Technical Support Document

for

EPA’s Proposed Action on North Dakota’s 

April 2011 State Implementation Plan Revisions

North Dakota Administrative Code 33-15-14, 

Designated Air Contaminant Sources, 

Permit to Construct, Minor Source Permit to Operate, 

Title V Permit to Operate

Docket EPA-R08-OAR-2012-0761

Prepared and Reviewed by:

Gail Fallon

Albion Carlson

Richard Payton

Elyana Sutin

Environmental Protection Agency Region 8

February 2014
2

Executive Summary:

EPA is proposing to approve State Implementation Plan (SIP) revisions submitted by the 

Governor of North Dakota on April 14, 2011. As described in our proposed rule, most of the revisions 

we are approving merely conform the North Dakota SIP to relevant Clean Air Act (CAA) requirements. 

Several of the rule revisions have broader implications related to North Dakota’s minor source 

permitting program. The permitting rule revisions expand an existing permitting exemption for oil and 

gas production operations. CAA section 110(l) requires a demonstration that a SIP revision does not 

interfere with any requirement concerning attainment and maintenance of the NAAQs and that any 

relaxation is sufficiently protective of air quality and other CAA requirements in order for EPA to 

approve. The demonstration provided herein, based primarily on air quality monitoring data and North 

Dakota’s existing oil and gas well registration program, confirms that the permitting rule revisions are 

not likely to interfere with national ambient air quality standards (NAAQS) or the State’s SIP control 

strategy. 

Introduction:

EPA is proposing to approve SIP revisions submitted by the Governor of North Dakota on April 

14, 2011. The revisions affect North Dakota’s air pollution control rules regarding general provisions, 

ambient air quality standards (sulfur dioxide (SO2), nitrogen dioxide (NO2), and lead), and permitting. 

EPA acted separately on certain other provisions in the April 14, 2011 submittal related to North 

Dakota’s regulation of greenhouse gases under its prevention of significant deterioration (PSD) program

in 2012 (77 FR 64734, October 23, 2012). 

The focus of this technical support document (TSD) relates to the permitting rule revisions in 

North Dakota Administrative Code (NDAC) Chapter 33-15-14. In addition to several housekeeping 

revisions, the State made revisions with the intent to change the permitting requirement for sources 

subject to a new source performance standard (NSPS) or a national emission standard for hazardous air 

pollutants maximum achievable control technology (MACT) requirement for hazardous air pollutants. 

The rule revisions affect oil and gas sources and other types of minor sources. Oil and gas production 

facilities are by far the most common minor source in North Dakota. Previously, the State’s rules at 33-

15-14-01 and 33-15-14-02 required all owners and operators of sources subject to an NSPS or MACT to 

obtain a permit to construct; with the revisions, only sources subject to an NSPS or MACT which the 

State has “adopted” are subject to the permitting requirements. The effect of these revisions is that the 

State will continue to not require permits for the multitude of small units subject to an NSPS or MACT, 

such as tanks, subject to the recently issued 40 CFR part 60, subpart OOOO (Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and Distribution), which the State has not 

adopted and does not intend to adopt into the NDAC. State permitting requirements aside, national 

emissions standards in any NSPS or MACT including subpart OOOO still apply to the subject sources. 

The revisions related to North Dakota’s minor source NSPS result in a narrower subset of sources 

subject to NSPS requirements (only those sources subject to NSPS or MACT that are adopted by the 

State) are subject to permitting. Under CAA section 110(l), EPA cannot approve a revision to a state’s

SIP without a demonstration that the revision will not interfere with any applicable requirement

concerning attainment and reasonable further progress, or any other applicable requirement of the CAA. 

EPA conducted such a demonstration for the permitting rule revision in the April 2011 submittal finding 

the revisions are not presently interfering with the State’s SIP control strategy or causing NAAQS 

violations in North Dakota.
3

North Dakota’s Existing Requirements for Oil and Gas:

North Dakota has numerous existing requirements (both state rule and guidance) geared towards 

controlling volatile organic compound (VOC) emissions from oil and gas production facilities. These 

requirements are summarized in Table 1 below. In addition to the specific requirements discussed 

below, NDAC 33-15-14-01.12 states, “Any source which is determined by the department to cause or 

contribute to a violation of any state ambient air quality standard or violates the other provisions of 

Chapter 33-15-02” is an air contaminant source (subject to a permit). However, North Dakota’s rules 

then limit this broad requirement for a permit by specifically exempting several categories of sources at 

NDAC 33-15-14-02.13.

Regarding minor source permitting for oil and gas production, the State has an existing 

permitting exemption for facilities which are not major sources at NDAC 33-15-14-02.13.o. This 

exemption negates the general authority set forth in NDAC 33-15-14-01.12 thus relaxing the minor 

source permitting program. However, this exemption cross references to a registration program for such 

sources at NDAC 33-15-20 which the State considers as a bolster to its regulation of oil and gas 

production facilities. According to North Dakota, all oil and gas production facilities must register with 

the State. North Dakota’s oil and gas registration program was approved into the SIP in 1987. The 

permitting exemption for oil and gas production (well) facilities was approved into the SIP in 1995. 

While the current language in Chapter 33-15-20 indicates this registration program only applies 

to sulfur emitting oil and gas operations, the State does require all oil and gas operations to comply with 

the registration program as evidenced in guidance documents.1, 2 The registration program in 33-15-20 

requires the owner and operator of any oil or gas well that is completed or recompleted on or after July 

1, 1987, to submit an oil and gas well registration form and an analysis of any gas produced from the 

well within 90 days of the completion or recompletion of the well. Registration is required for all wells 

that are not major sources regardless of size. Additionally, the rule requires emissions from various oil 

field equipment (separators, engines, incinerators, tanks, etc.) to comply with ambient air quality 

standards, to conduct routine inspections, to install any necessary equipment to ensure compliance with 

ambient air quality standards, and to notify the State in the event control equipment malfunctions are 

expected to cause emission of air contaminants in violation of State rules for longer than twenty-four 

hours. EPA acknowledges that there are ongoing discussions with North Dakota to address EPA’s

concerns with the rule language that EPA previously approved into the North Dakota SIP. In a 

December 10, 2013 letter from Terry O’Clair, Director of North Dakota’s Division of Air Quality to 

Gail Fallon, EPA Region 8, North Dakota committed to revising rule 33-15-20-01.1 to clarify that the 

provisions of Chapter 33-15-20 apply to all oil and gas production facilities, not just those that emit 

sulfur or sulfur compounds. Furthermore, EPA acknowledges that there are ongoing discussions with 

North Dakota to clarify and strengthen the State’s minor NSR program including addressing oil and gas 

production. 

 

1 A North Dakota Department of Health (NDDH) May 2, 2011 memorandum posted on the State’s website and included in 

the docket for this action states, “As an Oil and Gas Operator in the State of North Dakota, you are subject to Chapter 33-15-

20 of the North Dakota Air Pollution Control Rules...These rules require the owner or operator of any oil or gas well 

completed or recompleted on or after July 1, 1987, to submit a registration and gas analysis for production facilities to the

North Dakota Department of Health...” 

2 An NDDH December 10, 2013 letter to EPA Region 8 clarifies that the registration requirements of Subsection 33-15-20-

02.1 apply to any oil or gas well that is completed or recompleted after July 1, 1987 and that this has been the case for 26 

years. The State also conveys in the letter its intentions to revise its rules to clarify that the provisions of Chapter 33-15-20 

apply to all oil and gas operations.
4

The State has additional oil and gas guidance related to operations conducted in the Bakken 

Pool.

3

 The Bakken Pool guidance is intended to assist operators with emission calculations, determining 

emission control requirements, and maintaining compliance with the state rules. The Bakken Pool 

guidance elaborates on control measures already described in 33-15-20 for flares and gas emissions from 

tanks. As an example, the control requirement for ground pit flares is a destruction and removal 

efficiency (DRE) of 90% or greater for VOCs. For tanks, the Bakken Pool guidance requires vapor 

recovery units or oil stabilizers that are designed and operated to reduce the mass content of VOC and 

total hazardous air pollutant emissions in the vapors vented to the device by at least 99% by weight. The 

Bakken Pool guidance and the State’s website for oil and gas wells4further advise operators that 

additional rules and regulations related to NSPS and MACT applicability under 40 CFR parts 60 and 63 

may apply.

The State has additional rules unrelated to air quality established by the North Dakota Industrial 

Commission that provide collateral benefits. A requirement under Control of Oil and Gas Resources at 38-

08-06.4 restricts gas flaring to only the first production year for a well. After the first year this rule 

requires the well be controlled in one of the following ways:

 capped;

 connected to a gas gathering line; 

 equipped with an electrical generator that consumes at least 75 percent of the gas from the 

well; 

 equipped with a system that intakes at least 75 percent of the gas and natural gas liquids 

volume from the well for beneficial consumption by means of compression to liquid for use 

as fuel, transport to a processing facility, production of petrochemicals or fertilizer, 

conversion to liquid fuels, separating and collecting over 50 percent of the propane and 

heavier hydrocarbons; or

 equipped with other value-added processes as approved by the North Dakota Industrial

Commission which reduce the volume or intensity of the flare by more than 60 percent.

 

3 The Bakken Pool guidance is included in the docket for this action.

4

http://www.ndhealth.gov/AQ/OilAndGasWells.htm accessed on January 22, 2014.
5

Table 1. Summary of VOC Limitations in North Dakota State Rules or Guidance

Rule or Guidance VOC Limitations for Oil and Natural Gas Production 

Operations

North Dakota Department of Health (NDDH)

North Dakota Century Code 

Chapter 23-25 Air Pollution Control, 

Air Pollution Control Rules 

Article 33-15

Chapter 33-15-07 Control of Organic

Compounds Emissions 

Chapter 33-15-20 Control of Emissions 

from Oil and Gas

Well Production Facilities

(These are SIP provisions.)

NDDH - Bakken Pool Oil and Gas

Production Facilities Air Pollution Control

Permitting & Compliance Guidance 

(pages 39-43)

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 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).

Each flare must be equipped with an automatic ignition system or 

continuous burning pilot.

Provides acceptable control system requirements for wells and tanks 

(e.g., flare with automatic ignition system or continuous burning 

pilot).

North Dakota Industrial Commission (NDIC)

North Dakota 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 

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 hazardous air pollutant (HAP) emissions from all active 

produced water tanks 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 

ignitor, 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 

practices for minimizing emissions.
6

North Dakota’s Air Quality:

North Dakota is well in attainment for all the NAAQs. EPA performed an assessment of air 

quality trends in North Dakota and determined that the permitting rule revisions are not expected to 

cause violations of any NAAQS. Since the primary concern for the SIP relaxation pertains to minor 

source permitting for oil and gas operations, the analysis in this TSD focuses on the three criteria 

pollutants that would most likely be anticipated to result from oil and gas operations: ozone (O3), NO2, 

and SO2. EPA assessed O3 and NO2 because volatile organic compounds and nitrogen oxides (NOx) 

emissions from oil and natural gas production facilities are precursors to O3 formation. EPA also 

assessed SO2 which is often associated with oil and natural gas production. While SO2 is not present in 

appreciable amounts in North Dakota’s Bakken formation where the majority of the oil and gas activity 

is occurring, EPA included it for informational purposes. The other criteria pollutants (lead, particulate 

matter and carbon monoxide) are discussed in this assessment to provide additional information on all 

pollutants identified in the area.

The information in this TSD was compiled from information provided by the State, as well as 

EPA’s own analysis utilizing air monitoring data. This EPA analysis considered all the available 

monitoring data and encompasses the period of time for which the North Dakota oil and gas registration 

program has been in place. Monitoring began in various years depending on the pollutant and its 

corresponding standard, in some cases as early as 1979. 

As of the publication of this rule, all monitoring information referenced herein is available on the 

EPA’s Air Quality System (AQS) database. The AQS database is available to the public via EPA’s 

website at: http://www.epa.gov/ttn/airs/aqsdatamart/. The AQS is EPA’s repository of ambient air 

quality data. AQS stores data from over 10,000 monitors, approximately 5,000 of which are currently 

active. State, local and tribal agencies collect the data and submit it to AQS on a periodic basis. The 

monitoring data for this analysis was collected at North Dakota’s monitoring sites at Dunn, Hannover, 

Lostwood National Wildlife Refuge (NWR), Theodore Roosevelt National Park North Unit(TRNP-NU), 

Fargo, Bismarck, and Beulah. The North Dakota monitoring sites are shown on Figure 1 annotated with 

blue X symbols. Figure 1 also includes industry monitoring sites annotated with red and green symbols. 

Additional information is available in North Dakota’s report entitled, Annual Report North Dakota 

Ambient Monitoring Network Plan, 2012, (hereinafter referred to as the 2012 Annual Report) available 

in the docket for this rulemaking as well as at: http://www.ndhealth.gov/AQ/ambient/nwrev_12.pdf .
7

Figure 1. North Dakota Ambient Air Quality Monitoring Sites

Ozone:

O3 is formed by the interaction of directly-emitted precursor emissions, VOCs and NOx, in the 

presence of sunlight under the influence of meteorological and topographical features of an area. High

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

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

experience strong inversion conditions and snow cover during winter. 40 CFR 58 defines the O3

monitoring season for North Dakota as May 1 through September 30. In addition to the seven 

monitoring sites described above, North Dakota also has a new ozone monitor located in Williston that 

began operation January 1, 2014. This site is intended to further ascertain the impacts of oil 

development on ozone levels.

Statewide, major stationary point sources of VOCs in North Dakota include an oil refinery, a 

coal gasification plant, natural gas processing plants, an ethanol plant, a corn processing facility, and a 

container manufacturer. Area sources that also contribute to VOC emissions include oil and gas 

production operations and automobiles in urban areas. The 2012 Annual Report includes additional

information regarding point and area sources that contribute to VOC emissions in North Dakota. 

Figure 2 shows how the North Dakota monitoring data compares to the 2008 O3 standard and 

reflects a slightly downward trend. To attain the 2008 O3 standard, the 3-year average of the fourthhighest daily maximum 8-hour average O3 concentrations measured at each monitor, within an area, 

over each year, must not exceed 0.075 parts per million (ppm) (effective May 27, 2008.) (See 40 CFR 

50.9 and 50.10.) North Dakota is in attainment for the 2008 O3 standard with a current maximum design 

value of .059 ppm at the Lostwood NWR site based on 2010, 2011, and 2012 data. The maximum 

design value for Lostwood was 0.060 ppm using 2009, 2010, and 2011 data. Table 2 provides historical 
8

O3 design values for the past ten years. Figure 3 shows the design value trends for the past ten years are 

relatively static. 

Figure 2. North Dakota O3 Trends - Annual 4th Max 8-hr O3 Standard

Table 2. Historical O3 Design Values (ppm)

3-Year Average of 4

th Highest Daily Maximum

8-hour Average

Monitoring Sites 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Lostwood NWR 0.057 0.058 0.059 0.059 0.060 0.060 0.059

Bismarck 0.059 0.056 0.057 0.057 0.058

Fargo 0.063 0.061 0.060 0.060 0.060 0.058 0.055 0.058 0.059 0.061

Dunn 0.060 0.058 0.056 0.055 0.057 0.059 0.057

TRNP-NU 0.063 0.062 0.060 0.062 0.064 0.061 0.060 0.059 0.059

Beulah 0.062 0.060 0.058 0.059 0.061 0.062 0.058 0.059 0.058 0.060

Hannover 0.056 0.056 0.057 0.060 0.061 0.058 0.059 0.058 0.058

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

1970 1980 1990 2000 2010 2020

PPM

Year

Dunn 4th Max 8-hr O3

Hannover 4th Max 8-hr O3

Lostwood 4th Max 8-hr O3

TRNP-NU 4th Max 8-hr O3

Fargo 4th Max 8-hr O3

Bismarck 4th Max 8-hr O3

Beulah 4th Max 8-hr O3

8-hour O3 Std (0.075 ppm)
9

Figure 3. Historical O3 Design Value Trends 2003 – 2012

3-Year Average of 4th Highest Daily Maximum

8-hour Average

The O3 design values and trends provided in Table 2 and Figure 3 above, demonstrate that there 

was no change or that there was a decrease in O3 design values statewide, most notably at the 

monitoring sites located closest to the oil and gas development area, TRNP-NU and Lostwood NWR, 

even during the most recent years, 2009 to 2012, encompassing the period of increased development. 

Given a steady state or decreasing ozone environment at the most impacted sites during the emissions 

growth to date, with existing design values less than 80% of the current NAAQS, significant margin 

exists before continued emission growth could threaten the ozone NAAQS. This is discussed in more 

detail in the roll-forward analysis section below.

Nitrogen Dioxide:

NO2 is one of a group of highly reactive gasses known as “oxides of nitrogen,” or “nitrogen 

oxides.” EPA’s NAAQS uses NO2 as the indicator for the larger group of NOx. NO2 forms quickly 

from emissions from cars, trucks and buses, power plants, and off-road equipment. In addition to 

contributing to the formation of ground-level O3, and fine particle pollution, NO2 is linked with a 

number of adverse effects on the respiratory system. 

The larger NOx point sources in North Dakota are coal-fired steam-powered electrical generating 

plants in the west-central portion of the state and large internal combustion compressor engines in the 

-1.53E-16

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

0.045

0.05

0.055

0.06

0.065

0.07

0.075

0.08

0.085

0.09

0.095

0.1

2003 2005 2007 2009 2011

PPM

Design Value Years

Lostwood

Bismarck

Fargo

Dunn

TRNP-NU

Beulah

Hannover

8-Hour Ozone Standard
10

natural gas fields in the western part of the state. Figure 4 shows the contribution of point sources to 

total NOx emissions in the state. The “Point Sources” category consists of utility boilers (power plant 

boilers) and oil and gas production sources. The 2012 Annual Report includes additional information 

regarding point and area sources that contribute to NOx emissions in North Dakota. 

EPA first set standards for NO2 in 1971, setting both a primary standard (to protect health) and a 

secondary standard (to protect the public welfare) at 0.053 parts per million (53 ppb), averaged annually

(see 40 CFR 50.11). The Agency has reviewed the standards twice since that time, but chose not to 

revise the annual standards at the conclusion of each review. In January 2010, EPA established an 

additional primary standard at 100 ppb, averaged over one hour. Together the primary standards protect 

public health, including the health of sensitive populations - people with asthma, children, and the 

elderly. No area of the country has been found to be out of compliance with the current NO2 standards. 

Figure 5 shows North Dakota’s total annual NOx emissions from point sources and two subcategories for 1984 through 2011. The 2012 Annual Report includes additional information regarding 

point and area sources that contribute to NOx emissions in North Dakota. Figure 5 shows the North 

Dakota monitoring data for NO2. All 98th percentile values are less than half of the 100 ppb standard. 

Figure 4. North Dakota Annual Point Source NOx Emissions

0

20000

40000

60000

80000

100000

120000

140000

1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012

NOx (tons)

TOTAL UTILITY BOILERS OTHER POINT SOURCES
11

Figure 5. North Dakota Ambient NO2 Trends

Sulfur Dioxide:

SO2 is formed when sulfur containing compounds are burned (oxidized). SO2 is a byproduct of 

many industrial processes. SO2 is one of a group of highly reactive gases known as “oxides of sulfur.” 

EPA recently established a new 1-hour SO2 standard at a level of 75 parts per billion (ppb), based on the 

3-year average of the annual 99th percentile of 1-hour daily maximum concentrations. EPA also revoked 

both the existing 24-hour and annual primary SO2 standards (see 75 FR 35520). This final rule was 

effective on August 23, 2010. The secondary standard, 0.5 ppm 3-hour average, not to be exceeded 

more than once per calendar year, was established in 1973 (see 40 CFR 50.4 and 50.5). 

North Dakota has not yet been designated as either nonattainment, attainment or unclassifiable 

under the 1-hour SO2 NAAQS . The largest sources of SO2 emissions in North Dakota are from energy 

development in the west and west-central portions of the State. These sources include coal-fired steampowered electrical generating facilities, a coal gasification plant, natural gas processing plants, an oil 

refinery, flaring at oil and gas well sites, oil storage facilities, and compressor stations. Figure 6 shows 

the total annual SO2 emissions from point sources and three sub-categories for 1984 through 2011. The 

2012 Annual Report includes additional information regarding point and area sources that contribute to 

SO2 emissions in North Dakota. 

0

5

10

15

20

25

30

35

40

45

50

1975 1980 1985 1990 1995 2000 2005 2010 2015

PPB

Year

Dunn 98th %ile 1-hr NO2

Dunn Annual Mean NO2

Hannover 98th %ile 1-hr NO2

Hannover Annual Mean NO2

TRNP-NU 98th %ile 1-hr NO2

TRNP-NU Annual Mean NO2

Lostwood 98th %ile 1-hr NO2

Lostwood Annual Mean NO2

Fargo 98th %ile 1-hr NO2

Fargo Annual Mean NO2

Bismarck 98th %ile 1-hr NO2

Bismarck Annual Mean NO2

Beulah 98th %ile 1-hr NO2

Beulah Annual Mean NO2

All 98th percentile 

values are less than half the 

standard- 100 PPB.
12

Figure 7 shows the North Dakota monitoring data relative to the 99th percentile, 1-hour SO2 

standard. All the monitored 2012 99th percentile concentrations are below the 75 ppb standard with the 

highest value at 40 ppb. Although the EPA has not yet determined whether North Dakota is attaining or 

violating the 1-hour SO2 NAAQS, the static or decreasing trend in monitored SO2 ambient trends in 

recent years when oil and gas operations have been increasing does not suggest that these operations 

have had a detrimental effect on the monitored ambient concentrations of SO2 in North Dakota. EPA 

suspects the high monitored value at TRNP-NU in 1982 was due to poor data quality at that time. EPA 

believes the high monitored values at the Hannover site in 1989, 1998 and 1999 were due to the close 

proximity of the monitoring site to lignite fired power plants and perhaps the Dakota Gasification plant. 

Furthermore, the high monitored values were not exceedances of the less stringent 24-hour primary 

standard in effect at that time (0.14 ppm or 140 ppb) 

Figure 6. North Dakota Annual Point Source SO2 Emissions

0

50000

100000

150000

200000

250000

1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012

SO2 (tons)

TOTAL OIL & GAS OTHER PT. SOURCES UTITLITY BOILERS
13

Figure 7. North Dakota SO2 Trends – 99th Percentile 1-Hour SO2 Standard

Particulate Matter:

"Particulate matter," also known as particle pollution or PM, is a complex mixture of extremely 

small particles and liquid droplets. Particle pollution consists of a number of components, including 

acids (such as nitrates and sulfates), organic chemicals, metals, and soil or dust particles. 

The size of particles is directly linked to their potential for causing health problems. EPA is 

concerned about particles that are 10 micrometers in diameter or smaller because those are the particles 

that generally pass through the throat and nose and enter the lungs. Once inhaled, these particles can 

affect the heart and lungs and cause serious health effects. EPA groups particle pollution into two 

categories:

 "Inhalable coarse particles," such as those found near roadways and dusty industries, are larger 

than 2.5 micrometers and smaller than 10 micrometers in diameter. 

 "Fine particles," such as those found in smoke and haze, are 2.5 micrometers in diameter and 

smaller. These particles can be directly emitted from sources such as forest fires, or they can 

form when gases emitted from power plants, industries and automobiles react in the air. Some 

gaseous pollutants undergo a gas-to-particle conversion and are considered precursors to fine 

particle pollution (e.g., SO2 and NOx).

0

20

40

60

80

100

120

140

1975 1980 1985 1990 1995 2000 2005 2010 2015

PPB

Year

Lostwood 

Dunn Center

Bismarck

Hannover

Fargo

Buehla

TRNP

1-hr SO2 Std (ppb)
14

On July 1,1987, EPA established primary standards for PM10. These included a 24-hour standard 

at a level of 150 micrograms per cubic meter (ug/m

3

) (not to be exceeded more than once per year on 

average over a three-year period) and an annual standard at a level of 50 ug/m3 (annual arithmetic mean

averaged over three years). At that time, EPA also established secondary PM10 standards that were 

identical to the primary standards. (52 FR 24634, July 1, 1987.) Effective December 18, 2006, EPA 

revoked the annual PM10 standard but retained the 24-hour PM10 standard. (71 FR 61144, October 17,

2006.) 

On July 18, 1997, EPA established primary standards for PM2.5. These included a 24-hour 

standard at a level of 65 ug/m3(98th percentile, averaged over three years) and an annual standard at a 

level of 15.0 ug/m3. At that time, EPA also established secondary PM2.5 standards that were identical to 

the primary standards. (62 FR 38652, July 18, 1997.) These standards were reviewed and, in some 

cases, revised in 2006 and in 2012. The current PM2.5 primary annual standard is at a level of 12.0 

ug/m3(annual arithmetic mean, averaged over three years) and the primary 24-hour standard is at a level 

of 35 ug/m3(98th percentile, averaged over three years). The current 24-hour secondary standard is 

identical to the primary standard at a level of 35 ug/m3. The secondary annual standard is 15.0 ug/m3

(annual arithmetic mean, averaged over three years). (78 FR 3086, January 15, 2013.)

Figure 8 shows the total annual emissions from point sources and three sub-categories for 1984 

through 2011. The 2012 Annual Report includes additional information regarding point and area 

sources that contribute to PM emissions in North Dakota. Most direct emissions of PM in North Dakota 

come from major stationary sources such as large coal-fired facilities (e.g., power plants and sugar 

factories). The only appreciable source of direct PM emissions from oil and gas production operations 

is from development of the well pad which is of short duration. Vehicle traffic would be the only other 

significant source of PM emissions including fugitive dust from traffic on unpaved roads. Once a well is 

developed, these emissions usually decrease substantially. 

Figures 9 and 10 show the North Dakota monitoring data relative to the 24-hour PM10 standard 

and 24-hour PM2.5 standard. All the 2012 concentrations are well below the standards. 
15

Figure 8. North Dakota Annual Point Source PM10 Emissions

Figure 9. North Dakota PM10 Trends – 24-Hour Standard, 2

nd Max Values

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012

PM (tons)

TOTAL UTILITY BOILERS OTHER POINT SOURCES

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

1980 1985 1990 1995 2000 2005 2010 2015

ug/m3

Bismarck PM10 24hr 

2nd

Fargo PM10 24hr 2nd

Dunn PM10 24hr 2nd

TRNP PM10 24 hr 2nd

Beulah PM10 24hr 2nd

Hannover PM10 24hr 

2nd

Lostwood PM10 24hr 

2nd

PM10 24-hr Standard
16

Figure 10. North Dakota PM2.5 Trends – 24-Hour PM2.5 Standard

Carbon Monoxide:

Carbon monoxide (CO) is a colorless, odorless gas emitted from combustion processes. 

Nationally and, particularly in urban areas, the majority of CO emissions in ambient air come from 

automobiles. CO can cause harmful health effects by reducing oxygen delivery to the body’s organs and 

tissues. 

Due to its relatively low population, North Dakota does not have the number of mobile sources 

that would generally create CO emission concerns. There are several major stationary sources that do 

emit greater than 100 tpy of CO emissions. These include coal-fired steam-powered electrical 

generating facilities, a coal gasification plant, natural gas processing plants, an oil refinery, sugar 

factories, and a compressor station. Many of these are the same sources that are the major emitters of 

SO2 and NOx but the corresponding CO levels from these sources are considerably lower. Oil and gas 

well equipment does not emit high levels of CO. CO monitoring in North Dakota was terminated in 

1994 after operating for five years. The data indicated North Dakota did not have significant 

concentrations of CO. The 2012 Annual Report includes additional information regarding sources that 

contribute to CO emissions in North Dakota.

0

5

10

15

20

25

30

35

40

1999 2001 2003 2005 2007 2009 2011 2013

Ug/m3

Bismarck 2.5 24hr

Fargo PM2.5 24hr

Dunn PM2.5 24hr

Hannover PM2.5 24hr

Lostwood PM2.5 24hr

TRNP PM2.5 24hr

Beulah PM2.5 24hr

PM 2.5 24hr Standard
17

Lead:

Lead is a metal found naturally in the environment as well as in manufactured products. The 

major sources of lead emissions have historically been from fuels in on-road motor vehicles (such as 

cars and trucks) and industrial sources. As a result of EPA's regulatory efforts to remove lead from onroad motor vehicle gasoline, emissions of lead from the transportation sector dramatically declined by 

95 percent between 1980 and 1999, and levels of lead in the air decreased by 94 percent between 1980 

and 1999. Today, the highest levels of lead in air are usually found near lead smelters. The major 

sources of lead emissions to the air today are ore and metals processing and piston-engine aircraft 

operating on leaded aviation gasoline.

North Dakota determined through prior monitoring that the state has low lead concentrations. 

The State has no significant lead point sources. These considerations coupled with the federal 

requirement for monitoring primarily near point sources and in urbanized areas, caused North Dakota to 

terminate its lead monitoring program in 1983. 

Future Oil and Gas Development in North Dakota:

The North Dakota Department of Mineral Resources estimates future oil and gas development 

will proceed at a pace of approximately 2,000 new wells per year with 40,000 new wells completed over 

approximately the next 20 years.

5

 EPA reviewed various reports for obtaining oil and gas production 

forecasts.

6, 7

 Emissions information for oil and gas activity in the Williston Basin in 2009 and 

projections for 2015 is available in two reports developed under the direction of the Western Governor’s 

Association (WGA).8,9 EPA used this emissions information to conduct the roll-forward analysis below. 

The WGA reports are available in the docket for this action.

Roll-Forward Analysis for SO2 and NO2:

To assess potential future air quality conditions as a result of the State’s minor source permitting 

rule revision, EPA conducted a roll-forward analysis for SO2 and NO2 similar to the analysis states 

perform in maintenance demonstrations. We did not include PM or O3 in this analysis. The available 

monitoring data for PM is not conducive to the analysis as further discussed below, and a roll-forward 

analysis is not appropriate for predicting O3 impacts in North Dakota due to the complex chemistry 

involved in the formation of this secondary pollutant (there is a lack of a predictable correlation between 

NOx and VOC emissions to O3 concentrations). Nonetheless, based on the roll-forward analysis for SO2

and NOx, we would anticipate the same conclusions for PM. Regarding O3 formation in western North 

Dakota, this NOx limited environment where VOC emissions dominate the overall emissions from oil 

 

5 North Dakota Department of Mineral Resources, presentation to Government Finance Interim Committee, December 12, 

2013. Available in the docket for this action and at: https://www.dmr.nd.gov/oilgas/presentations/GovFinance121213.pdf

6 U.S. Department of Interior, Bureau of Land Management, February 25, 2011. “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.” 

7 U.S. Department of Interior, Bureau of Land Management, October 2, 2009. “Reasonable Foreseeable Development 

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

8 Amnon Bar-Ilan, et al., June 25, 2013. “Development of Baseline 2009 Emissions from Oil and Gas Activity in the 

Williston Basin.” Prepared for Western Governor’s Association. Prepared by ENVIRON International Corporation, Novato, 

CA.

9 Amnon Bar-Ilan, et al., July 25, 2013. “Development of 2015 Oil and Gas Emissions Projections for the Williston Basin.” 

Prepared for Western Governor’s Association. Prepared by ENVIRON International Corporation, Novato, CA.
18

and gas operations, has not historically seen increasing O3 concentrations even with increasing 

emissions of NOx. We would anticipate the O3 concentrations would remain below the O3 NAAQS 

based on some of the assumptions in our roll-forward analysis for NOx and as discussed in more detail 

below. Finally, we also did not include CO or lead in this roll-forward analysis since these pollutants 

are not present at appreciable levels and are no longer included in the State’s monitoring program.

The emissions presented in the WGA Williston Basin reports were used in this analysis and 

include the emissions from all the states (North Dakota, South Dakota, and Montana) and tribes located 

within the basin. EPA did not make adjustments to remove emissions from outside North Dakota as the 

percentage of increased emissions used in the roll-forward analysis should be approximately the same 

for the entire basin as compared to those for North Dakota alone. 

 

The WGA 2009 baseline emissions, 2015 projected emissions and hypothetical 2021 emissions 

are shown in Table 3.

Table 3. WGA Emission Estimates

Pollutant WGA 2009 Baseline 

Emissions (tons)

WGA 2015 Projected 

Emissions (tons)

Hypothetical 

Emissions Projected 

to 2021 (tons)*

SO2 2,081 7,046 12,011

NO2 (as NOx) 14,387 46,114 77,841

PM 1,045 2,596 4,147

*The 2021 emissions are projected from a linear extrapolation of the 2009 and 2015 emissions.

The increases for 2015 as percentages are shown in Table 4.

Table 4. Emission Increase Percentages

Pollutant WGA 2015 Projected 

Emissions 

(% of 2009)

Hypothetical 

Emissions Projected 

to 2021 (% of 2009)

SO2 339 577

NO2 (as NOx) 321 541

PM 248 397

Ambient data is complete in AQS through 2012, so design values can be determined for the 2009 

baseline emission year, and for 2012, the most complete monitoring year. Therefore, an estimate of 

emissions for the 2012 monitoring year would be useful in projecting the impact of future emission 

growth on monitored values. 2012 emissions values are estimated in Tables 5 and 6 by assuming linear 

growth in emissions from the 2009 baseline year to the 2015 projection year.
19

Table 5. Emissions, Including Linear Interpolation of 2012 Estimated Emissions

Pollutant WGA 2009 

Baseline 

Emissions (tons)

Interpolated 

2012 Projected 

Emissions 

(tons)

WGA 2015 

Projected 

Emissions (tons)

Hypothetical 

Emissions 

Projected to 2021 

(tons)

SO2 2,081 4,564 7,046 12,011

NO2 (as NOx) 14,387 30,251 46,114 77,841

PM 1,045 1,821 2,596 4,147

Table 6. Estimated Percentage in Emissions Growth, Including 2012

Pollutant Estimated Percent 

Growth by 2012 (% of 

2009)

WGA 2015 Projected 

Emissions (% of 

2009)

Hypothetical 

Emissions Projected 

to 2021 (% of 2009)

SO2 219 339 577

NO2 (as NOx) 210 321 541

PM 174 248 397

Ambient monitoring data is available for 2009 and 2012 at a number of monitoring sites around 

the state. Sites southeast of the prime oil and gas area are located near large lignite power plants 

northwest of Bismarck, so are not ideally sited to monitor impacts of oil and gas development. Many 

have also shown flat or downward trends in pollution levels from 2009 to 2012 while emissions from oil 

and gas development have been increasing. This may reflect recent addition of emission controls on 

some of the dominant power plant stacks. Overall total power plant SO2, NOx and PM emissions have 

been greater and are in closer proximity to these monitors than have been emissions of the same 

pollutants from oil and gas development. The Williston monitoring site does not have data to allow 

design value calculation in both 2009 and 2012 needed for a roll-forward assessment, as monitoring only 

began there in 2013. Theodore Roosevelt National Park North Unit and Lostwood NWR, on the 

southern and northern edges of the oil and gas development areas, respectively, and Dunn Center to the 

southeast are the most appropriate monitors for use in the roll-forward analysis, and all are currently 

within 1 to 4 miles of active well pads. Design values from the sites are shown in Table 7. PM2.5 was 

not monitored with regulatory monitors at these sites until 2010. Figure 11 shows the location of the 

monitoring sites in relation to North Dakota power plants.
20

Table 7. NW North Dakota Monitored Ambient Design Values

Monitoring Site 2009 Design Values 2012 Design Values

SO2

(ppb)

1-hr 

Standard

NO2

(ppb)

1-hr 

Standard

PM2.5

(ug/m3)

24-hr 

Standard

SO2

(ppb)

1-hr 

Standard

NO2

(ppb)

1-hr 

Standard

PM2.5

(ug/m3)

24-hr 

Standard

Lostwood NWR 42* 16 -- 33 17 15*

TRNP-NU 11 7 -- 10 10 18*

Dunn Center 12 13 -- 13* 11* 15*

*Data marked are incomplete in AQS and a valid, regulatory design value cannot be calculated that complies with the 

applicable 40 CFR part 50 appendix. For the engineering analysis herein,, as opposed to a finding of attainment or nonattainment or other regulatory decision, the incomplete design value is believed to be sufficiently representative.

Figure 11. Monitor (Orange) and Power Plant (Black) Locations in Western North Dakota
21

For both NO2 and SO2, trends from 2009 to 2012 at the three sites have been both upward and 

downward, despite large increases from oil and gas operations10 which we expect were accompanied by 

increases in NOx and VOC emissions. At Lostwood NWR there has there been a small increase in the 

NO2 design value (from 16 to 17 ppb) from 2009 to 2012, while at TRNP there has been a larger 

increase of 3 ppb, although from a lower baseline value in 2009. Dunn Center has seen a 2 ppb decrease 

in NO2 design value in the same period. For SO2, Dunn Center has seen a 1 ppb increase in the 2009-

2012 period, while Lostwood NWR and TRNP have seen SO2 decreases. For PM2.5, regulatory PM2.5

monitors were not operating at any of the sites prior to 2010, so 2007-2009 PM2.5 design values are not 

available at any of the sites. A roll-forward analysis for PM impacts therefore cannot be conducted in a 

manner similar to that for SO2 and NO2.

The greatest NO2 increase was the 3 ppb increase at TRNP-NU, while the largest SO2 increase 

was the 1 ppb increase at Dunn Center. For purposes of the roll-forward analysis, it could be concluded 

that the impact from oil and gas emissions growth between 2009 and 2012 at all three monitors was 3 

ppb of NO2 increase or less and 1 ppb of SO2 increase or less, and then roll forward these impacts 

proportionally using the larger emission increases projected for the future. For a doubling of NO2

emissions from oil and gas between 2009 and 2012, monitors saw no more than a 3 ppb increase. For 

the 321% increase projected in NO2 emissions between 2009 and 2015, there would be a proportionate 

no more than (321%/210%)*3 ppb = 4.6 ppb increase in ambient concentration. Similarly by 2021, for a 

541% increase in NO2 emissions, there would be no more than a (541%/210%) * 3 ppb = 7.7 ppb 

increase in ambient concentrations of NO2. For SO2, with a 1 ppb concentration increase at Dunn 

Center, the growth in concentration by 2015 would be 339%/219% * 1 ppb = 1.55 ppb, and by 2021 

would be 577%/291% * 1 ppb = 2.5 ppb. These calculations are summarized in Table 8.

Table 8. SO2 and NO2 Roll-Forward Calculations

Pollutant Impacted 

Site

2009 to 2012 

Concentration 

Growth

2009 to 

2012 

Growth

Factor

2012 to 2015 

Growth Factor

2012 to 2021 

Growth Factor

NO2 TRNPNU3 ppb 210% 321%/210% = 

1.53 (4.6 ppb)

577%/210% = 2.58 

(7.7 ppb)

SO2 Dunn 

Center

1 ppb 219% 339%/219% = 

1.55 (1.55 ppb)

577%/219% = 2.5 

(2.5 ppb)

Regarding O3, while the relationship between NOx and O3 concentrations is not linear, some 

conclusions may be drawn based on the historical monitoring data and the estimated doubling of NOx

emissions discussed above for the time period, 2009 to 2012. The O3 design values and trends provided 

in Table 2 and Figure 3 above, demonstrate that there was no change or that there was a decrease in O3

design values at the most relevant monitoring sites, TRNP-NU and Lostwood NWR, during the time 

 

10 Evidence of trends in oil and gas development is presented in “Director’s Cut” reports prepared by the NDIC Department 

of Mineral Resources and available at https://www.dmr.nd.gov/oilgas/ . The January 14, 2014 report is included in the 

docket for this action.
22

period 2009 to 2012. Given a steady state or decreasing ozone environment at the most impacted sites 

during the emissions growth to date, with existing design values less than 80% of the current NAAQS, 

significant margin exists before continued NOx emission growth could threaten the ozone NAAQS.

We present these calculations as a means of roughly characterizing the expected impact of 

increased oil and gas exploration on ambient air quality, given that the immediate practical effect of this 

revision to retain the current approach of exempting oil and gas exploration from being subject to minor 

source permitting requirements. Although we recognize that this analysis is imprecise, in light of the 

fact that monitors in North Dakota currently read well below the relevant NAAQS, we believe the 

analysis does support the conclusion that cumulative impacts on any existing monitors from additional 

oil and gas exploration under the current approach would likely also remain well below the NAAQS(We 

note, however, that EPA has not yet issued a designation decision for North Dakota under the SO2

NAAQS, and the outcome of that future decision may necessitate further SIP revisions if the State is 

required to develop for EPA approval a future demonstration of attainment of the SO2 NAAQS for any 

portion of the State.)

Given that the majority of the emission increases are projected to come from many distributed 

minor sources, it is possible that local impacts could be higher at areas within the oil and gas 

development area not currently monitored. The TRNP-NU, Lostwood NWR and Dunn Center monitors 

are currently impacted by localized oil and gas activity, however, with multiple well pads within one

mile of the Lostwood NWR monitor and Dunn Center, and well pads within four miles of the TRNP-NU

monitor. The trends seen by these monitors should, therefore, well represent the recent impacts of 

localized oil and gas emissions growth, and be valid data sets for roll-forward estimation, even of

localized impacts within the oil and gas development area. In addition, we note that many future oil and 

gas activities will be subject to additional controls pursuant to 40 CFR part 60, subpart OOOO, which 

further supports the conclusion that retaining the current approach for oil and gas permitting will not 

interfere with attainment and maintenance of the NAAQS.

Additional Considerations:

Another consideration relevant to future development and in support of the April 2011 

permitting revisions is North Dakota’s effort to establish additional authorities to issue general permits. 

North Dakota completed its rulemaking process and submitted the general permit provision to EPA with 

a SIP submission in January 2013. A general permit would allow the State to group numerous similar 

sources, such as oil and gas production operations, under a single permit and would provide a 

mechanism to manage preconstruction decisions related to oil and gas operations should changing air 

quality conditions in the future require curtailing new development. EPA will act separately on the 

general permit provision.

We also note that the State revised and submitted the revision to its broad coverage of NSPS and 

MACT requirements to only state-adopted NSPS and MACT requirements before NSPS subpart OOOO 

became effective. Merely because of EPA’s promulgation of the NSPS subpart OOOO, North Dakota’s 

previously-existing, SIP-approved catch-all provision triggered a huge expansion of the number of 

sources required to apply for and obtain a minor source permit. This expansion did not result from a 

reasoned consideration of the types and sizes of sources appropriate for new source review, but the 
23

arbitrary effect of North Dakota’s preexisting rule. North Dakota took the timely and proactive step to 

avoid this unintended consequence by adopting and submitting the revision we are considering in this 

analysis, and we are mindful that North Dakota’s revision will not alter the universe of minor sources 

that were subject to North Dakota’s minor NSR review before EPA promulgated NSPS subpart OOOO. 

Conclusions:

In conclusion, past air quality trends based on monitoring data are favorable and show that 

current trends in emissions growth, primarily from oil and gas operations, have not contributed to 

interference with national ambient air quality standards or the State’s SIP control strategy, and we do not 

expect this to change in the future. Furthermore, the projected emissions from oil and gas operations 

should not cause NAAQS violations as discussed in the roll-forward analysis conducted herein. The 

changes in NDAC Chapter 33-15-14 only affect the applicability of certain permitting requirements 

contained in that Chapter. These rule changes do not affect emission limits in the SIP or other 

requirements that would affect ambient concentrations of criteria pollutants. National emissions 

standards, such as those in 40 CFR 60 subpart OOOO for oil and gas production operations, still apply 

to North Dakota regardless of North Dakota’s permitting or registration requirements. These changes 

are consistent with CAA and regulatory requirements. The changes that EPA is proposing to approve 

should not interfere with maintenance of the NAAQS or any other CAA requirements.