## Technical Support Document

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## 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 20142

Executive Summary:

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

Governor o f North Dakota on April 14, 2011

. As described in our proposed rule, most of the revisions we are approving merely conform the North Da kota 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 oi l and

ga s 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 othe r 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 No rth Dakota’s air pollution control rules regarding general provisions, ambient air quality standards (sulfur dioxide (SO 2 ), nitrogen dioxide (NO 2 ), 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) C hapter 33

- 15

- 14. In addition to several housekeeping revisions, the S tate made revisions with the intent to change the permitting requirement for sources subject to a new source perform ance 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 a nd 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; wit h 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 subje ct 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 ado pt into the NDAC. S tate 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 NSP S 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

. U nder CAA s ection 110(l), EPA cannot approve a revision to a state’s

SIP without a demonstration that the revision w ill 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 findin g 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 sou rce (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 , t he Stat e 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, t his exe mption 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 regist er with

the State. North Dakota’s oil and gas registration program was approved into the SIP in 19 87. The permitting exemption for oil and gas production (well) facilities was approved into the SIP in 19 95.

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 re gi stration form and an analysis of any gas produced from the

well w ithin 90 days of the completion or r ecompletion 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 ambi ent air quality

standards , to conduct routine inspections, to instal l any necessary equipment to ensure compliance with ambient air quality standards, and to notif y 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 t o clarif

y 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 memo randum 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 Hea lth...”

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

year s. 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 t he Bakken

Pool

. 3 The Bakken Pool guidance is intended to assist operato rs 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. A s a n 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 redu ce 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 wells 4 further 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 unde r 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;

 c onnected to a gas gathering line ;

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

well ;

 e quipped 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 compr ession 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

 e quipped with other value

- added processes as approved by the North Dakota I ndustrial

C ommission 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 tan ks (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 cont rolled 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 lea st 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 che cks 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 (O 3 ) , NO 2 , and SO 2 . EPA assessed O 3 and N O 2 because volatile organic compounds and nitrogen oxides (NO

x ) emissions from oil and natural gas production facilities are precursors to O 3 formation. EPA also

assessed SO 2 which is often associated with oil and natural gas production. While SO 2 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 di scussed 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 stan dard, 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 A Q S 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 Nati onal Park N orth U nit (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 informat ion 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:

O 3 is formed by the interaction of directly

- emitted precursor emissions, VOCs and NO

x , 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 d uring 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 O 3 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 th e impacts of oil development on ozone levels.

Statewide, m ajor 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

containe r 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 em issions in North Dakota.

Figure 2 shows how the North Dakota monitoring data compares to the 2008 O 3 standard and reflects a slightly downward trend

. To attain the 2008 O 3 standard, the 3

- year average of the fourth

highest daily maximum 8

- hour average O 3 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 O 3 standard with a current maximum design

value of .059 ppm at the Lostwood NWR site based on 20 10, 20 11, and 20 12 data

. The maximum design value for Lostwood was 0 .060 ppm using 200 9, 20 10, and 20 11 data. Table 2 provides historical8

O 3 design values for the past ten years

. Figure 3 sho ws the design value trends for the past ten years are relatively static.

Figure 2. North Dakota O 3 Trends

- Annual 4th Max 8

- hr O 3 Standard

Table 2

. Historical O 3 Design Values (ppm)

3

- Year Average of 4 th Highest Daily Max imum

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 O 3 Design Value Trends 2003

– 2012

3

- Year Average of 4 th Highest Daily Maximum

8

- hour Average

The O 3 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 O 3 design values statewide, most notably at the monitoring sites located closest to the oil and gas development area , TRN P

- 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 de sign values less than 80% of the current NAAQS, significant margin

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

detail in the roll

- forward analysis section below.

Nitrogen Dioxide:

NO 2 is one of a group of highly reactive gasses known as “oxides of nitrogen,” or “nitrogen oxides.” EPA’s NAAQS uses NO 2 as the indicator for the larger group of NO

x . NO 2 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 O 3 , and fine particle pollution, NO 2 is linked with a number of adverse effects on the respiratory system.

The larger NO

x 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 Standard10

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

total NO

x 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 NO

x emissions in Nort h Dakota.

EPA first set standards for NO 2 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 re viewed 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 NO 2 standards.

Figure 5 shows North Dakota’s total ann ual NO

x emissions from point sources and two sub

categories for 1984 through 2011. The 2012 Annual Report includes additional information regarding point and area sources that contribute to NO

x emissions in North Dakota. Figure 5 shows the North Dakota monitoring data for NO 2 . All 98 th percentile values are less than half of the 100 ppb standard.

Figure 4 . North Dakota Annual Point Source NO

x Emissions

0 20000 40000 60000 80000 100000 120000 140000

1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 NO x (tons)

TOTAL UTILITY BOILERS OTHER POINT SOURCES11 Figure 5 . North Dakota Ambient NO 2 Trends

Sulfur Dioxide:

SO 2 is formed when sulfur containing compounds are burned (oxidized). SO 2 is a byproduct of many industrial processes. SO 2 is one of a group of highly reactive gases known as “oxides of sulfur.” EPA recently established a new 1

- hour SO 2 standard at a level of 75 parts per billion (ppb), based on the

3

- year average of the annual 99 th percentile of 1

- hour daily maximum concentrations. EPA also revoked both the existing 24

- hour and annual primary SO 2 standards (see 75 FR 3552 0). 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 SO 2 NAAQS . The largest sources of SO 2 emissions in North Dakota are from energy development in the west and west

- central portions of the State . These sources include coal

- fired steam

po wered 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 SO 2 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

SO 2 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 99 th percentile, 1

- hour SO 2 standard. All the monitored 2012 99 th 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 SO 2 NAAQS, t he static or decreasing trend in monitored SO 2 ambient trend s 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 concentratio ns of SO 2 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 w ere 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 SO 2 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 BOILERS13 Figure 7 . North Dakota SO 2 Trends

– 99 th Percentile 1

- H our SO 2 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, met als, and soil or dust particles.

The size of particles is directly l inked 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 smalle r 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., SO 2 and NO

x ). 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 PM 10

. 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 PM 10 standards that were identical to the primary standards. ( 52 FR 24634 , July 1, 1987. ) Effective December 18, 2006, EPA

revoked the a nnu al PM 10 standard but retained the 24

- hou r PM 10 standard. ( 71 FR 61144

, October 17,

2006

. )

On July 18, 1997, EPA established primary standards for PM 2.5 . These included a 24

- hour standard at a level of 65 ug/m 3 (98 th percentile, averaged over three years) and an annual standard at a level of 15.0 ug/m 3

. At that time, EPA also established secondary PM 2.5 standards that were identical to the primary standards. (62 FR 38652, July 18, 1997.) These standards were revie wed and , in some

cases, revised in 2006 and in 2012. The current PM 2.5 primary annual standard is at a level of 12.0 ug/m 3 (annual arithmetic mean, averaged over three years) and the primary 24

- hour standard is at a level

of 35 ug/m 3 (98 th percentile, ave raged over three years). The current 24

- hour secondary standard is identical to the primary standard at a level of 35 ug/m 3 . The secondary annual standard is 15.0 ug/m 3
(annual arithmetic mean, averaged over three years). ( 78 FR 3086, January 15, 2013. )

Figure 8 show s 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 substanti ally.

Figures 9 and 10 show the North Dakota monitoring data relative to the 24

- hour PM 10 standard

and 24

- hour PM 2.5 standard. All the 2012 concentrations are well below the standard s.15 Figure 8 . North Dakota Annual Point Source PM 10 Emissions

Figure 9

. North Dakota PM 10 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 PM 10 24

- hr Standard16 Figure 10 . North Dakota PM 2.5 Trends

– 24

- Hour PM 2.5 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, Nor th 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

generat ing 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

SO 2 and NO

x but the corresponding CO levels from these sources are considerably lower

. Oil and gas

well equipment do es 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

c oncentrations of C O. 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 Standard17

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 on

road motor vehicle gasoline, emissions of lead from the transportation s ector 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 emissio ns 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 t he state has low lead concentrations. The State has no significant lead point sources. T hese considerations coupled with the federal requirement for monitoring primarily near point sources and in urbanized areas, caused North Dakota to
terminat e 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 repo rts 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 SO 2 and NO 2 :

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 SO 2 and NO 2 similar to the analysis states perform in maintenance demonstrations. We did not include PM or O 3 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 O 3 impacts in North Dakota due to the complex chemistry involved in the formation of this secondary pollutant ( there is a lac k of a predictable correlation between

NO

x and VOC emissions to O 3 concentrations )

. Nonetheless, based on the roll

- forward analysis for SO 2 and NO

x , we would anticipate the same conclusions for PM

. Regarding O 3 formation in western North

Dakota

, this NO

x 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, Fe bruary 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 Willis ton Basin.” Prepared for Western Governor’s Association. Prepared by ENVIRON International Corporation, Novato, CA.18

and gas operations, has not historically seen increasing O 3 concentrations even with increasing

emissions of NO

x . We would anticipate the O 3 concentrations would remain below the O 3 NAAQS based on some of the assumptions in our roll

- forward analysis for NO

x and as discussed in more detail

below. Finally, w e also did not include CO or lead in this roll

- forward analysis since these pollutants are not present at appreciable leve ls 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 locat ed 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 b aseline emissions, 2015 projected emissions and hypothetical 2021 e missions

are shown in T able 3

.

Table 3

. W GA Emission Estimates

Pollutant W GA 2009 Baseline

Emissions (tons) W GA 2015 Projected

Emissions (tons) Hypothetical

Emissions Projected to 2021 (tons) *

SO 2 2,081 7,046 12,011

NO 2 (as NO

x ) 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 W GA 2015 Projected

Emissions (% of 2009) Hypothetical

Emissions Projected to 2021 ( % of 2009 )

SO 2 339 577

NO 2 (as NO

x ) 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 proj ecting 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 W GA 2009

Baseline Emissions (tons) Interpolated

2012 Projected

Emissions (tons) W GA 2015

Projected Emissions (tons) Hypothetical

Emissions Projected to 2021 (tons)

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

NO 2 (as NO

x ) 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 )

SO 2 219 339 577

NO 2 (as NO

x ) 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 SO 2 , NO

x and PM emissions have
been greater and ar e 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 assess ment , as monitoring only
began there in 2013 . T heodore 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 mo nitors 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

. PM 2.5 was not monitored with regulatory monitors at these si tes until 2010. Figure 11 shows th e 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

SO 2 (ppb)

1

- hr

Standard NO2

(ppb)

1

- hr

Standard PM 2.5

(ug/m 3 )

24

- hr

Standard SO 2

(ppb)

1

- hr

Standard NO 2

(ppb)

1

- hr

Standard PM 2.5

(ug/m 3 )

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 a ppendix. For the engineering analysis herein, , as opposed to a finding of attainment or non

attainment or other r egulatory decis i on , the incomplete design value is believed to be sufficiently representative.

Figure 11. Monitor (Orange) and Power Plant (Black) Locations in Western North Dakota21

For both NO 2 and SO 2 , trends from 2009 to 2012 at the three sites have been both upward and
downward, despite large increases from oil and gas operations 10 which we expect were accompanied by

increases in NO

x and VOC emissions

. A t Lostwood NWR there has there been a small increase in the

NO 2 design value (from 16 to 17 ppb) from 2009 to 2012 , while at T RNP 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 NO 2 design value in the same period. For SO 2 , Dunn Center has seen a 1 ppb increase in the 2009

- 2012 period, while Lostwood NWR and T RNP have seen SO 2 decreases. For PM 2.5 , regulatory PM 2.5 monitors were not operating at any of the sites prior to 2010, so 2007

- 2009 PM 2.5 design values are not
available at any of the sites. A r oll

- forward analysis for PM impacts therefore can no t be conducted in a

manner similar to that for SO 2 and NO 2

.

The greatest NO 2 increase was the 3 ppb increase at TRNP

- NU , while the largest SO 2 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 NO 2 increase or less and 1 ppb of SO 2 increase or les s, and then roll forward these i mpacts proportionally u sing the larger emission increases projected for the future. F or a doubling of NO 2 emissions from oil and gas between 2009 and 2012, monitors saw no more than a 3 ppb increase. For
the 321% increase projected in NO 2 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 NO 2 emissions, there would be no more than a (541%/210%) * 3 ppb = 7.7 ppb

increase in ambient concentrations o f NO 2 . For SO 2 , 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

. SO 2 and NO 2 Roll

- Forward Calculations

Pollutant Impacted

Site 2009 to 2012

Concentration

Growth 2009 to

2012

Growth

Factor 2012 to 2015

Growth Factor 20 12 to 2021

Growth Factor

NO 2 TRNP

NU 3 ppb 210% 321%/210% = 1.53 (4.6 ppb) 577%/210% = 2.58

(7.7 ppb)

SO 2 Dunn

Center 1 ppb 219% 339%/219% = 1.55 (1.55 ppb) 577%/219% = 2.5

(2.5 ppb)

Regarding O 3 , while the relationship between NO

x and O 3 concentrations is not linear, some
conclusions may be drawn based on the historical monitoring data and the estimated doubling of NO

x emissions discussed above for the time period, 2009 to 2012. The O 3 design values and trends provided
in Table 2 and Fig ure 3 above, demonstrate that there was no change or that there was a decrease in O 3 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 Resour ces 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 a t 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 NO

x emission growth c ould 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 a nd 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
analysi s 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 dec ision for North Dakota under the SO 2 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 SO 2 NAAQS for any
portion of the Stat e.)

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 , Lostw ood 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 see n 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 attainmen t 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, und er 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 p rovision.

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 consid eration of the types and sizes of sources appropriate for new source review, but the23

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 r evision 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 conc lusion, 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 Ch apter 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 regula tory requirements. The changes that EPA is proposing to approve

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