed combustor or utility flare capable of a 98% destruction efficiency if a

pipeline is not available. Natural gas emissions from storage tanks shall be controlled with an enclosed 

combustor or utility flare capable of 98% reduction. We applied the destruction efficiency above to the 

emissions data from the applications to obtain the amount of VOCs reduced on an annual basis for a 

single well. Additionally, we assumed that no pipelines were available in order to develop a worst-case 

scenario estimate of emissions from production and storage operations. We believe this is a 

conservative approach for cost analysis purposes because the costs to implement the control 

technologies required by the FIP may be reduced or even eliminated if pipeline infrastructure is 

available. Also, emission estimates are likely higher than actual emission rates due to the decline in 

production over time. Average VOC emissions in tpy for production and storage operations associated 

with an individual well on the FBIR are presented in Table 2 below.24

 

24 A summary of VOC emissions from application data titled “VOC Emissions Analysis from Syn Minor Application Data” 

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.
 

18 

Table 2- Average VOC Emissions for Single Well 

Parameter (per individual well) Average VOC Emissions 

(tpy) 

Produced natural gas (heater/treater) uncontrolled VOC emissions 1,610 

Storage tank uncontrolled VOC natural gas emissions 555 

Total uncontrolled VOC emissions 2,165 

Produced natural gas (heater/treater) controlled VOC emissions165 

Storage tank controlled VOC natural gas emissions 10 

Total controlled VOC emissions 75 

Total amount of reduction in VOC emissions due to controls 2,090 

1. Controlled produced natural gas heater/treater emissions calculated from 90% destruction efficiency for 90 days and 

98% destruction efficiency for the remaining 9 months of the year. 

2. Costs of Compliance 

We relied on cost estimates supplied by oil and natural gas operators on the FBIR for capital costs and 

annual costs associated with control technology provisions in the FIP.25 For each operator, the 

annualized capital cost was calculated by multiplying the total capital investment cost by the appropriate 

capital recovery factor (CRF) for the equipment life indicated by the operator.26, 27 In most cases, the 

equipment life for control devices was 10 years and had a CRF of 0.014238 based on a 7% interest rate. 

Because the equipment life for pit flares varied among operators, the appropriate CRF based on a 7% 

interest rate was used to determine the capital recovery costs. The annualized capital cost was then 

combined with the annual operating costs provided by the operator to obtain the total annual cost (TAC) 

for each piece of equipment. The average TAC was calculated for each type of equipment to provide a 

representative annual cost for the cost analysis.28 Equipment of concern in the cost analysis were pit 

flares, single-tip utility flares, dual-tip or tandem utility flares, enclosed combustors, auto-ignition 

systems, and continuous pilot systems. 

Due to variability in oil and natural gas operations on the FBIR among the production companies, we 

developed typical operating scenarios to evaluate the cost impacts associated with the FIP. We believe 

the scenarios analyzed are a conservative representation of realistic operations, based on input from the 

operators and knowledge of industry practice. Each scenario assumes that pipeline infrastructure is not 

available at the oil and natural gas production facility, or well pad, thereby requiring the combustion of 

waste natural gas from various emission sources. Although pipeline infrastructure does exist in areas of 

the FBIR, this assumption provides a worst-case cost impact analysis. Actual cost impacts of the FIP 

 

25 The cost estimates 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. 

26 EPA’s Control Cost Manual at page 2-41 (further referred to as CCM) Sixth Edition, January 2002, EPA 452/B-02-001. 

The CCM can be found at http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf. 

27 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF for a 7% interest rate based on 

the equipment life of the operator, as determined by Table A-2 in Appendix A to Chapter 2 of the CCM. The justification for 

using the CRF at a 7% interest rate can be found in Office of Management and Budget, Circular A-4, Regulatory Analysis, 

http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

28 The cost data analysis 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. 
 

19 

are expected to decrease over time as the pipeline infrastructure is further developed on the FBIR. The 

following operating scenarios were developed for the cost impact analysis: 

• Scenario A: A facility with one well requiring the use of a pit flare, single-tip utility flare, 

enclosed combustor, and two auto-ignition or continuous pilot system devices; 

• Scenario B: A facility with two or more wells requiring the use of a pit flare, single-tip utility 

flare, two enclosed combustors, and three auto-ignition or continuous pilot system devices; or 

• Scenario C: A facility with more than two wells requiring the use of a pit flare, dual-tip or 

tandem utility flare, and an auto-ignition or continuous pilot system. 

The average TAC for each operating scenario is presented below in Table 3. All costs are presented in

2012 dollars. 

Table 3 – Total Annual Cost for Operating Scenarios on the FBIR 

Operating Scenario Total Annual Cost1

Scenario A $35,750 

Scenario B $52,095 

Scenario C $59,975 

1. Total annual cost includes the calculated capital recovery based on the equipment life and 7% interest rate and annual 

operating costs provided by the operator. 

As indicated in Table 3, the TAC is higher for operating scenarios that utilize multiple combustors or

tandem utility flares. However, if the TAC is calculated on a per well basis, the TAC per well for 

operating Scenario B and C are lower than the TAC for operating Scenario A. Input from operators on 

the FBIR has indicated that as the volume of produced natural gas and natural gas emissions increases at 

facilities due to higher production volumes from more wells at the well pad, multiple enclosed 

combustors or tandem utility flares are utilized to reduce operating costs. We conservatively assumed

that an enclosed combustor can only process the natural gas emissions from a single well for destruction. 

Therefore, a two-well facility would require a minimum of two enclosed combustors. From the costs 

provided by the operators and the TAC for each operating scenario, we determined that it is typically 

more economical to use tandem utility flares at well pads consisting of three or more wells, although 

many factors may influence control device selection. Possible influences on control device selection 

may include the volume of produced natural gas and natural gas emissions at the facility, grouped 

installation and operating costs among multiple facilities, vendor pricing, safety and compliance 

regulations, or standardized operator preferences. By using this approach, we determined that the 

maximum TAC impact per well is approximately $35,750. However, the actual average TAC per well 

is likely much lower due to advances in horizontal drilling techniques resulting in multiple wells per

well pad. Since we have determined future development will average a well pad density of two wells 

per pad (Scenario B), the anticipated maximum TAC per well is reduced to approximately $26,000. 

We further evaluated the cost impact of the FIP by determining the cost effectiveness for each operating 

scenario. Using an average VOC reduction of 2,090 tpy per well, the cost effectiveness for each 

operating scenario is presented in Table 4. 
 

20 

Table 4 – Cost Effectiveness Per Well for Operating Scenarios 

Operating Scenario Emissions Reduction 

(tpy) 

Remaining 

Controlled 

Emissions (tpy) 

Cost Effectiveness 

($/ton VOC reduced)

Scenario A12,090 75 $17 

Scenario B2 4,180 150 $12 

Scenario C36,270 225 $10 

1. Values shown are for a single-well based on one-well facility 

2. Values shown are for a single-well based on a two-well facility. 

3. Values shown are for a single-well based on a three-well facility. Facilities with greater than three wells will 

increase cost effectiveness. 

As indicated in Table 4, the cost effectiveness for a typical two-well facility is less than $15 per ton of 

VOC reduced per well. As the number of wells per well pad increases, the cost effectiveness generally

increases. 

It is also important to note that we believe the FIP does not impose any significant cost on operators that 

would not already be incurred in the absence of the FIP. Safety considerations and standard industry 

practice already require the use of control equipment to eliminate the explosion hazard at the well pad, 

thereby reducing any danger to operator personnel and facility equipment. Additionally, operator 

environmental stewardship imposes control requirements to reduce potential impacts to the surrounding 

public and environment. Therefore, the FIP does not impose any significant additional costs that are not 

already being incurred by the operators. 

We would also like to note that pipeline infrastructure on the FBIR is anticipated to increase over the 

next several years. As pipeline infrastructure becomes available, the FIP requires operators to capture 

produced natural gas and natural gas emissions when economically feasible as opposed to routing the 

emissions to a combustion device. Pipeline infrastructure will not only allow operators to remove 

control equipment that are no longer required, but it will also generate increased revenue from the 

capture salable product. Furthermore, the FIP will provide the option for operators to utilize vapor 

recovery units (VRUs) as opposed to enclosed combustors as a method for reducing emissions from 

storage tanks. As the price and demand of natural gas increases in future years, VRUs may prove to be

an economic method of generating increased revenue and reducing the cost impacts of control 

equipment. 

Using a maximum TAC impact for a two-well facility of approximately $52,000 and reasonable 

foreseeable development estimated at 1,000 facilities, the maximum annual cost of compliance with the 

FIP on the oil and natural gas industry is estimated to be approximately $50 million. However, we 

believe this is a conservative estimate and that actual annual cost would be much lower due to factors

such as increased well pad density, standard industry practice, and anticipated pipeline infrastructure 

development. Therefore, the FIP will not have an annual effect on the economy of $100 million or more

and does not meet the definition of a significant regulatory action under Executive Order 12866. 

 
 

21 

V. Air Quality 

The State of North Dakota operates three ambient monitoring sites in the western part of the state that 

are designed to characterize regional background concentrations of criteria pollutants. These sites are 

located at Dunn Center, Theodore Roosevelt National Park-Northern Unit (TNRP) and Lostwood 

National Wildlife Refuge (LNWR). The sites collect background concentrations of criteria pollutants, 

including ozone and nitrogen dioxide (NO2). The locations of monitoring sites in North Dakota are 

shown below in Figure 1. The measured ambient ozone and NO2 concentrations in western North 

Dakota and the region of the FBIR are substantially lower than our National Ambient Air Quality 

Standard (NAAQS) of 75 parts per billion (ppb) for 8-hour average ozone and 100 ppb for 1-hour 

average NO2. 

 Figure 1. Locations of ambient air quality monitoring sites in ND. 

As part of the technical analysis for the FIP, we evaluated the impacts of changes in VOC and nitrogen

oxide (NOx) emissions from enclosed combustors and utility flares used for the control of VOC 

emissions at well pads consisting of two wells on the FBIR. The primary air pollutants that are affected 

by the FIP include VOC and NOX, where both VOC and NOX are precursors to ozone, and NOX is a 

precursor to NO2. A more detailed discussion of our evaluation on the ozone and NO2 NAAQS is 

included in the docket. 29 We reviewed data from synthetic minor permit applications and determined 

that a typical uncontrolled well pad with two wells would have VOC emissions of about 4,330 tpy. 

 

29 “Impacts of Well Pad VOC Enclosed Combustors and Utility Flares on the Ozone and NO2 NAAQS”, Memo to file, dated 

June 15, 2012, from Gail Tonnesen, EPA Region 8 Air Quality Modeler. 
 

22 

After installing VOC control equipment, including a combination of enclosed combustors, pit flares, and 

utility flares with destruction efficiencies ranging from 90-98%, potential emissions from a typical well 

pad with two wells and no pipeline access were estimated to be 150 tpy of VOCs. Additionally, EPA 

projected 8.8 tpy of NOX emissions resulting from the combustion of natural gas emissions at the control 

device for a two-well pad. Actual emissions are expected to be much lower due to the anticipated 

development of pipeline infrastructure in future years. 

The NAAQS for ozone is 75 parts per billion (ppb), and compliance with the NAAQS is determined by 

comparison to a “design value” that is calculated as the three year average of the fourth highest daily 

eight hour ozone concentration at each monitor site. Based on the most recent ambient monitoring data

in North Dakota, the 2011 ozone design values at the Dunn, TRNP and LNWR sites are 55, 59, and 60 

ppb, respectively.2 We performed a qualitative assessment of impacts on the ozone NAAQS. Ambient 

ozone is a secondary pollutant that is formed from precursor emissions of VOC and NOX. High ambient 

ozone levels are typically observed in urban areas during stagnant meteorological conditions during the 

summer and more recently, in areas of intensive oil and natural gas production in mountain basins that

experience strong inversion conditions and snow cover during winter. For a typical oil and natural gas 

production facility (well pad with two wells), we estimated that the use of enclosed combustors, utility 

flares, and pit flares would result in VOC reductions of about 4,180 tpy and an increase in NOX

emissions of 8.8 tpy. We estimated the reasonably foreseeable development of 1,000 well pads with an 

enclosed combustor and/or utility flare controls would result in a cumulative reduction of 4,180,000 tons 

of VOC and an increase of 8,800 tpy of NOX distributed over the FBIR region of 1,544 square miles. 

Because the proposed action would result in large VOC reductions and comparatively small NOX

increases, the action could result in either net increases or net decreases in ambient ozone levels 

depending on the sensitivity of ozone formation to changes in VOC and NOX. Since North Dakota and 

the FBIR generally have meteorological conditions with high winds and good ventilation during the 

summer ozone season, the emissions changes from the proposed action are not expected to significantly 

increase or reduce ambient ozone levels. Elevated winter ozone concentrations have not been observed 

in North Dakota. However, preliminary analysis of winter ozone in Wyoming indicates that winter 

ozone formation is more sensitive to VOC emissions than to NOX emissions. Thus, if high winter ozone 

conditions are observed in North Dakota in the future, the large VOC reductions from the proposed 

action would be expected to result in net ozone reductions on the FBIR. 

Based on this qualitative assessment, the emissions changes from the proposed action are not expected 

to significantly increase or reduce ambient ozone levels. Given that current ambient ozone levels in 

North Dakota are substantially lower than the ozone NAAQS, we determined that the proposed action is 

not expected to cause violations of the ozone NAAQS. We propose to continue to monitor ambient 

ozone levels in the region, and if increasing levels of ozone are observed in the future, additional 

analysis of VOCs and NOX impacts on ozone will be performed at that time. 

Compliance with the NAAQS for NO2 is determined by calculating a “design value” which is the eighth 

highest daily one hour average concentration averaged over a three year period at each monitor site. 

 

2

 The Air Quality System (AQS) – the EPA’s Repository of Air Quality Data, available online at: 

http://www.epa.gov/ttn/airs/airsaqs/. The AQS monitoring data for the ND sites 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 
 

23 

Source specific model impacts must be combined with background NO2 concentrations to evaluate 

potential exceedances of the NO2 NAAQS. Current background concentrations of NO2 in the region are 

quite low. AQS data from 2009 through 2011 shows 1-hour NO2 design values for the Dunn, LWNR 

and TNRP monitors at 11 ppb, 17 ppb, and 9 ppb, respectively, compared to the standard of 100 ppb. 

The Dunn monitor site is located about midway between the oil development along the North Dakota – 

Montana border and the seven coal conversion facilities to the east. We selected the Dunn monitor data 

as the most appropriate background site for the FBIR because it is a rural background monitor that is 

influenced by regional energy development activity.

We performed a quantitative assessment of impacts on the NO2 NAAQS. As part of the quantitative 

analysis, we evaluated various scenarios of NOX emissions from enclosed combustors and utility flares 

using the AERMOD nearfield dispersion model to determine the impacts on the 1-hour average ambient 

NO2 NAAQS. Input data to the AERMOD model for enclosed combustors included emission rates of 

NOX, stack height and diameter, stack natural gas exit velocity and temperature. Input data for utility 

flares includes flare height and calories per second generated by the enclosed combustor. The 

AERMOD modeling results did not indicate exceedances of the NO2 NAAQS for NOX emissions from 

utility flares or enclosed combustors. Based on this analysis, we determined that the proposed action is 

not expected to cause violations of the NO2 NAAQS. 

We also evaluated the impacts of other pollutants on the NAAQS. Expected emissions of sulfur dioxide 

(SO2) and particulate matter (PM) pollutants from enclosed combustors and utility flares used for 

control of VOC emissions at well pads are estimated to be below the Federal Tribal NSR permitting 

thresholds, and are therefore expected to have insignificant impacts on the NAAQS for these pollutants. 

Expected emissions of carbon monoxide (CO) from the enclosed combustors and utility flares are also 

expected to have an insignificant impact on the CO NAAQS because of the level of the CO standard in 

comparison to the emissions. 

VI. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations.

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on 

environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and 

permitted by law, to make environmental justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or environmental effects of their 

programs, policies, and activities on minority populations and low income populations in the United 

States. 

We define “Environmental Justice” to include meaningful involvement of all people regardless of race, 

color, national origin, or income with respect to the development, implementation, and enforcement of 

environmental laws, regulations, and polices. 

 
 

24 

1. Public Participation 

To promote meaningful involvement, we will solicit input from potentially affected stakeholders and 

communities during the public comment period by posting information about the proposed rule 

throughout the reservation at tribal offices, community centers and the Fort Berthold Community 

College and publishing a notice in five (5) local newspapers. In addition, we will hold a public hearing 

on the Fort Berthold Indian Reservation during the public comment period. 

2. Determination 

For purposes of Executive Order 12898 on environmental justice, we recognized that compliance with 

the National Ambient Air Quality Standards (NAAQS) is “emblematic of achieving a level of public 

health protection that, based on the level of protection afforded by a primary NAAQS, demonstrates that 

our issuance of a PSD permit for a proposed facility will not have disproportionately high and adverse

human health or environmental effects on minority populations and low-income populations.” In re 

Shell Gulf of Mexico, Inc. & Shell Offshore, Inc., 15 E.A.D. ___, slip op. at 74 (EAB 2010). This is 

because the NAAQS are health-based standards, designed to protect public health with an adequate 

margin of safety, including sensitive populations such as children, the elderly, and asthmatics. Although 

taken from the context of issuance of a PSD permit, this logic applies with equal force to our issuance of 

a Clean Air Act Federal Implementation Plan. 

We determined that this proposed rule will not have disproportionately high and adverse human health 

or environmental effects on minority, low income and indigenous populations because it is in 

compliance with the NAAQS and provides environmental protection for all affected populations without 

having any disproportionately high and adverse human health or environmental effects on any 

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

3. Demographics 

Additionally, the Agency has reviewed this rule to determine if there is an overrepresentation of 

minority, low income, or indigenous populations near the sources30 such that they may currently face 

disproportionate risks from pollutants that could be mitigated by this rulemaking. This analysis only

gives some indication of the prevalence of sub-populations that may be exposed to HAP pollution from 

the sources affected by this rulemaking; it does not identify the demographic characteristics of the most 

highly affected individuals or communities, nor does it quantify the level of risk faced by those 

individuals or communities. 

 

 

30 Source information on oil and gas wells located on the Fort Berthold Indian Reservation provided by HPDI Inc. 2010 
 

25 

The demographic data in Table 5 shows that several demographic categories exceed 20 percent of their 

corresponding national averages: 

• Native American = +64 percentage points or +5477% 

• Minority = +42 percentage points or +152% 

• Population under 18 = +6 percentage points or + 25 % 

Table 5 - Summary of Demographic Data Analysis 

The analysis of demographic data used proximity-to-a-source as a surrogate for exposure to identify 

those populations considered to be living near affected sources, such that they have notable exposures to 

emissions from these sources. The demographic data for this analysis were extracted from the 2010 

census data, which were provided to us by the United States Census Bureau. Distributions by race are 

based on demographic information at the census block level, and all other demographic groups are based

on the extrapolation of census block group level data to the census block level. The socio-demographic 

parameters used in the analysis included the following categories: 

• Racial (White, African American, Native American, Other or Multiracial, and All Other Races); 

• Ethnicity (Hispanic); and 

• Other 

o Number of people below the poverty line, 

o Number of people with ages between 0 and 18, 

o Number of people greater than or equal to 65, 

o Number of people over age 25 without a high school diploma. 

POPULATION 6493 312861256

WHITE 1977 30% 226405205 72% -58%

AFRICAN AMERICAN 14 0% 39475216 13% -98%

NATIVE AMERICAN 4221 65% 3646995 1% 5477%

OTHER OR MULTIRACIAL 281 4% 43333840 14% -69%

MINORITY24516 70% 86456051 28% 152%

HISPANIC OR LATINO3272 4% 54181245 17% -76%

AGE 0 - 17 1955 30% 75217176 24% 25%

AGE 65+ 657 10% 40830262 13% -22%

NO HIGH SCHOOL DIPLOMA 383 6% 31914536 10% -42%

BELOW POVERTY LINE 838 13% 43487509 14% -7%

>= 1.2 of National Average

% 

DEMOGRAPHIC SUMMARY Change 1

NEAR 

SOURCE 

NATIONAL 

TOTAL

% OF NEAR 

SOURCE 

% OF 

NATIONAL 

Sources: The demographics are from the U.S. Census Bureau, 2010. Information on the facilities is from U.S. EPA.

1. Racial and ethnic categories overlap and cannot be summed.

2. The “Minorities” population is the overall population (in the first column) minus white population (in the second column).

3. The Census Bureau defines “Hispanic or Latino” as an ethnicity rather than as a racial category, Hispanics or Latinos may belong to any race.
 

26 

In determining the aggregate demographic makeup of the communities near affected sources, we 

focused on those census blocks within 3 miles of affected sources and determined the demographic 

composition (e.g., race, income, etc.) of these census blocks and compared them to the corresponding 

compositions nationally. The radius of 3 miles (or approximately 5 km) is consistent with other 

demographic analyses focused on areas around potential sources31

,

32

,

33

,

34 however, not necessarily 

associated with the distance health risks are seen. To the extent that any minority, low income, or 

indigenous subpopulation is disproportionately impacted by the emissions as a result of the proximity of 

their homes to these sources, that subpopulation also stands to see increased environmental and health

benefit from the emission reductions called for by this rule. 

Because this study area is primarily on a reservation, a second analysis examined if predominantly 

Native Americans block groups had other environmental justice concerns. Table 6 compares 

demographic information for the Native American block groups to national averages. Besides race, the 

poverty rate and age demographics are the major differences between the predominately Native 

Americans and national averages. The overall study area has a poverty rate 7 percent below the national 

average, while the areas of concentrated native Americans has a poverty rate of 28 percent, which is 103 

percent higher than the national average (28 percent vs. 14 percent). 

 

31 U.S. GAO (Government Accountability Office). Demographics of People Living Near Waste Facilities. Washington DC: 

Government Printing Office; 1995. 

32 Mohai P, Saha R. “Reassessing Racial and Socio-economic Disparities in Environmental Justice Research”. Demography. 

2006;43(2): 383–399. 

33 Mennis J. “Using Geographic Information Systems to Create and Analyze Statistical Surfaces of Populations and Risk for 

Environmental Justice Analysis”. Social Science Quarterly, 2002;83(1):281-297. 

34 Bullard RD, Mohai P, Wright B, Saha R, et al. Toxic Waste and Race at Twenty 1987-2007. United Church of Christ. 

March, 2007. 
 

27 

Table 6 - Block Groups with 50% of More Native Americans 

Table 7 compares the Native American block groups with the white block groups. The Native American 

population is 520 percent higher than in the predominately white block groups (71 percent vs. 11 

percent), poverty level 138 percent higher (28 percent vs. 12 percent), the population under 18 years of 

age is 40 percent higher (31 percent vs. 23 percent), and population below five years is 56 percent higher 

(9 percent vs. 6 percent). 

Demographic 

Summary1

Native 

American 

Areas

% Of Native 

American 

Areas

National 

Totals

% Of 

National 

Totals

% Change

POPULATION 5,815 312,861,256

WHITE 1,437 25% 226,405,205 72% -66%

AFRICAN AMERICAN 7 0% 39,475,216 13% -99%

NATIVE AMERICAN 4,120 71% 3,646,995 1% 5978%

OTHER OR MULTIRACIAL 251 4% 43,333,840 14% -69%

MINORITY2

4,378 75% 86,456,051 28% 172%

HISPANIC OR LATINO3

260 4% 54,181,245 17% -74%

AGE 0 - 4 537 9% 20,465,068 7% 41%

AGE 0 - 17 1,826 31% 75,217,176 24% 31%

AGE 65+ 528 9% 40,830,262 13% -30%

NO HIGH SCHOOL 

DIPLOMA

496 9% 32,060,510 10% -17%

BELOW POVERTY LINE 1,643 28% 43,616,850 14% 103%

>= 1.2 times National Average

Sources: The demographics are from the U.S. Census Bureau, 2010. Information on the facilities is from U.S. EPA.

1. Racial and ethnic categories overlap and cannot be summed.

2. The “Minorities” population is the overall population (in the first column) minus white population (in the second column).

3. The Census Bureau defines “Hispanic or Latino” as an ethnicity rather than as a racial category, Hispanics or Latinos may belong to any race.

4. Where facility study areas overlap, the census block populations are only counted once. Therefore, a facility level total will not match this summary total.
 

28 

Table 7 - Comparing Native American Block Groups to Remaining Study Area 

 

VII. Conclusion

We believe that in light of the regulatory gap and potential for future air quality issues related to VOC 

generally presented on the FBIR, it is appropriate to establish the air quality rule that is proposed today. 

By means of the proposed rule, we will impose regulatory requirements on the oil and natural gas 

production industry on the FBIR, equivalent to those imposed by the NDDoH rules for the areas outside 

the FBIR. We believe that it is appropriate to focus initially on the oil and natural gas production 

operations that have been identified as having the greatest potential to impact future air quality on the 

FBIR and in shared airsheds of North Dakota. 

This rule would regulate activities, pollutants, and facilities by supplementing the existing federal 

regulatory programs such as the PSD, Minor NSR, Title V, NSPS, and NESHAP programs. This 

proposed rule would provide additional regulatory tools for us to use in implementing the CAA on the 

FBIR. We have adequate enforcement authority under Section 113 of the CAA to ensure compliance 

with the requirements that are proposed. 

Demographic 

Summary1

Native 

American 

Areas

% Native 

American 

Areas

White Areas % White 

Area

% Change

POPULATION 5,815 9,976

WHITE 1,437 25% 8,593 86% -71%

AFRICAN AMERICAN 7 0% 20 0% -40%

NATIVE AMERICAN 4,120 71% 1,140 11% 520%

OTHER OR MULTIRACIAL 251 4% 223 2% 93%

MINORITY2

4,378 75% 1,383 14% 443%

HISPANIC OR LATINO3

260 4% 190 2% 135%

AGE 0 - 4 537 9% 590 6% 56%

AGE 0 - 17 1,826 31% 2,245 23% 40%

AGE 65+ 528 9% 1,573 16% -42%

NO HIGH SCHOOL 

DIPLOMA

496 9% 1,054 11% -19%

BELOW POVERTY LINE 1,643 28% 1,183 12% 138%

>= 1.2 times Total Study Area

Sources: The demographics are from the U.S. Census Bureau, 2010. Information on the facilities is from U.S. EPA.

1. Racial and ethnic categories overlap and cannot be summed.

2. The “Minorities” population is the overall population (in the first column) minus white population (in the second column).

3. The Census Bureau defines “Hispanic or Latino” as an ethnicity rather than as a racial category, Hispanics or Latinos may belong to any race.

4. Where facility study areas overlap, the census block populations are only counted once. Therefore, a facility level total will not match this summary total.
 

29 

Regulating these sources is appropriate not only in order to protect air quality from the potential for 

significant deterioration caused by the release of VOC, but also to ensure equal incentive for operators 

to develop the mineral resource on Tribal versus state land. VOC is regulated indirectly by National 

Ambient Air Quality Standards (NAAQS) as a precursor to ozone formation under section 109 of the 

CAA. The rule proposed today would control emissions of VOC to the atmosphere as appropriate for 

the purpose of maintaining or attaining the NAAQS for ozone. Along with the protections this Federal

air quality rule would provide, the rule can also assist the Three Affiliated Tribes of the Mandan, 

Hidatsa, and Arikara Nations in developing an air quality management program by using the federal rule

as a template in drafting a TIP. 

The FBIR is currently experiencing one of the largest oil and natural gas booms the nation has ever 

experienced. Oil and natural gas development is expected to continue to increase significantly in the

future, thus increasing the total VOC emissions in the area. 

Due to the current lack of pipeline infrastructure, the use of pit flares, utility flares, and enclosed 

combustors are standard industry practice for controlling VOC emissions at oil and natural gas 

production facilities on the FBIR. We determined it is necessary to promulgate a FIP to regulate the 

affected equipment and reduce the environmental impact of increasing oil and natural gas development 

in the area. The emission control requirements in the FIP will provide up to 98% reduction in these 

emissions, greatly reducing the environment impact of the booming oil and natural gas industry on the 

FBIR. 

We believe that this rule is appropriate because it establishes federally enforceable requirements to 

control VOC emissions from oil and natural gas production equipment equivalent to the requirements 

imposed by the NDDoH, which will allow owners and operators to take into account controls they 

would use (and are already using) regardless of any federally enforceable requirement. Thus, the FIP 

equalizes the playing field between NDDoH jurisdiction and our jurisdiction on the FBIR. Additionally, 

the FIP will reduce the permitting burden for us, thereby preventing potential delays in development of 

the economically valuable mineral resource, because many facilities will be able to commence 

construction without first having to obtain a construction permit.