773 San Marin Drive, Suite 2115, Novato, CA 94998 415.899.0700 

ENVIRON International Corporation 

Final Report 

DEVELOPMENT OF 2015 OIL AND GAS EMISSIONS PROJECTIONS 

FOR THE WILLISTON BASIN 

Prepared by 

Amnon Bar-Ilan 

Rajashi Parikh 

John Grant 

Yesica Alvarez 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

Kathleen Sgamma 

Western Energy Alliance 

410 17th Street, Suite 1920 

Denver, CO 80202 

Phase III Oil & Gas Emissions Inventory Project 

July 25, 2013 
July 2013 

Final Report i

TABLE OF CONTENTS 

 Page 

INTRODUCTION ......................................................................................................................1

GEOGRAPHIC GROUPING ......................................................................................................2

PARAMETERS PROJECTED ....................................................................................................3

PROJECTION METHODOLOGIES FOR THE WILLISTON BASIN .......................................6

Associated Gas Flaring and Venting ........................................................................................6

Bakken Formation Counties ....................................................................................................8

Cedar Creek Anticline Counties ............................................................................................ 12

Other Counties ...................................................................................................................... 17

SCALING FACTOR DEVELOPMENT AND UNCONTROLLED 2015 

EMISSIONS ....................................................................................................................... 23

CONTROLLED 2015 EMISSIONS .......................................................................................... 25

Nonroad Diesel Engine Standards and Fuel Sulfur Standards ................................................ 26

New Source Performance Standards for Stationary Spark-Ignited Engines ............................ 27

New Source Performance Standards for Pneumatic Devices .................................................. 28

New Source Performance Standards and Montana Regulations for Well Completions ........... 28

New Source Performance Standards and Montana and North Dakota Regulations for Crude 

Oil and Condensate Tanks ..................................................................................................... 29

SUMMARY RESULTS ............................................................................................................ 30

REFERENCES ......................................................................................................................... 39

LIST OF TABLES 

Table 1. Scaling parameter for each oil and gas source category considered in this 

inventory. ..................................................................................................................3 

Table 2. Scaling factors for five parameters used in the projection analysis for all 

counties in the Williston Basin. ................................................................................ 23 

Table 3. Summary of federal and state “on-the-books” regulations affecting the oil 

and gas source categories considered in this inventory. ............................................ 25

Table 4. Federal NSPS emissions standards for engines less than 25 horsepower. .................. 27

Table 5. Federal NSPS emissions standards for engines greater than 25 

horsepower but less than 100 horsepower. ............................................................... 28

Table 6. Federal NSPS emissions standards for engines greater than 25 

horsepower but less than 100 horsepower. ............................................................... 28

Table 7. Crude oil tank controls assumptions in the 2015 Williston Basin midterm 

emissions. ................................................................................................................ 29

Table 8. 2015 emissions of all criteria pollutants by county for the Williston Basin. .............. 33

Table 9. 2015 NOx emissions by county and by source category for the Williston 

Basin. ...................................................................................................................... 35
July 2013 

Final Report ii

Table 10. 2015 VOC emissions by county and by source category for the Williston 

Basin. ...................................................................................................................... 37

LIST OF FIGURES 

Figure 1. Fraction of gas produced that is processed and sold in the Bakken 

Formation in North Dakota and Montana. ..................................................................7

Figure 2. Total well count historical data (from the IHS database) for Bakken 

Formation Counties in the Williston Basin and projections to 2015. ...........................8

Figure 3. Spud count historical data (from the IHS database) for Bakken Formation 

Counties in the Williston Basin and projections to 2015. ............................................9

Figure 4. Total gas production historical data (from the IHS database) for Bakken 

Formation Counties in the Williston Basin and projections to 2015. ......................... 10

Figure 5. Oil production historical data (from the IHS database) for Bakken 

Formation Counties in the Williston Basin and projections to 2015. ......................... 11

Figure 6. Condensate production historical data (from the IHS database) for the 

Bakken Formation Counties in the Williston Basin and projections to 

2015......................................................................................................................... 12

Figure 7. Total well count historical data (from the IHS database) for Cedar Creek 

Anticline Counties in the Williston Basin and projections to 2015. .......................... 13

Figure 8. Spud count historical data (from the IHS database) for Cedar Creek 

Anticline Counties in the Williston Basin and projections to 2015. .......................... 14

Figure 9. Total gas production historical data (from the IHS database) for Cedar 

Creek Anticline Counties in the Williston Basin and projections to 2015. ................ 15

Figure 10. Oil production historical data (from the IHS database) for Cedar Creek 

Anticline Counties in the Williston Basin and projections to 2015. .......................... 16

Figure 11. Condensate production historical data (from the IHS database) for Cedar 

Creek Anticline Counties in the Williston Basin and projections to 2015. ............... 17

Figure 12. Total well count historical data (from the IHS database) for Other 

Counties in the Williston Basin and projections to 2015. .......................................... 18

Figure 13. Spud count historical data (from the IHS database) for Other Counties in 

the Williston Basin and projections to 2015. ............................................................ 19

Figure 14. Total gas production historical data (from the IHS database) for Other 

Counties in the Williston Basin and projections to 2015. .......................................... 20

Figure 15. Oil production historical data (from the IHS database) for Other Counties 

in the Williston Basin and projections to 2015. ........................................................ 21

Figure 16. Condensate production historical data (from the IHS database) for Other 

Counties in the Williston Basin and projections to 2015. .......................................... 22

Figure 17. 2015 NOx emissions by source category and by county in the Williston 

Basin. ...................................................................................................................... 31
July 2013 

Final Report iii

Figure 18. 2015 VOC emissions by source category and by county in the Williston 

Basin. ...................................................................................................................... 31

Figure 19. 2015 NOx emissions contributions by source category in the Williston 

Basin. ...................................................................................................................... 32

Figure 20. 2015 VOC emissions contributions by source category in the Williston 

Basin. ...................................................................................................................... 32
July 2013 

Final Report 1

INTRODUCTION 

This document outlines the projection methodologies used in generating the 2015 emissions 

projections from oil and gas sources in the Williston Basin. These methodologies will use as a 

starting point the 2009 baseline Williston Basin oil and gas emissions inventory, described in the 

baseline emissions report entitled “Development of Baseline 2009 Emissions from Oil and Gas 

Activity in the Williston Basin”. Like the midterm inventory for the Powder River Basin, the 

Williston Basin projected inventory is for calendar year 2015 rather than 2012. The 2015 

calendar year was chosen because of the long duration of the project and the Montana 

Department of Natural Resources (MTDNR) and North Dakota Department of Health (NDDOH) 

need for a farther future year projection than 2012. 

The methodology used to develop the 2015 projections for the Williston Basin is described 

below in subsections: 

 Geographic grouping of data – regional differences in production or activity are factored 

into the projection methodology by geographic region; 

 Projected parameters – seven basic parameters are projected forward to 2015 for purposes 

of developing scaling factors: total well counts, conventional gas well counts, spud 

counts, total gas production, oil well oil production, condensate production and total gas 

processed; 

 Scaling factors and developing uncontrolled emissions projections – the projected 

parameters are used to develop scaling factors (incorporating geographic groupings), and 

these scaling factors are applied to the 2009 baseline emissions; 

 Application of “on-the-books” regulations and control measures – existing regulations are 

summarized for their impacts on the future year emissions and applied to adjust the 

uncontrolled 2015 inventory. 

Projections for years beyond 2015 (not addressed in this methodology) will likely include 

additional parameters and will be based on these 2015 projections as the start year. The 

methodology for developing far future year projections will be detailed in a separate analysis. 

Following the discussion of the methodology, the results of the 2015 emissions projections for 

the Williston Basin are presented in graphical and tabular formats. 
July 2013 

Final Report 2

GEOGRAPHIC GROUPING 

The projections for 2015 have been conducted for three geographic groupings in the Williston 

Basin. These include: 

 Bakken Formation Counties – this grouping represents the core Bakken oil development 

area in the basin including Daniels, McCone, Richland, Roosevelt, Sheridan, and Valley 

Counties in Montana and Billings, Bottineau, Burke, Divide, Dunn, Golden Valley, 

McHenry, McKenzie, Mclean, Mercer, Morton, Mountrail, Oliver, Pierce, Renville, 

Rolette, Sheridan, Stark, Ward and Williams Counties in North Dakota; 

 Cedar Creek Anticline – this grouping represents the other major concentrated 

development area in the basin including Dawson, Fallon, Prairie and Wibaux Counties in 

Montana, Bowman and Slope Counties in North Dakota, and Harding County in South 

Dakota; 

 All Other Counties – this grouping contains primarily conventional gas and oil 

production areas outside of the Bakken and Cedar Creek Anticline and includes all 

remaining counties in the basin in Montana, North Dakota and South Dakota; 

As noted above, the geographic groupings were constructed to group similar production types or 

to group counties that do not represent significant fractions of the total production in the 

Williston Basin. The Williston Basin contains the core Bakken oil shale production area, 

representing significantly greater oil production than any other Phase III basin studied to date 

(Bar-Ilan, et al., 2009a; Bar-Ilan, et al., 2009b; Bar-Ilan, et al., 2009c; Bar-Ilan, et al., 2008). In 

addition to the Bakken formation, the Cedar Creek Anticline represents another major 

concentration of development and thus was projected independently of the Bakken formation. 

Finally all other counties in the basin were grouped together as “minor” counties, not 

representing significant fractions of basin-wide oil or gas production. This approach of 

identifying a core production area and a larger grouping of “minor” production counties is 

similar to that used for the Piceance Basin (Bar-Ilan, et al., 2009d). 
July 2013 

Final Report 3

PARAMETERS PROJECTED 

The 2015 projections for oil and gas emissions in the Powder River Basin rely on scaling 7 

parameters: 

 Total well counts 

 Spud counts 

 Total gas production 

 Oil well oil production 

 Condensate production 

 Total gas processed 

 Total casinghead gas flared 

These seven parameters are considered because each parameter applies to the emissions 

projections of one or more source categories. Note that the analysis uses data from the IHS 

database, which defines condensate production as liquid hydrocarbon production from wells 

which are classified as gas wells. Similarly, oil well oil production is defined as liquid 

hydrocarbon production from wells which are classified as oil wells. The classification of gas 

vs. oil wells is obtained directly from the IHS database is based on the gas-oil ratio (GOR) of the 

well, using a cutoff GOR defined either by the Montana Board of Oil and Gas or North Dakota 

Industrial Commission Division of Oil and Gas. This is the distinction made between 

condensate and oil production. Because of the large amount of primary oil production in the 

Bakken formation, the effect of this definition of condensate and oil is minor. Most of the liquid 

hydrocarbon production in the basin is in the form of primary oil. 

The mapping of source category to projection parameter is shown below in Table 1. 

Table 1. Scaling parameter for each oil and gas source category considered in this inventory. 

Source SCC Description Projection Parameter

Unpermitted 2310000100 Heaters Total Well Count 

Unpermitted 2310000220 Drill rigs Spuds 

Unpermitted 2310000230 Workover rigs Total Well Count 

Unpermitted 2310000300 Pneumatic devices Total Well Count 

Unpermitted 2310000700 Unpermitted Fugitives Total Well Count 

Unpermitted 2310000801 Gas Well Truck Loading 

Gas Well Condensate 

Production 

Unpermitted 2310000802 Oil Well Truck Loading Oil Well Oil Production 

Unpermitted 2310000820 Gas Plant Truck Loading 

Gas Well Condensate 

Production 

Unpermitted 2310001610 Venting - initial completions Spuds 

Unpermitted 2310001620 Venting - recompletions Spuds 

Unpermitted 2310001630 Venting - blowdowns Total Gas Production 

Unpermitted 2310001640 Venting - Compressor Startup Total Gas Production 

Unpermitted 2310001650 Venting - Compressor Shutdown Total Gas Production 

Unpermitted 2310002230 Condensate tank 

Gas Well Condensate 

Production 

Unpermitted 2310002240 Oil Tank Oil Well Oil Production 

Unpermitted 2310002231 Condensate tank flaring 

Gas Well Condensate 

Production 

Unpermitted 2310003100 Miscellaneous engines Total Well Count 

Unpermitted 2310003200 Pneumatic pumps Total Well Count 

Unpermitted 2310020600 Compressor engines Total Gas Production 
July 2013 

Final Report 4

Source SCC Description Projection Parameter

Unpermitted 2310021410 Dehydrator Total Gas Production 

Unpermitted 2310000330 Artificial Lift Oil Well Oil Production 

Unpermitted 2310002241 Oil Tank Flaring Oil Well Oil Production 

Unpermitted 2310003500 Other Flaring Total Gas Production 

Unpermitted 2310003501 Associated Gas Flaring 

Based on volume of 

gas flared in 2015 

MTDEQ Permitted 

Sources 10200603 Process Heaters Total Gas Processed 

MTDEQ Permitted 

Sources 10500106 Process Heaters Total Gas Processed 

MTDEQ Permitted 

Sources 20100202 Compressor Engines Total Gas Processed 

MTDEQ Permitted 

Sources 20200102 Compressor Engines Total Gas Processed 

MTDEQ Permitted 

Sources 20200201 Compressor Engines Total Gas Processed 

MTDEQ Permitted 

Sources 20200202 Compressor Engines Total Gas Processed 

MTDEQ Permitted 

Sources 20200253 Compressor Engines Total Gas Processed 

MTDEQ Permitted 

Sources 20200254 Compressor Engines Total Gas Processed 

MTDEQ Permitted 

Sources 30200699 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 30301012 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 30501050 Natural Gas Production, Other Not Classified Total Gas Processed 

MTDEQ Permitted 

Sources 30502504 Natural Gas Production, Other Not Classified Total Gas Processed 

MTDEQ Permitted 

Sources 31000101 Permitted Fugitives Total Gas Processed 

MTDEQ Permitted 

Sources 31000107 Natural Gas Production, Other Not Classified Total Gas Processed 

MTDEQ Permitted 

Sources 31000129 Oil Production, Gas/Liquid Separation Total Gas Processed 

MTDEQ Permitted 

Sources 31000202 Natural Gas Production, Gas Stripping Operations Total Gas Processed 

MTDEQ Permitted 

Sources 31000205 Natural Gas Production, Flares Total Gas Processed 

MTDEQ Permitted 

Sources 31000207 Permitted Fugitives Total Gas Processed 

MTDEQ Permitted 

Sources 31000220 Permitted Fugitives Total Gas Processed 

MTDEQ Permitted 

Sources 31000227 Dehydrator Total Gas Processed 

MTDEQ Permitted 

Sources 31000228 Dehydrator Total Gas Processed 

MTDEQ Permitted 

Sources 31000301 Dehydrator Total Gas Processed 

MTDEQ Permitted 

Sources 31000404 Process Heaters Total Gas Processed 

MTDEQ Permitted 

Sources 31000405 Process Heaters Total Gas Processed 

MTDEQ Permitted 

Sources 40301008 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40301009 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40301010 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40301012 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40301021 Permitted Tank Losses Total Gas Processed 
July 2013 

Final Report 5

Source SCC Description Projection Parameter

MTDEQ Permitted 

Sources 40301117 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40400116 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40400140 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40400151 Permitted Fugitives Total Gas Processed 

MTDEQ Permitted 

Sources 40400250 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40400302 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40400311 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40400312 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40600131 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40600132 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40600135 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40700809 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40700810 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40781602 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40781604 Permitted Tank Losses Total Gas Processed 

MTDEQ Permitted 

Sources 40781605 Permitted Tank Losses Total Gas Processed 

NDDOH Permitted 

Sources 20200201 Compressor Engines Total Gas Processed 

NDDOH Permitted 

Sources 20200202 Compressor Engines Total Gas Processed 

NDDOH Permitted 

Sources 31000205 Natural Gas Production, Flares Total Gas Processed 

NDDOH Permitted 

Sources 31000299 Natural Gas Production, Other Not Classified Total Gas Processed 

NDDOH Permitted 

Sources 31000301 Dehydrator Total Gas Processed 

NDDOH Permitted 

Sources 31000404 Process Heaters Total Gas Processed 

NDDOH Permitted 

Sources 40400302 Permitted Tank Losses Total Gas Processed 
July 2013 

Final Report 6

PROJECTION METHODOLOGIES FOR THE WILLISTON BASIN 

For the Williston Basin, the methodology for obtaining the 2015 value of each projection 

parameter (total well counts, spud counts, total gas production, oil well oil production, 

condensate production, total gas processed, and casinghead gas flared) is described below. In 

general, spud count projections were developed by obtaining the historical spud count and well 

count data for the geographic grouping using the IHS database, and reviewing the historic rate of 

spuds to new wells added in each geographic grouping. Well count and production projections 

for the basin were developed by developing extrapolated trend lines from historical data, or 

conservatively holding well counts and project constant into the future if historic data indicated 

decline. Condensate production projections were assumed to follow the trends for gas 

production. “Total gas processed” and “casinghead gas flared” are related parameters. The 

“total gas processed” projection factor applies to permitted midstream gas gathering and 

processing sources, and the “casinghead gas flared” projection factor applies only to the 

casinghead gas flaring source category. These are described below as they are not projected 

similarly to the other parameters. 

Because of the recent increase in activity in the Bakken formation, additional annual data on oil 

and gas production and well counts was gathered from the IHS database for calendar years 2010, 

2011 and 2012 in order to better track these recent trends. Therefore extrapolations and 

projections were made for the period 2012-2015, but it should be noted that projection factors 

represent the ratio of 2015 values of the parameters to 2009 values of the parameters. 

The IHS database is a tool to query oil and gas statistical well and production data, and uses as 

its reference data the databases maintained by various state OGCC’s (or equivalent). 

Associated Gas Flaring and Venting 

Special consideration is given to develop projections of the total amount of gas processed in the 

Williston Basin in 2015, relative to the total amount of gas processed in 2009. Information 

obtained from the state and federal agencies as well as industry participants indicates that some 

associated gas produced from the Bakken formation is flared due to a lack of gas gathering and 

processing infrastructure. This was discussed in the technical report for the Williston Basin 

baseline 2009 inventory (Bar-Ilan, et al., 2013). The amount of gas sold was used as a surrogate 

for the amount of gas processed, as this information was tracked for the basin by the North 

Dakota oil and gas commission. Historic data on the fraction of gas sold was plotted and 

extrapolated to 2015; the 2015 fraction of gas sold was then combined with the projected total 

gas production to derive the projected 2015 total gas processed. The ratio of 2015 to 2009 total 

gas processed was used to project midstream gas gathering emission sources. The inverse of this 

value represents the fraction flared, and therefore a similar approach was used to derive the 

projection factor for the casinghead gas flaring source category. Figure 1 below shows the 

projected fraction of gas sold in the Williston Basin. 
July 2013 

Final Report 7

Figure 1. Fraction of gas produced that is processed and sold in the Bakken Formation in North 

Dakota and Montana. 

This analysis was conducted for the Bakken geographical grouping, where the majority of new 

gas production is occurring in the Williston Basin in this time period. It was assumed that for the 

Cedar Creek Anticline and “Other Counties” geographical groupings, all gas produced was 

processed. In practical application, the “total gas processed” projection factor is dominated by 

the activities in the Bakken formation as shown in Figure 1. 

The decline in the fraction of gas processed in the Bakken from 2009 through 2011 is due to the 

increase in associated gas production without sufficient gas gathering and processing 

infrastructure. During the period from 2011 through October 2012, this trend reverses as 

additional infrastructure is established in this geographic area; this was the time period used to 

project a trendline forward to 2015. There are three primary observations from this analysis: 

(1) The “gas processed” projection factor is a combination of growth in the total amount of 

gas produced and the increase in gas gathering infrastructure; 

(2) This projection factor would be lower if the increase in gas gathering and processing 

infrastructure were not accounted for; and 

(3) Similarly the projection factor for casinghead gas flaring would be higher if the increase 

in gas gathering and processing infrastructure were not accounted for; 

It should be noted that this analysis used the available data on recent trends in the increase in gas 

gathering and processing infrastructure, however more detailed survey data from industry would 

improve these projections. 

 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

2008 2009 2010 2011 2012 2013 2014 2015

Percentage of Gas Sold

Year

Bakken Historical Percent of Gas

Sold

Bakken Forecasted Percent of

Gas Sold

North Dakota Statewide Monthly

Fraction of Gas Sold
July 2013 

Final Report 8

Bakken Formation Counties 

Total Well Counts

Total well counts in the Bakken Formation counties in the Williston Basin have been plotted for 

the years 1970 – 2012 below in Figure 2, including projections to 2015. 

Figure 2. Total well count historical data (from the IHS database) for Bakken Formation 

Counties in the Williston Basin and projections to 2015. 1

Total well count projections were developed for the period 2012 – 2015 by linear extrapolation 

of the well counts in the period 2010-2012. This period represented the recent historic increase 

in oil wells and oil production activity in the Bakken Formation and was considered a reasonable 

historic period from which to project the remaining data. 

Spud Counts 

Spud counts in the Bakken Formation Counties in the Williston Basin have been plotted for the 

years 1970 – 2010 below in Figure 3, including projections to 2015. 

 

1

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Well Count

Year

Conv. Well Count

projected
July 2013 

Final Report 9

Figure 3. Spud count historical data (from the IHS database) for Bakken Formation Counties in 

the Williston Basin and projections to 2015. 2

Historic spud counts in the Bakken Formation Counties, as obtained from the IHS database for 

the period 1970-2010 are erratic, making an extrapolation from historical data infeasible. Rather 

the change in the number of active wells each year in the period 2006-2010 was compared to the 

number of spuds that occurred in that same period. A ratio of the average number of annual 

spuds to the number of annual active wells added was developed. This ratio of 2.01 was then 

applied to the projected number of wells in the Bakken Formation Counties as described in 

Figure 2 above to estimate the projected number of spuds. 

Total Gas Production 

Total gas production in the Bakken Formation Counties in the Williston Basin has been plotted 

for the years 1970 – 2012 below in Figure 4, including projections to 2015. 

 

2

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

500

1,000

1,500

2,000

2,500

3,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Number of Spuds

Year

Spuds

projected (well count basis)
July 2013 

Final Report 10

Figure 4. Total gas production historical data (from the IHS database) for Bakken Formation 

Counties in the Williston Basin and projections to 2015. 3

Total gas production was linearly projected from 2012 - 2015 based on the rate of increase from 

the period 2010-2012 in order to account for the recent growth in Bakken Formation activity. 

The majority of gas production in the Bakken Formation geographical grouping is from 

casinghead gas production at Bakken oil wells. 

Oil Well Oil Production 

Oil well oil production in the Bakken Formation Counties in the Williston Basin has been plotted 

for the years 1970 – 2012 below in Figure 5, including projections to 2015. 

 

3

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

100,000,000

200,000,000

300,000,000

400,000,000

500,000,000

600,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Gas Production [mcf]

Year

Conv. Gas Prod (mcf)

projected
July 2013 

Final Report 11

Figure 5. Oil production historical data (from the IHS database) for Bakken Formation Counties 

in the Williston Basin and projections to 2015. 4

Oil production in the Bakken Formation was linearly projected forward to 2015 based on the 

growth period from 2010 to 2012. Because of the sensitivity of this projection to the selection of 

projection parameters (extrapolation type, data period from which to project) and the importance 

of this projection to the overall 2015 midterm emission inventory, reference data was obtained 

from other studies to confirm the plausibility of this projection. A study conducted by Bentek 

Energy for the North Dakota Pipeline Association (NDPA) and North Dakota Industrial 

Commission (NDIC) was used to compare the midterm projections of oil production in the 

Bakken Formation (Bentek, 2012). The Bentek study presented a range of oil production 

projections based on a variety of parameters used to define three scenarios: (1) a low scenario; 

(2) a base case scenario; and (3) a high growth scenario. The linearly projected oil production 

shown in Figure 5 falls within a reasonable range between the base case and low scenarios 

developed in the Bentek study for calendar year 2015, more closely approximating the base case 

scenario. Because the consistency with the Bentek study appeared reasonable, this linear 

projection was used for Bakken Formation oil production in 2015. 

Condensate Production 

Condensate production in the Bakken Formation Counties in the Williston Basin has been 

plotted for the years 1970 – 2010 below in Figure 6, including projections to 2015. 

 

4

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

50,000,000

100,000,000

150,000,000

200,000,000

250,000,000

300,000,000

350,000,000

400,000,000

450,000,000

500,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Oil Production [bbl]

Year

Oil Well Oil Production (bbl)

projected
July 2013 

Final Report 12

Figure 6. Condensate production historical data (from the IHS database) for the Bakken 

Formation Counties in the Williston Basin and projections to 2015. 5

Condensate production in the Bakken Formation Counties is low relative to primary oil 

production. Large increases in annual condensate production were observed in the period 2005-

2008 with subsequent decline in 2009 and a slight increase in 2010. This may reflect economic 

conditions which favored the development of primary oil wells over gas wells producing 

condensate. Given the erratic nature of recent condensate production activity in the Bakken 

Formation, the analysis conservatively assumed that 2010 condensate production levels would 

remain constant in the period 2010-2015. 

Cedar Creek Anticline Counties 

Total Well Counts 

Total well counts in the Cedar Creek Anticline Counties in the Williston Basin have been plotted 

for the years 1970 – 2010 below in Figure 7, including projections to 2015. 

 

5

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved).

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Condensate Production [bbl]

Year

Gas Well Condensate Production (bbl)

projected
July 2013 

Final Report 13

Figure 7. Total well count historical data (from the IHS database) for Cedar Creek Anticline 

Counties in the Williston Basin and projections to 2015. 6

Total active well counts in the Cedar Creek Anticline formation have been steadily increasing 

since approximately the mid-1990’s and this trend was continued. Total well counts were 

linearly extrapolated to 2015 based on historic data from the period 2006-2010. 

Spud Counts 

Spud counts in the Cedar Creek Anticline Counties in the Williston Basin have been plotted for 

the years 1970 – 2010 below in Figure 8, including projections to 2015. 

 

6

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

500

1,000

1,500

2,000

2,500

3,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Well Count

Year

Conv. Well Count

projected
July 2013 

Final Report 14

Figure 8. Spud count historical data (from the IHS database) for Cedar Creek Anticline 

Counties in the Williston Basin and projections to 2015. 7

Historic spud counts in the Cedar Creek Anticline Counties, as obtained from the IHS database 

for the period 1970-2010 are erratic, making an extrapolation from historical data infeasible. 

The change in the number of active wells each year in the period 2006-2010 was compared to the 

number of spuds that occurred in that same period, and determined the number of spuds required 

to match the increase or decrease in well counts for each year in that period. An average total 

spud count needed to maintain the observed number of active wells in the period 2006-2010 was 

developed, with a value of 99 spuds per year. The annual number of spuds estimated using this 

methodology was held constant for the period 2011-2015. 

Total Gas Production 

Total gas production in the Cedar Creek Anticline Counties in the Williston Basin have been 

plotted for the years 1970 – 2010 below in Figure 9, including projections to 2015. 

 

7

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

50

100

150

200

250

300

350

400

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Number of Spuds

Year

Spuds

projected (well count historic basis)
July 2013 

Final Report 15

Figure 9. Total gas production historical data (from the IHS database) for Cedar Creek Anticline 

Counties in the Williston Basin and projections to 2015. 8

Total gas production in the Cedar Creek Anticline Counties was generally increasing during the 

entire historical period tracked through 2008. Data from 2009 and 2010 show that gas 

production levels have declined during these past two years likely due to economic 

circumstances that favor oil production over gas production, and therefore this analysis 

conservatively assumed that gas production would remain at 2010 levels through the period 

2011-2015. 

Oil Well Oil Production 

Oil well oil production in the Cedar Creek Anticline Counties in the Williston Basin has been 

plotted for the years 1970 – 2010 below in Figure 10, including projections to 2015. 

 

8

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Gas Production [mcf]

Year

Conv. Gas Prod (mcf)

projected
July 2013 

Final Report 16

Figure 10. Oil production historical data (from the IHS database) for Cedar Creek Anticline 

Counties in the Williston Basin and projections to 2015. 9

Oil production has been generally increasing in the Cedar Creek Anticline Counties in the 

Williston Basin throughout the historical period until 2007. During the period 2007-2010 oil 

production in the Cedar Creek Anticline declined by approximately 35%. Given that no 

additional information was available on anticipated trends in this formation, it was 

conservatively assumed that oil production would remain at 2010 levels in the period 2011-2015. 

Condensate Production 

Condensate production in the Cedar Creek Anticline Counties in the Williston Basin has been 

plotted for the years 1970 – 2010 below in Figure 11, including projections to 2015. 

 

9

 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Oil Production [bbl]

Year

Oil Well Oil Production (bbl)

projected
July 2013 

Final Report 17

Figure 11. Condensate production historical data (from the IHS database) for Cedar Creek 

Anticline Counties in the Williston Basin and projections to 2015. 10

Condensate production in the Cedar Creek Anticline has been steadily increasing in the period 

2005-2010. Although gas production in the Cedar Creek Anticline experienced a decline after 

2008, this trend was not observed in the condensate production. Therefore condensate 

production was linearly extrapolated to 2015 based on the historic data in the period 2006-2010. 

Other Counties 

Total Well Counts 

Total well counts in the “Other Counties” grouping in the Williston Basin have been plotted for 

the years 1970 – 2010 below in Figure 12, including projections to 2015. 

 

10 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Condensate Production [bbl]

Year

Gas Well Condensate Production (bbl)

projected
July 2013 

Final Report 18

Figure 12. Total well count historical data (from the IHS database) for Other Counties in the 

Williston Basin and projections to 2015. 11

Total well counts in the “Other Counties” grouping have generally increased in the period 2005-

2010. Total well counts were linearly extrapolated to 2015 based on historical data in the period 

2006-2010. 

Spud Counts 

Spud counts in the “Other Counties” grouping in the Williston Basin have been plotted for the 

years 1970 – 2010 below in Figure 13, including projections to 2015. 

 

11 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

10

20

30

40

50

60

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Well Count

Year

Conv. Well Count

projected
July 2013 

Final Report 19

Figure 13. Spud count historical data (from the IHS database) for Other Counties in the 

Williston Basin and projections to 2015. 12

Historic spud counts in the “Other Counties” grouping, as obtained from the IHS database for the 

period 1970-2010 are erratic, making an extrapolation from historical data infeasible. The 

change in the number of active wells each year in the period 2006-2010 was compared to the 

number of spuds that occurred in that same period, and determined the number of spuds required 

to match the increase or decrease in well counts for each year in that period. An average total 

spud count needed to maintain the observed number of active wells in the period 2006-2010 was 

developed, with a value of 2.7 spuds per year. The annual number of spuds estimated using this 

methodology was held constant for the period 2012-2015. 

Total Gas Production 

Total gas production in the “Other Counties” grouping in the Williston Basin has been plotted 

for the years 1970 – 2010 below in Figure 14, including projections to 2015. 

 

12 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

20

40

60

80

100

120

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Number of Spuds

Year

Spuds

projected (well count historic basis)
July 2013 

Final Report 20

Figure 14. Total gas production historical data (from the IHS database) for Other Counties in 

the Williston Basin and projections to 2015. 13

Total gas production in the “Other Counties” grouping has been generally in decline from a peak 

in the early 1970’s, although gas production levels in this grouping are minimal compared to the 

other geographic groupings in the Williston Basin. This analysis conservatively assumed that 

total gas production would remain at 2010 levels through the period 2011-2015. 

Oil Well Oil Production 

Oil well oil production in the “Other Counties” grouping in the Williston Basin has been plotted 

for the years 1970 – 2010 below in Figure 15, including projections to 2015. 

 

13 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Gas Production [mcf]

Year

Conv. Gas Prod (mcf)

projected
July 2013 

Final Report 21

Figure 15. Oil production historical data (from the IHS database) for Other Counties in the 

Williston Basin and projections to 2015. 14

Oil production in the “Other Counties” grouping has been generally decreasing since a peak in 

the mid-1970’s. This analysis conservatively assumed that oil production would remain at 2010 

levels through the period 2011-2015. 

Condensate Production 

Condensate production in the “Other Counties” grouping in the Williston Basin has been plotted 

for the years 1970 – 2010 below in Figure 16, including projections to 2015. 

 

14 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

50,000

100,000

150,000

200,000

250,000

300,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Oil Production [bbl]

Year

Oil Well Oil Production (bbl)

projected
July 2013 

Final Report 22

Figure 16. Condensate production historical data (from the IHS database) for Other Counties in 

the Williston Basin and projections to 2015. 15

There has been negligible condensate production in the “Other Counties” grouping in the 

Williston Basin throughout the historical period from 1970-2010. It was assumed that there 

would be no condensate production in 2015 in this geographical grouping. 

 

15 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

0

100

200

300

400

500

600

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Condensate Production [bbl]

Year

Gas Well Condensate Production (bbl)

projected
July 2013 

Final Report 23

SCALING FACTOR DEVELOPMENT AND UNCONTROLLED 2015 EMISSIONS 

Scaling factors were generated for the Williston Basin geographic groupings described above, 

for each parameter considered here: total well counts, spud counts, total gas production, oil well 

oil production, and condensate production. Total gas processed and casinghead gas flared are 

not projected in a similar methodology to the other parameters, as described above. These are 

presented for each county below, and it is noted that all geographic groupings are comprised of 

more than one county in which the scaling factors for each parameter are identical for all 

counties in the grouping. The ratio of the value of each of these parameters in 2015 to their 

values in 2009 is the scaling factor for that parameter for purposes of this projection. This is 

shown in Equation 1 below: 

2009,,

2015,,

, ji

ji

ji W

W f 

Equation (1) 

where: 

fi,j is the scaling factor for geographic grouping j in the Williston Basin for parameter i

(total well count, spud count, total gas production, oil well oil production, and condensate 

production) 

Wi,j,2006 is the value of parameter i in geographic grouping j in 2009 

Wi,j,2012 is the projected value of parameter i in geographic grouping j in 2015 

The scaling factor based on the appropriate parameter is selected for each source category as 

described in Table 1. The scaling factors for the eight parameters used in this analysis for each 

county in the Williston Basin are presented in Table 2 below. 

Table 2. Scaling factors for five parameters used in the projection analysis for all counties in the 

Williston Basin.

County 

Total Well 

Count 

Spud 

Count

Total Gas

Production

Oil 

Production 

Condensate

Production 

Carter (MT) 1.25 0.67 0.90 0.77 1.00

Custer (MT) 1.25 0.67 0.90 0.77 1.00

Daniels (MT) 2.30 4.30 5.51 5.46 1.04

Dawson (MT) 1.14 1.53 0.86 0.85 2.46

Fallon (MT) 1.14 1.53 0.86 0.85 2.46

Garfield (MT) 1.25 0.67 0.90 0.77 1.00

McCone (MT) 2.30 4.30 5.51 5.46 1.04

Prairie (MT) 1.14 1.53 0.86 0.85 2.46

Richland (MT) 2.30 4.30 5.51 5.46 1.04

Roosevelt (MT) 2.30 4.30 5.51 5.46 1.04

Sheridan (MT) 2.30 4.30 5.51 5.46 1.04

Valley (MT) 2.30 4.30 5.51 5.46 1.04

Wibaux (MT) 1.14 1.53 0.86 0.85 2.46

Barnes (ND) 1.25 0.67 0.90 0.77 1.00

Billings (ND) 2.30 4.30 5.51 5.46 1.04

Bottineau (ND) 2.30 4.30 5.51 5.46 1.04

Bowman (ND) 1.14 1.53 0.86 0.85 2.46

Burke (ND) 2.30 4.30 5.51 5.46 1.04
July 2013 

Final Report 24

County 

Total Well 

Count 

Spud 

Count

Total Gas

Production

Oil 

Production 

Condensate

Production 

Burleigh (ND) 1.25 0.67 0.90 0.77 1.00

Divide (ND) 2.30 4.30 5.51 5.46 1.04

Dunn (ND) 2.30 4.30 5.51 5.46 1.04

Golden Valley (ND) 2.30 4.30 5.51 5.46 1.04

McHenry (ND) 2.30 4.30 5.51 5.46 1.04

McIntosh (ND) 1.25 0.67 0.90 0.77 1.00

McKenzie (ND) 2.30 4.30 5.51 5.46 1.04

McLean (ND) 2.30 4.30 5.51 5.46 1.04

Mercer (ND) 2.30 4.30 5.51 5.46 1.04

Morton (ND) 2.30 4.30 5.51 5.46 1.04

Mountrail (ND) 2.30 4.30 5.51 5.46 1.04

Renville (ND) 2.30 4.30 5.51 5.46 1.04

Slope (ND) 1.14 1.53 0.86 0.85 2.46

Stark (ND) 2.30 4.30 5.51 5.46 1.04

Stutsman (ND) 1.25 0.67 0.90 0.77 1.00

Ward (ND) 2.30 4.30 5.51 5.46 1.04

Williams (ND) 2.30 4.30 5.51 5.46 1.04

Butte (SD) 1.25 0.67 0.90 0.77 1.00

Harding (SD) 1.14 1.53 0.86 0.85 2.46
July 2013 

Final Report 25

CONTROLLED 2015 EMISSIONS 

This methodology considered any “on-the-books” federal or state regulations that would affect 

the uncontrolled 2015 emissions projections described above. Table 3 below lists the “on-thebooks” federal and state regulations that affect emissions source categories in the oil and gas 

industry, and the action taken to adjust the 2015 emissions inventory appropriately. A more 

detailed description follows of the methodology used to address each of these regulations as they 

affected the uncontrolled 2015 Williston Basin emissions projections. The uncontrolled 2015 

emissions were adjusted based on the proposed actions or control factors developed for each 

regulation described in Table 3 to account for how these regulations may affect any oil and gas 

source category considered in this inventory. 

Table 3. Summary of federal and state “on-the-books” regulations affecting the oil and gas 

source categories considered in this inventory. 

Source 

Category Regulation 

Enforcing 

Agency 

Effective 

Date 

Implementation in the 2012

Powder River Basin 

Emissions Projections 

Federal

Drill Rigs, 

Workover Rigs 

Nonroad engine Tier 

standards (1-4) 

(EPA, 2005) US EPA 

Phase in 

from 

1996 - 2014 

EPA NONROAD model used to create 

county-level control factors for the drill rig 

SCC to account for fleet turnover. 

Drill Rigs, 

Workover Rigs

Nonroad diesel fuel sulfur 

standards 

(EPA, 2006) US EPA

Phase in 

beginning in 

2010

Assume 15 ppm sulfur in nonroad diesel 

fuel throughout Powder River Basin. 

Control factors derived from EPA 

NONROAD model (see above).

All New SparkIgnited Stationary 

Engines

New Source 

Performance Stds. 

(NSPS) 

(EPA, 2008; EPA, 2012) US EPA

Phase in 

from 2008 - 

2011

Control factors developed considering the 

specific composition of engines in the 

inventory (described in more detail below).

Insufficient information to determine the 

mix of wet/dry seals on compressors 

therefore no additional control factor 

applied due to Subpart OOOO 

requirements.

Pneumatic 

Controllers

New Source 

Performance Stds. 

Subpart OOOO (NSPS) 

(EPA, 2012) US EPA

Beginning 

Sep. 2011

Assume all new pneumatic controllers 

after September 2011 are low-bleed 

devices.

Condensate and 

Crude Oil Tanks 

New Source 

Performance Stds. 

Subpart OOOO (NSPS) 

(EPA, 2012) US EPA Oct. 15, 2013

Control factors developed for tanks by 

region (described in more detail below) 

Gas Well 

Completions

New Source 

Performance Stds. 

Subpart OOOO (NSPS) 

(EPA, 2012) US EPA

Oct. 2012 

(low 

pressure) / 

Jan. 2015 (all 

other)

Insufficient information to estimate the 

impact of this regulation requiring reduced 

emission completions

Dehydrators 

New Source 

Performance Stds. 

Subpart HH (NSPS) 

(EPA, 2012) US EPA 

Phase in 

from Oct. 

2012-Oct. 

2015 

All dehydration assumed controlled in the 

baseline 2009 inventory based on limited 

survey data, therefore no additional effect 

of this regulation. 

Gas Processing 

Plants 

New Source 

Performance Stds. 

Subpart OOOO (NSPS) 

(EPA, 2012) US EPA Oct. 2013 

Not enough information on detailed 

emissions at gas processing facilities; 

conservatively assumed that there would 

be no effect of this regulation on the 2015 

inventory. 

Minor Source 

Reporting 

Requirements on 

Indian Tribal Land

New Source 

Performance Stds. 

Subpart OOOO (NSPS) 

(EPA, 2012) US EPA

Phase-In 

Beginning 

Aug. 2011

No information was available from the 

minor source reporting regulation.
July 2013 

Final Report 26

Source 

Category Regulation 

Enforcing 

Agency 

Effective 

Date 

Implementation in the 2012

Powder River Basin 

Emissions Projections 

State – Montana

Well Completions

MT ARM 36.22.1221 

Completion venting 

controls. MTDEQ 1984 

Not enough information was available in 

producer data; conservatively assume that 

there would be no effect of this regulation 

on the 2015 inventory. 

Condensate and 

Crude Oil Tanks

MT ARM 17.8.1603(1)(b)

VOC vapors from oil or 

condensate storage 

tanks with a PTE > 15 tpy

must be controlled MTDEQ Jan 2006

Control factors developed for tanks by 

region (described in more detail below)

All VOC sources

MT ARM 

17.8.1711(1)(a) 

VOC vapors from each 

piece of O&G well facility 

equipment with PTE >15 

tpy, must be controlled MTDEQ Apr 2006

Not enough information to make a 2015 

specific analysis. Assumed that rates of 

control in 2015 are similar to rates of 

control in 2009 for VOC sources not 

controlled per other regulations.

MT ARM 17.8.1603(1)(a)

VOC vapors must be 

captured and routed to a 

gas pipeline if within 1⁄2 

mile to control device. MTDEQ Jan 2006 

MT ARM 17.8.752

case by case BACT 

determination MTDEQ Dec 2002

MT ARM 17.8.1711(1)(a)

VOC vapors from each 

piece of O&G well facility 

equipment, with a PTE > 

15 tpy, must be 

controlled MTDEQ Apr 2006

Truck loading 

MT ARM 17.8.1711(1)(b)

Submerged filling on all 

hydrocarbon liquid 

loading or unloading MTDEQ Apr 2006 

Assumed submerged filling for all tank 

loading. 

State – North Dakota

Condensate and 

Crude Oil Tanks

NDAC 33-15-07 and 

Bakken Pool O&G 

Control Permitting & 

Compliance Guidance 

Flaring controls for tanks NDDOH 2011

Control factors developed for tanks by 

region (described in more detail below)

Tank loading 

NDAC 33-15-07

Submerged filling 

requirements for tanks > 

1000gal NDDOH 

Initial 2009 

Baseline and 

All Projection 

Years 

Assumed submerged filling for all tank 

loading. 

Nonroad Diesel Engine Standards and Fuel Sulfur Standards 

The EPA NONROAD2005 model was run with fuel inputs based on a 2002 study entitled 

“WRAP Mobile Sources Emission Inventory Update” (Pollack, et al., 2006). The model outputs 

were used to develop county-level emissions per unit population for “other oil field equipment” 

(SCC 2270010010) for the calendar year 2006, and then separately for the calendar year 2012. 

These emissions per unit population reflect the predicted fleet mix of engines – for various tier 

standards from baseline uncontrolled engines through Tier IV engines – and are used as a 

representation of fleet turnover for drilling rigs and workover rigs. The ratios of the per unit 

emissions in 2012 to those in 2006 for each county of interest were taken to be the control factors 

accounting for federal non-road tier standards. 
July 2013 

Final Report 27

In addition, the NONROAD model runs with the fuel inputs used for developing the tier 

standards control factors were also used to develop the control factors for SOx emissions factors 

for drilling rigs and workover rigs. The model is capable of tracking the expected reduction in 

fuel sulfur content from the baseline 2006 year – assumed to be the same as the WRAP 2002 

inventory – and the 2012 future year. A similar approach was used as for the federal tier 

standards to develop control factors. The ratio of per unit SOx emissions in 2012 to those in 

2006 were taken to be a control factor to apply to uncontrolled 2012 SOx emissions for drilling 

rigs and workover rigs to account for federal non-road diesel fuel standards. 

New Source Performance Standards for Stationary Spark-Ignited Engines 

An analysis was undertaken to implement the US EPA NSPS. In previous basin analyses of 

NSPS application (Bar-Ilan, et al., 2009a; Bar-Ilan, et al., 2009b; Bar-Ilan, et al., 2009c; BarIlan, et al., 2008), it was assumed that a flat or declining gas production projection would 

indicate no need for additional horsepower of compression. This was coupled with the 

assumption that there would be negligible turnover of engines during the period of the 

projections to conclude that NSPS did not need to be applied if gas production was declining in 

any geographic grouping. Where gas production is projected to increase – most notably in the 

Bakken Formation Counties, NSPS requirements were applied, similar to the assumptions made 

in developing projected emissions for other basins. 

NSPS Regulations 

The EPA has promulgated a new regulation covering new stationary, spark-ignited engines of 

various horsepower classes. The regulation is assumed to apply to central compressor engines, 

wellhead and lateral compressor engines, and artificial lift engines as well as any other 

miscellaneous engines that are stationary, spark-ignited natural gas engines. The regulation 

requires new engines of various horsepower classes to meet increasingly stringent NOx and 

VOC emission standards over the phase-in period of the regulation. 

For engines less than 25 horsepower, Table 4 shows the requirements of the NSPS regulation. 

Table 4. Federal NSPS emissions standards for engines less than 25 horsepower.

HP Rangea

Emissions Standards Requirement in (g/hp-hr)b

HC + NOx NMHC + NOxc CO

≤ 25 Hp 

Class I 16.1 (12.0) 14.8 (11.0) 610 (455)

Class I -A 50-37 - -

Class I -B 40 (30) 37 (27.6)

Class II 12.1 (9.0) 11.3 (8.4) a

 Class I-A: Engines with displacement less than 66 cubic centimeters (cc); Class 1-B: Engines with displacement 

greater than or equal to 66cc and less than 100cc; Class I: Engines with displacement greater than or equal to 

100 cc and less than 225 cc b

 Modified and reconstructed engines manufactured prior to July 1, 2008, must meet the standards applicable to 

engines manufactured after July 1, 2008 c

 NMHC+NOX standards are applicable only to natural gas fueled engines at the option of the manufacturer, in lieu 

of HC+NOX standards 

For engines in the horsepower range 25 – 100 horsepower, Table 5 shows the requirements of 

the NSPS regulation.
July 2013 

Final Report 28

Table 5. Federal NSPS emissions standards for engines greater than 25 horsepower but less 

than 100 horsepower.

HP Range Manufacture Date

Emissions Standards Requirement

(g/hp-hr) 

HC + NOx CO

25<HP<100 1-Jul-08 3.8 6.5

1-Jul-08

(severe duty) 3.8 200

For engines in the horsepower range 100 – 1,350 horsepower, Table 6 shows the requirements of 

the NSPS regulation. 

Table 6. Federal NSPS emissions standards for engines greater than 25 horsepower but less 

than 100 horsepower.

Engine Type and Fuel HP Range 

Manufacture 

Date 

Emissions Standards 

Requirement (g/hp-hr) 

NOx CO VOC

Non-Emergency SI Natural Gas and 

Non-Emergency SI Lean Burn LPG 100≤HP<500 1-Jul-08 2 4 1

1-Jan-11 1 2 1

Non-Emergency SI Lean Burn Natural 

Gas and LPG 500≥HP<1350 1-Jan-08 2 4 1

1-Jul-10 1 2 1

Non-Emergency SI Natural Gas and 

Non-Emergency SI Lean Burn LPG 

(except lean burn 500≥HP<1350) 

HP≥500 1-Jul-07 2 4 1

A detailed analysis was carried forward to analyze the effects of this rule on the permitted and 

survey-based wellhead engine fleet in the Williston Basin. Engines were sorted into bins 

representing horsepower ranges based on the available compressor engine data gathered as part 

of the baseline 2009 inventory development. Because the NSPS requirements change over the 

phase-in period of the regulation, the growth of compression horsepower was tracked for each 

year in the period 2009-2015. For each year, the additional compression horsepower was sorted 

into the horsepower range bins, and NSPS was applied to these engines. 

New Source Performance Standards for Pneumatic Devices 

Following the requirements of the NSPS Subpart OOOO, it was assumed that all new pneumatic 

devices installed after September 2011 would be low-bleed. This analysis assumed new 

pneumatic device installation tracked the increase in well counts in each geographic grouping. 

New Source Performance Standards and Montana Regulations for Well Completions 

Both the NSPS Subpart OOOO and Montana ARM 36.22.1221 require controls on well 

completions in the form of either reduced emission completions (NSPS Subpart OOOO) or 

combustion controls on vented gas during completions. However insufficient information was 

available from the baseline 2009 survey data to accurately characterize the uncontrolled fraction 

of well completions or the uncontrolled VOC emissions from these completions, therefore it was 

not possible to implement these regulations in the 2015 midterm projections for the Williston 

Basin. 
July 2013 

Final Report 29

New Source Performance Standards and Montana and North Dakota Regulations for 

Crude Oil and Condensate Tanks 

Crude oil tanks in the Bakken Formation represent one of the largest VOC sources in the 2015 

midterm projected inventory for the Williston Basin, and thus special consideration was given to 

this source category based on the regulatory requirements of the NSPS, and Montana and North 

Dakota state regulations. The regulations and control assumptions for oil tanks were considered 

separately for four geographic areas: (1) North Dakota non-tribal land; (2) Fort Berthold Indian 

Reservation (tribal land in North Dakota); (3) Montana non-tribal land; and (4) Montana tribal 

land (primarily the Fort Peck Indian Reservation). These are summarized in Table 7 below. 

Table 7. Crude oil tank controls assumptions in the 2015 Williston Basin midterm emissions.

Geographic Area Controls Assumptions 

North Dakota Non-Tribal Land 

Per NDDOH regulations, any well site with >20tpy 

uncontrolled emissions requires control at 98% destruction 

efficiency (DRE); <20tpy requires 90% DRE. 

Analysis conducted to determine fraction of sites with 

greater or less than 20tpy uncontrolled emissions: 84% 

would require 98% DRE, 16% would require 90% DRE, 

assumed average of 97% DRE at all tanks. 

North Dakota Tribal Land 

Based on limited survey data and information from industry 

participants, practices on the Fort Berthold Indian 

Reservation were assumed similar to those on non-tribal 

land. Federal Implementation Plan (FIP) and interim final 

rule (IFR) for the Fort Berthold reservation confirm these 

assumptions are reasonable. 

Montana Non-Tribal Land 

For production added through August 2013: Per MTDEQ 

regulation, any well site with >15tpy uncontrolled emissions 

requires control at 90% DRE. 

Analysis conducted to determine fraction of sites with 

greater or less than 15tpy uncontrolled emissions; derived 

average control of 94% of production at 90% DRE. 

For production added after August 2013: Subpart OOOO 

was assumed to apply, with a 99% rule penetration (based 

on fraction of sites meeting thresholds) and a 95% DRE 

Montana Tribal Land 

For production added through August 2013: Assumed 

flaring rate based on 2009 baseline survey data at a 90% 

DRE. 

For production added after August 2013: Subpart OOOO 

was assumed to apply, with a 99% rule penetration (based 

on fraction of sites meeting thresholds) and a 95% DRE 

It should be noted that these assumptions utilized survey data provided by operators as part of the 

2009 baseline inventory. Although this survey data was limited, this was the only data available 

for some geographic areas. 
July 2013 

Final Report 30

SUMMARY RESULTS 

The scaling factors were applied to the baseline 2009 inventory, and “on-the-books” regulations 

were applied to the uncontrolled 2015 emissions projections to generate the final 2015 emissions 

projections and results are presented below. It should be noted that all figures showing countylevel emissions only include those counties representing 1% or greater of the total emissions in 

the basin. 

Figure 17 and Table 8 show that NOx emissions are primarily concentrated in Mountrail, 

Williams, McKenzie and Dunn Counties in North Dakota and Richland County in Montana, 

representing approximately 69% of total basin-wide NOx emissions. Additional significant NOx 

emissions occur in Fallon County Montana and Billings County North Dakota. Figure 18 and 

Table 8 show that VOC emissions are primarily concentrated in Mountrail, McKenzie, Bowman, 

Dunn and Williams Counties in North Dakota and Richland County in Montana, representing 

approximately 72% of total basin-wide VOC emissions Additional VOC emissions are 

observed in Billings County North Dakota and Fallon County Montana. Given the large volume 

of produced oil and associated gas in the Williston Basin, VOC emissions are driven by the 

presence of oil production and associated gas production in these counties. 

Consistent with the 2009 baseline emissions analysis, compressor engines, drilling rigs and 

artificial lift engines remain the dominant NOx source categories in the Williston Basin, 

representing approximately 75% of total basin-wide NOx emissions as shown in Table 9. It is 

noted that drilling emissions decline over time as expected from turnover of equipment to newer 

engines meeting more stringent emissions standards. Therefore drilling represents a smaller 

fraction of basin-wide NOx in 2015 than in 2009. 

VOC emissions in the 2009 baseline inventory are dominated by oil tanks; but in the 2015 

midterm projected inventory VOC emissions are comprised of a number of source categories 

including oil tanks, casinghead gas venting and flaring, and pneumatic devices and pneumatic 

pumps as shown in Table 10, representing approximately 75% of basin-wide VOC emissions. 

Oil tank flashing VOC emissions are still projected to be the largest source category, but 

represent a significantly smaller fraction of the total basin-wide VOC emissions in 2015 than in 

2009 as a result of increasing control of these emissions through the use of flares. Venting of 

casinghead gas is observed to increase significantly from 2009 to 2015, driven by the large 

growth in associated gas production despite increasing gas gathering and processing 

infrastructure. Venting from pneumatic devices and pneumatic pumps is observed to increase as 

a percentage of total basin-wide VOC emissions in 2015 relative to 2009, driven mainly by the 

large increase in the number of new wells projected to be added to the basin. It should be noted 

that the VOC emissions are very sensitive to the selection of a “fraction of gas processed” factor, 

which is based on a limited set of available data on gas gathering infrastructure development. 

Additional information on the development of gas gathering infrastructure would help to 

improve this estimate. 

 
July 2013 

Final Report 31

Figure 17. 2015 NOx emissions by source category and by county in the Williston Basin. 

Figure 18. 2015 VOC emissions by source category and by county in the Williston Basin. 

0

2000

4000

6000

8000

10000

12000

NOx Emissions (tons/year)

County

Other Categories

Casinghead Gas Venting and Flaring

Oil tank flaring

Oil Well Truck Loading

Oil Tank

Condensate tank

Artificial Lift

Miscellaneous engines

Unpermitted Fugitives

Heaters

Venting - recompletions

Pneumatic pumps

Pneumatic devices

Drill rigs

Compressor engines

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

100000

VOC Emissions (tons/year)

County

Other Categories

Casinghead Gas Venting and

Flaring

Condensate tank flaring

Oil Well Truck Loading

Oil Tank

Condensate tank

Artificial Lift

Miscellaneous engines

Unpermitted Fugitives

Heaters
July 2013 

Final Report 32

Figure 19. 2015 NOx emissions contributions by source category in the Williston Basin. 

Figure 20. 2015 VOC emissions contributions by source category in the Williston Basin. 

Compressor engines

32%

Drill rigs

27%

Heaters

3%

Miscellaneous engines

2%

Artificial Lift

16%

Oil tank flaring

7%

Casinghead Gas 

Venting and Flaring

10%

Other Categories

3%

Compressor engines

1% Pneumatic devices

10%

Pneumatic pumps

12%

Venting -

recompletions

1%

Unpermitted Fugitives

3%

Condensate tank 

8%

Oil Tank

23%

Oil Well Truck Loading

7%

Casinghead Gas 

Venting and Flaring

30%

Other Categories

4%
July 2013 

Final Report 33

Table 8. 2015 emissions of all criteria pollutants by county for the Williston Basin. 

County 

NOx

[tons/yr] 

VOC

[tons/yr] 

CO

[tons/yr] 

SOx

[tons/yr] 

PM

[tons/yr] 

Carter (MT) 79 178 129 0 1 

Custer (MT) 120 28 104 0 3 

Daniels (MT) 2 112 4 0 0 

Dawson (MT) 99 1,383 108 0 8 

Fallon (MT) 1,798 24,357 2,943 45 97 

Garfield (MT) 5 112 6 0 0 

McCone (MT) 121 187 65 0 2 

Prairie (MT) 4 238 4 0 0 

Richland (MT) 4,488 75,047 10,633 15 208 

Roosevelt (MT) 1,174 10,743 1,524 112 88 

Sheridan (MT) 441 9,004 1,009 0 28 

Valley (MT) 1,573 4,813 1,494 30 73 

Wibaux (MT) 37 2,218 36 0 2 

Barnes (ND) 316 6 24 10 20 

Billings (ND) 1,808 18,505 3,388 1,216 51 

Bottineau (ND) 1,189 15,018 1,908 1 105 

Bowman (ND) 1,111 44,884 1,499 1 43 

Burke (ND) 889 10,601 1,433 191 65 

Burleigh (ND) 63 17 60 0 0 

Divide (ND) 853 7,147 1,456 0 74 

Dunn (ND) 4,615 33,667 8,113 11 385 

Golden Valley (ND) 187 2,560 411 0 11 

McHenry (ND) 365 382 38 10 20 

McIntosh (ND) 134 17 134 7 10 

McKenzie (ND) 5,919 49,616 9,035 1,552 274 

McLean (ND) 196 635 238 0 22 

Mercer (ND) 56 32 55 0 7 

Morton (ND) 386 77 444 21 21 

Mountrail (ND) 10,611 95,234 22,775 1 701 

Renville (ND) 337 7,221 620 0 23 

Slope (ND) 36 2,721 49 0 3 

Stark (ND) 597 4,478 880 0 10 

Stutsman (ND) 28 10 42 0 0 

Ward (ND) 128 507 149 0 15 

Williams (ND) 6,161 27,813 5,476 3,822 210 

Butte (SD) 12 2 11 0 1 

Harding (SD) 176 4,874 186 0 15 

TOTAL 46,114 454,443 76,480 7,046 2,596 

Daniels, (MT) (Tribal) 2 94 3 0 0 

Roosevelt, (MT) (Tribal) 342 5,259 606 89 41 

Sheridan, (MT) (Tribal) 2 143 6 0 0 

Valley, MT (Tribal) 54 2,075 95 0 4 

Dunn, ND (Tribal) 667 2,829 951 0 70 

McKenzie, ND (Tribal) 112 876 168 0 11 

McLean, ND (Tribal) 196 635 238 0 22 

Mountrail, ND (Tribal) 2,345 17,868 4,541 0 187 

TOTAL (Tribal) 3,720 29,779 6,609 90 335

Daniels, (MT) 

(Non-Tribal) 0 17 0 0 0 

Roosevelt, (MT) 

(Non-Tribal) 832 5,484 919 23 47 

Sheridan, (MT) 

(Non-Tribal) 438 8,861 1,003 0 28 

Valley, MT 

(Non-Tribal) 1,519 2,738 1,399 30 69 

Dunn, ND 

(Non-Tribal) 3,948 30,838 7,163 11 315 

McKenzie, ND 5,807 48,740 8,866 1,552 264 
July 2013 

Final Report 34

County 

NOx

[tons/yr] 

VOC

[tons/yr] 

CO

[tons/yr] 

SOx

[tons/yr] 

PM

[tons/yr] 

(Non-Tribal) 

McLean, ND 

(Non-Tribal) 0 0 0 0 0 

Mountrail, ND 

(Non-Tribal) 8,266 77,367 18,233 1 514 
July 2013 

Final Report 35

Table 9. 2015 NOx emissions by county and by source category for the Williston Basin.

County 

Compressor 

Engines 

Drill 

Rigs Heaters 

Miscellaneous 

Engines 

Artificial Lift 

Engines 

Oil Tank 

Flaring 

Casinghead 

Gas Flaring 

Other 

Categories Totals 

Carter (MT) 75 0 2 2 1 0 0 0 79 

Custer (MT) 119 0 0 0 0 0 0 0 120 

Daniels (MT) 0 0 1 0 0 0 0 0 2 

Dawson (MT) 55 20 6 5 5 2 0 6 99 

Fallon (MT) 1,046 204 129 109 82 38 0 190 1,798 

Garfield (MT) 2 0 1 1 0 0 0 0 5 

McCone (MT) 117 0 1 1 1 0 0 0 121 

Prairie (MT) 0 0 1 1 1 0 0 0 4 

Richland (MT) 887 297 174 147 1,307 612 846 218 4,488 

Roosevelt (MT) 750 130 33 28 107 50 69 6 1,174 

Sheridan (MT) 12 93 39 33 122 57 79 6 441 

Valley (MT) 1,298 186 33 28 9 4 6 9 1,573 

Wibaux (MT) 1 0 11 9 9 4 0 1 37 

Barnes (ND) 316 0 0 0 0 0 0 0 316 

Billings (ND) 752 37 85 72 335 157 217 154 1,808 

Bottineau (ND) 1 649 97 82 164 77 106 12 1,189 

Bowman (ND) 672 99 51 43 160 10 0 77 1,111 

Burke (ND) 114 353 69 59 116 55 75 48 889 

Burleigh (ND) 63 0 0 0 0 0 0 0 63 

Divide (ND) 29 501 26 22 128 60 83 4 853 

Dunn (ND) 331 2,560 71 60 747 350 484 12 4,615 

Golden Valley (ND) 9 56 12 10 47 22 31 2 187 

McHenry (ND) 353 0 3 3 3 1 2 0 365 

McIntosh (ND) 134 0 0 0 0 0 0 0 134 

McKenzie (ND) 2,350 1,429 161 136 768 360 498 218 5,919 

McLean (ND) 1 167 3 3 10 5 7 0 196 

Mercer (ND) 0 56 0 0 0 0 0 0 56 

Morton (ND) 386 0 0 0 0 0 0 0 386 

Mountrail (ND) 549 4,434 94 80 2,553 1,196 1,653 52 10,611 

Renville (ND) 1 93 54 46 65 30 42 7 337 

Slope (ND) 5 20 2 2 5 0 0 3 36 

Stark (ND) 333 19 13 11 104 49 67 2 597 

Stutsman (ND) 28 0 0 0 0 0 0 0 28 

Ward (ND) 0 111 3 3 5 2 3 0 128 

Williams (ND) 4,024 835 86 73 427 200 277 238 6,161 

Butte (SD) 0 12 0 0 0 0 0 0 12 

Harding (SD) 28 86 19 16 22 1 0 3 176 

TOTAL 14,839 12,444 1,281 1,086 7,305 3,345 4,545 1,269 46,114 

Daniels, (MT) (Tribal) 0 0 0 0 0 0 0 0 2 

Roosevelt, (MT) (Tribal) 221 37 12 11 28 13 18 2 342 

Sheridan, (MT) (Tribal) 0 0 0 0 1 0 1 0 2 

Valley, MT (Tribal) 0 19 8 7 9 4 6 1 54 
July 2013 

Final Report 36

County 

Compressor 

Engines 

Drill 

Rigs Heaters 

Miscellaneous 

Engines 

Artificial Lift 

Engines 

Oil Tank 

Flaring 

Casinghead 

Gas Flaring 

Other 

Categories Totals 

Dunn, ND (Tribal) 7 520 4 4 62 29 40 1 667 

McKenzie, ND (Tribal) 5 74 4 3 12 6 8 1 112 

McLean, ND (Tribal) 1 167 3 3 10 5 7 0 196 

Mountrail, ND (Tribal) 35 1,280 21 18 467 219 302 3 2,345 

TOTAL (Tribal) 270 2,097 53 45 590 276 382 8 3,720 

Daniels, (MT) 

(Non-Tribal) 0 0 0 0 0 0 0 0 0 

Roosevelt, (MT) 

(Non-Tribal) 529 93 21 18 79 37 51 5 832 

Sheridan, (MT) 

(Non-Tribal) 12 93 39 33 121 57 78 6 438 

Valley, MT 

(Non-Tribal) 1,298 167 25 21 0 0 0 8 1,519 

Dunn, ND 

(Non-Tribal) 324 2,041 67 57 685 321 443 11 3,948 

McKenzie, ND 

(Non-Tribal) 2,344 1,354 157 133 757 354 490 218 5,807 

McLean, ND 

(Non-Tribal) 0 0 0 0 0 0 0 0 0 

Mountrail, ND 

(Non-Tribal) 513 3,154 74 62 2,086 977 1,351 49 8,266 
July 2013 

Final Report 37

Table 10. 2015 VOC emissions by county and by source category for the Williston Basin.

County 

Pneumatic 

Devices 

Pneumatic 

Pumps 

Recompletion 

Venting Fugitives 

Condensate 

Tanks Oil Tanks 

Oil Well 

Truck 

Loading 

Casinghead

Gas 

Venting 

Other 

Categories Totals 

Carter (MT) 62 74 3 22 0 13 3 0 2 178 

Custer (MT) 10 12 0 4 0 0 0 0 1 28 

Daniels (MT) 19 23 3 7 0 50 2 8 0 112 

Dawson (MT) 203 241 20 70 3 650 24 0 171 1,383 

Fallon (MT) 4,462 5,290 448 1,545 16 10,222 375 0 1,999 24,357 

Garfield (MT) 41 49 2 14 0 4 1 0 0 112 

McCone (MT) 31 38 4 11 0 10 2 10 80 187 

Prairie (MT) 41 49 4 14 0 124 5 0 1 238 

Richland (MT) 5,830 7,129 843 2,081 12 24,126 5,964 25,063 3,999 75,047 

Roosevelt (MT) 1,118 1,368 162 399 0 4,814 489 2,054 340 10,743 

Sheridan (MT) 1,316 1,611 190 470 4 2,334 555 2,333 190 9,004 

Valley (MT) 1,105 1,353 160 394 0 1,125 43 181 451 4,813 

Wibaux (MT) 384 456 39 133 0 1,155 42 0 9 2,218 

Barnes (ND) 0 0 0 0 0 0 0 0 6 6 

Billings (ND) 2,844 3,481 411 1,015 73 2,205 1,528 6,421 528 18,505 

Bottineau (ND) 3,247 3,975 469 1,159 324 1,080 749 3,146 869 15,018 

Bowman (ND) 1,759 2,089 177 609 18,740 19,885 730 0 894 44,884 

Burke (ND) 2,328 2,850 337 831 167 767 531 2,233 557 10,601 

Burleigh (ND) 0 0 0 0 0 0 0 0 17 17 

Divide (ND) 888 1,087 128 317 482 840 582 2,446 377 7,147 

Dunn (ND) 2,391 2,926 346 853 1,432 4,921 3,410 14,330 3,060 33,667 

Golden Valley (ND) 391 479 57 140 0 310 215 903 65 2,560 

McHenry (ND) 106 129 15 38 0 19 13 54 9 382 

McIntosh (ND) 0 0 0 0 0 0 0 0 17 17 

McKenzie (ND) 5,390 6,597 779 1,924 7,348 5,060 3,506 14,734 4,280 49,616 

McLean (ND) 106 129 15 38 0 67 46 194 40 635 

Mercer (ND) 6 8 1 2 0 1 1 4 9 32 

Morton (ND) 0 0 0 0 0 0 0 0 77 77 

Mountrail (ND) 3,167 3,876 458 1,130 1,720 16,809 11,648 48,949 7,477 95,234 

Renville (ND) 1,807 2,212 261 645 222 426 295 1,241 112 7,221 

Slope (ND) 67 79 7 23 1,856 632 23 0 34 2,721 

Stark (ND) 441 540 64 157 0 684 474 1,991 128 4,478 

Stutsman (ND) 0 0 0 0 0 0 0 0 10 10 

Ward (ND) 99 122 14 35 0 34 24 100 77 507 

Williams (ND) 2,900 3,549 419 1,035 4,566 2,814 1,950 8,195 2,385 27,813 

Butte (SD) 0 0 0 0 0 0 0 0 2 2 

Harding (SD) 670 796 67 232 152 2,709 99 0 150 4,874 

TOTAL 43,230 52,616 5,903 15,348 37,116 103,890 33,329 134,590 28,422 454,443 

Daniels, (MT) (Tribal) 12 15 2 4 0 50 2 8 0 94 

Roosevelt, (MT) 

(Tribal) 416 509 60 148 0 3,358 129 541 97 5,259 
July 2013 

Final Report 38

County 

Pneumatic 

Devices 

Pneumatic 

Pumps 

Recompletion 

Venting Fugitives 

Condensate 

Tanks Oil Tanks 

Oil Well 

Truck 

Loading 

Casinghead

Gas 

Venting 

Other 

Categories Totals 

Sheridan, (MT) 

(Tribal) 6 8 1 2 0 105 4 17 1 143 

Valley, MT (Tribal) 261 319 38 93 0 1,125 43 181 15 2,075 

Dunn, ND (Tribal) 149 182 22 53 0 411 285 1,197 531 2,829 

McKenzie, ND (Tribal) 130 160 19 47 0 78 54 226 163 876 

McLean, ND (Tribal) 106 129 15 38 0 67 46 194 40 635 

Mountrail, ND (Tribal) 695 851 101 248 0 3,074 2,130 8,951 1,818 17,868 

TOTAL (Tribal) 1,776 2,174 257 634 0 8,268 2,693 11,315 2,664 29,779 

Daniels, (MT) 

(Non-Tribal) 6 8 1 2 0 0 0 0 0 17 

Roosevelt, (MT) 

(Non-Tribal) 702 859 101 250 0 1,456 360 1,513 243 5,484 

Sheridan, (MT) 

(Non-Tribal) 1,310 1,604 189 468 4 2,229 551 2,316 189 8,861 

Valley, MT 

(Non-Tribal) 844 1,034 122 301 0 0 0 0 436 2,738 

Dunn, ND 

(Non-Tribal) 2,242 2,744 324 800 1,432 4,510 3,125 13,133 2,529 30,838 

McKenzie, ND 

(Non-Tribal) 5,259 6,437 760 1,877 7,348 4,982 3,452 14,507 4,117 48,740 

McLean, ND 

(Non-Tribal) 0 0 0 0 0 0 0 0 0 0 

Mountrail, ND 

(Non-Tribal) 2,471 3,025 357 882 1,720 13,736 9,518 39,998 5,659 77,367 
July 2013 

Final Report 39

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Final Report 40

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