March 2012

FEIS

Appendix G

Air Quality Technical Support Document
Greater Natural Buttes

Air Quality Technical Support Document

Bureau of Land Management

March 2012

Vernal Field Office/Utah
ES-1 March 2012

Executive Summary

The Bureau of Land Management has prepared this Technical Support Document to provide details of the air 

quality analysis that supports the Environmental Impact Statement for the infill drilling activity proposed within 

the Greater Natural Buttes Project Area (GNBPA). This document provides an overview of emissions for four 

modeling scenarios identified as follows:

• 2006 Baseline – 2006 base year actual emissions;

• 2018 Projected Baseline – 2018 projected emissions without the proposed project;

• 2017 Proposed Action – 2018 Projected Baseline with project emissions from the proposed 

development alternative in 2017 (3,675 wells); and 

• 2026 Optimal Recovery Alternative – 2018 Projected Baseline emissions with project emissions from 

the maximum recovery alternative development scenario in 2026 (13,446 wells).

Several models were used to characterize the air quality impacts from these scenarios, as summarized in the 

following sections. For the GNBPA, the existing air quality currently is classified as being in attainment or 

unclassifiable. Until the recent installation of two ozone monitors on tribal land northwest of the GNBPA in 

December 2008, there were no ambient air quality monitors in the Uinta Basin. Data from these two new 

stations were not available for use in the ozone modeling analysis. Therefore, the lack of usable direct 

measurements of the current air quality conditions in the Uinta Basin is a factor that prevents validation of the 

ozone model. However, the model does provide a means to compare the relative change in ambient ozone 

concentration between the project alternatives and baseline air quality.

ES-1 Emissions Summary 

Air emissions inventories for the modeled scenarios were developed from the Western Regional Air 

Partnership (WRAP) emissions inventories and project-specific data provided by Kerr-McGee Oil & Gas 

Onshore LP (KMG). The WRAP inventories were compiled using data provided by state and tribal regulatory 

agencies as well as industry partners for existing as well as projected oil and gas emission sources. These 

inventories include point, area, non-road mobile, and on-road mobile sources and include identification of 

these source groups by location (within counties and modeling grid cells). The WRAP emissions inventories 

include baseline data for nitrogen oxides (NOX), carbon monoxide (CO), sulfur dioxide (SO2), particulate matter 

less than 10 microns in aerodynamic diameter (PM10), fine particulate matter, and volatile organic compounds 

(VOCs).

All or portions of multiple WRAP inventories were used to develop emissions inventories for the 2006 Baseline 

and the 2018 Projected Baseline scenarios for this analysis. The WRAP inventories used are identified as 

follows:

• 2002 Plan2d – original WRAP baseline inventory for all sources (used non oil and gas portion only);

• 2018 PRP18a – original WRAP forecasted inventory for non-road mobile and on-road mobile sources;

• 2018 PRP18b – original WRAP forecasted inventory for point and area sources;

• 2002 Phase II – 2002 base year inventory for oil and gas sources outside the Uinta and Piceance 

basins only;

• 2018 Phase II – 2018 forecasted inventory for oil and gas sources outside the Uinta and Piceance 

basins only; 
ES-2 March 2012

• 2006 Draft Phase III – 2006 base year inventory for oil and gas sources in the Uinta and Piceance 

basins only; and

• 2012 Draft Phase III – 2012 base year inventory for oil and gas sources in the Uinta and Piceance 

basins only.

The WRAP III emissions inventory is an update of the WRAP II database based on existing and approved oil 

and gas emissions sources through 2006 in the Uinta and Piceance basins only. It focused additional effort on 

accounting for VOC emissions from regional sources, but it updated emissions of other criteria pollutants 

within these basins as well. The emission source categories and the development of these baseline 

inventories for 2006 and 2018 are summarized in Table ES-1.

Table ES-1 Summary of Baseline Inventory Development

Emissions Source Category

Inventory Used for 

2006 Baseline

Inventory Used for 

2018 Projected Baseline

Oil and Gas – Unita Basin WRAP Oil and Gas Phase III 2006 Projected from WRAP Phase III Oil and 

Gas 2006 based on projected cumulative 

activity in 2018

Oil and Gas – Piceance Basin WRAP Oil and Gas Phase III 2006 Projected from WRAP Phase III Oil and 

Gas 2006 and 2012 

Oil and Gas – All Other Basins Interpolated from WRAP Phase II Oil and 

Gas 2002 and 2018

WRAP Oil and Gas Phase II 2018

Point Sources – Non Oil and 

Gas

Interpolated from WRAP 2002 Plan2d and 

WRAP 2018 PRP18a

WRAP 2018 PRP18b

Area Sources – Non Oil and 

Gas

Interpolated from WRAP 2002 Plan2d and 

WRAP 2018 PRP18a

WRAP 2018 PRP18b

Non-Road Motor Vehicle Interpolated from WRAP 2002 Plan2d and 

WRAP 2018 PRP18a

WRAP 2018 PRP18a

On-Road Motor Vehicle Calculated with 2005/2006 meteorology and 

2006 vehicle miles traveled (VMT)

interpolated from WRAP 2002 Plan2D and 

WRAP 2018 PRP18a VMT

Calculated with 2005/2006 Meteorology 

and WRAP 2018 PRP18a VMT

Biogenic Model of Emissions of Gases and Aerosols 

from Nature (MEGAN) with 2005/2006 

meteorology

MEGAN with 2005/2006 meteorology (held 

steady from 2005/2006)

Wildfire 2006 Wildfire Inventory 2006 Wildfire Inventory (held steady from 

2006)

The 2018 Projected Baseline emissions inventory was developed to coincide with the 2018 projected WRAP 

Phase II inventory and the highest production year for the Proposed Action when planned drilling would still be 

occurring (2017). Emissions inventories for criteria pollutants and source characteristics for the Proposed 

Action and Optimal Recovery Alternative scenarios were based on project data provided by KMG. Sources 

were grouped as necessary to facilitate modeling and analysis.

The oil and gas emissions inventory in the Uinta Basin for the year 2018 was developed in two steps. First, the 

rate of activity increase in five operating factors (well counts, spud counts, gas production, condensate 

production, and oil production) was applied to relevant source category emissions for the Uinta Basin 2006 
ES-3 March 2012

WRAP Phase III inventory. Second, controls from applicant-committed measures, federally enforceable 

requirements, or binding agreements were applied. 

The 2018 Projected Baseline also was used as the baseline for the Optimal Recovery Alternative, though peak 

production under this alternative is anticipated in 2026. This approach provided a consistent basis of 

comparison between the alternatives and reduced uncertainty in baseline emissions from projecting 

development beyond the WRAP inventory time horizon. 

Emissions Data Assumptions

Emissions data for the Proposed Action and the Optimal Recovery Alternative were developed from available 

emission factors, analytical data, applicable applicant-committed environmental protection measures, 

applicant-provided equipment specifications, federally required controls or emission standards, and anticipated 

activity levels. Emission rates were developed for the criteria pollutants and for selected hazardous air 

pollutants (HAPs). A summary of criteria pollutant emissions from stationary sources in the Uinta Basin is 

provided in Table ES-2, and the project-related increases in the major components of HAPs for the Proposed 

Action and Optimal Recovery Alternative are provided in Table ES-3. Emissions for a full list of HAPs were 

reviewed, but only those with the greatest emissions in relation to health effects were evaluated. 

Table ES-2 Summary of Criteria Pollutant Emissions for Each Scenario

Criteria 

Pollutant

Emissions (tons per year [tpy])

2006

Baseline

2018 Projected

Baseline

2017 Proposed Action

2026 Optimal Recovery

Alternative

Project Total Project Total

NOX 10,754 10,138 2,213 12,209 4,946 15,084

CO 7,800 9,732 1,300 10,887 2,994 12,726

SO2 391 30 25 55 78 108

PM10 592 565 1,011 1,538 2,657 3,223

VOC 70,226 184,262 6,617 190,916 24,976 209,238

Table ES-3 Summary of Potential Increases in Emissions of HAPs for Project-related Alternatives

Pollutant

Potential HAP Increase (tpy)

Proposed Action Optimal Recovery Alternative

Benzene 67.0 255.2

Toluene 172.4 661.9

Ethyl Benzene 12.7 48.5

Xylenes 185.7 714.1

Formaldehyde 71.3 156.5

n-Hexane 194.9 748.5
ES-4 March 2012

ES-2 Model Types

Air quality impacts were assessed for the Proposed Action and Optimal Recovery Alternative using the 

following air quality models:

• CALPUFF – This United States (U.S). Environmental Protection Agency (USEPA) guideline modeling 

system was used to determine air quality and visibility impacts at Class I areas (e.g., national parks 

and wilderness areas) in the region as well as at selected Class II sensitive areas. Further, this model 

addressed acid deposition in these areas and impacts to acid neutralizing capacity (ANC) in specified 

lakes of concern.

• CMAQ – The Community Multi-Scale Air Quality Model (CMAQ) was used to determine impacts on 

regional ozone levels.

• AERMOD – This USEPA guideline model was used to assess impacts of a typical development 

scenario in the near-field (within 50 kilometers [km]).

The region of study, or modeling domain, for the CALPUFF and CMAQ model systems is depicted in 

Figure ES-1, including the location of the GNBPA and the identified Class I and sensitive Class II areas. The 

AERMOD model assessed impacts within 50 km of each modeled source within the development scenario for 

the project. Therefore, there was no specified study domain for the AERMOD analysis. Models generally were 

run with default values or with model settings that were representative of the region.

ES-3 Summary of Impacts on Class I and Selected Class II Areas – Air Quality 

The guideline CALPUFF modeling system was used to determine impacts on Class I areas and sensitive

Class II areas in the region. 

Proposed Action 

The greatest impact on ambient air quality from project sources on Class I areas was at Arches National Park, 

where the maximum impact for all criteria air pollutants occurs. The highest PM10 24-hour impact was 

0.10 micrograms per cubic meter (μg/m3

) at this site. All other impacts for all criteria pollutants at all Class I 

areas for the Proposed Action were below 0.01 μg/m3

. 

The greatest impacts at the identified sensitive Class II areas were at the Flaming Gorge National Recreation 

Area with the maximum 24-hour PM10 impact of 3.23 μg/m3 and the maximum annual PM10 impact of 

0.58 μg/m3

. All other impacts from all other criteria pollutants at Class II areas were less than 0.5 μg/m3.

Optimal Recovery Alternative

For the Optimal Recovery Alternative at Class I areas, the maximum 24-hour PM10 impact was 0.24 μg/m3 at 

Arches National Park. The maximum annual average PM10 impact of 0.02 μg/m3 also occurred at the Arches 

National Park. All other impacts from all other criteria pollutants in Class I areas were less than 0.13 μg/m3

.

At sensitive Class II areas under the Optimal Recovery Alternative, the maximum impacts were at the Flaming 

Gorge National Recreation Area for all criteria air pollutants. The maximum annual average NO2 impact was 

0.94 μg/m3

. The PM10 impact on a 24-hour average was 7.36 μg/m3, and the annual PM10 impact was 

1.38 μg/m3

. Impacts from all other criteria pollutants at all other Class II areas were less than 1.0 μg/m3.
ES-5 March 2012

Figure ES-1 Greater Natural Buttes Modeling Domain
ES-6 March 2012

ES-4 Cumulative Impacts 

When added to the background concentrations, all cumulative impacts from all sources for each of the 

alternatives, including the modeled non-project sources, were well below the established National Ambient Air 

Quality Standards (NAAQS) for all criteria air pollutants.

Summary Impact at Class I/II Areas – Visibility 

The CALPUFF model system also was used to evaluate impacts on visibility at the Class I areas and at the 

listed sensitive Class II areas. 

Proposed Action 

The results of the CALPUFF analysis showed that there were no days with a contribution to visibility impacts 

greater than 10 percent increase in the light extinction coefficient (1.0 deciview) at listed Class I areas. 

Therefore, the Proposed Action would not contribute to an impact on visibility at the Class I Areas. 

The modeling results at the listed sensitive Class II areas showed the highest impacts at Flaming Gorge 

National Recreation Area and Dinosaur National Monument. The CALPUFF modeling showed that up to 

102 days would be impacted with greater than 10 percent increase in light extinction at Flaming Gorge. The 

same analysis showed the eighth highest increase in extinction for the Proposed Action was 32.6 percent. At 

Dinosaur National Monument, the model predicted 32 days per year with an impact above 10 percent and an 

eighth highest increase in light extinction of 16.6 percent. Except at Flaming Gorge National Recreation Area 

and Dinosaur National Monument, modeled results for all other Class II areas under CALPUFF Method 6 

showed that all of the eighth highest impacts are less than a 10 percent increase in light extinction above 

natural background (expressed as an impact of 1.0 deciviews). Class II areas were included in the analysis as 

a courtesy to sister federal agencies. Class II areas have no visibility protection under state or federal laws or 

regulations.

Optimal Recovery Alternative

For the Optimal Recovery Alternative, all project-related impacts were below 10 percent light extinction at all 

Class I areas. At Class II areas, the eighth highest impacts using CALPUFF Method 6 were above 10 percent 

at Flaming Gorge National Recreation Area and Dinosaur National Monument. The Method 6 analysis showed

that the eighth highest increase in light extinction for project-related sources was 62.4 percent at Flaming 

Gorge, with 156 days predicted to be greater than 10 percent. At Dinosaur National Monument, the eighth 

highest increase was 32.7 percent, with 71 days predicted to be greater than 10 percent.

ES-5 Summary Impacts at Class I/II areas – Acid Deposition 

The CALPUFF model system also provided acid deposition results for nitrate and sulfate ion deposition at

Class I and sensitive Class II areas, which were then used to analyze impacts to the ANC of selected sensitive 

lakes in the modeling domain. 

Acid Deposition

Impacts from project-related sources for both the Proposed Action and the Optimal Recovery Alternative were 

well below the U.S. Forest Service (USFS) established comparative deposition values (5 and 3 kilograms per 

hectare-year for sulfur and nitrogen deposition, respectively). Cumulative deposition from all modeled sources 

also was below the established comparative deposition values for both alternatives at all Class I and Class II 

areas except Mesa Verde National Park.
ES-7 March 2012

Acid Neutralization

The model showed project-related impacts at all identified sensitive lakes to be below the USFS screening

threshold for ANC established for further analysis. Therefore, no additional analysis was conducted for these 

impacts.

ES-6 Summary Impacts on Ambient Ozone Levels 

Ozone Model and Limitations

Impacts on ambient air ozone levels were evaluated using the CMAQ model system. The modeling system 

met the USEPA-established criteria for acceptable model accuracy and error statistics at the existing 

monitoring stations within the modeling domain but not in the GNBPA. There were no recent or statistically 

valid representative monitoring data that could be used to compare baseline modeled impacts to actual levels 

in the GNBPA. The Greater Natural Buttes project model was run using the 2006 WRAP Phase III emissions 

data, but there were no concurrent ambient measurements to compare the modeled results to actual 

monitored concentrations. This lack of concurrent data prevented validation and calibration of the model 

results; however, the model did provide a means to compare the relative change in ambient ozone 

concentration between the project alternatives and baseline air quality. 

Ozone Model Results

The model results showed no impacts above the current ozone standard of 75 parts per billion (ppb) for the 

fourth highest annual level in the Uinta Basin for the Projected Baseline and the project alternatives. The 

maximum fourth highest impact was 2.4 ppb from the Proposed Action scenario and 4.9 ppb from the Optimal 

Recovery Alternative. For both scenarios, the impacts were occurring in areas simulated to remain below the 

75 ppb ozone standard.

ES-7 Localized Impacts on Air Quality 

AERMOD Model and Limitations

The AERMOD modeling system was used to evaluate localized impacts on criteria air pollutants at receptors 

within the GNBPA. A series of source configurations was developed, including well sites, drilling, operation,

and compression, and projected air quality impacts on the near-field, which was defined as receptors within 

50 km. The model used a 5-year period of meteorological data from the Vernal Airport. Due to the lack of air 

quality monitoring data in this region, it was difficult to assess background concentrations for determining 

compliance with ambient air quality standards.

AERMOD Model Results

Using background data from AQS, the localized impacts on ambient air quality for criteria pollutants of 

single sources plus background were all less than the NAAQS. The impacts of all multiple production 

well scenarios also were below the NAAQS. Near-field modeling showed that simultaneous operation 

of drill rigs on adjacent pads would not cause an exceedance of the NAAQS for 1-hour NO2. The 

modeled ambient air concentrations of HAPs do not exceed USEPA RfCs or TSLs for any scenario or 

pollutant.

ES-8 Greenhouse Gas Emissions

The predicted annual increase in greenhouse gas emissions (carbon dioxide [CO2], nitrous oxide, and

methane) were tabulated for both the Proposed Action and the Optimal Recovery Alternative. Both direct 

project-related and indirect (from electric power generation) emissions were included. During the maximum 
ES-8 March 2012

production year for each alternative, a total 2.75 million metric tons of CO2 equivalent gases would be emitted 

by the Proposed Action, and 5.48 million metric tons of CO2 equivalent gases would be emitted by the Optimal 

Recovery Alternative.
i March 2012

Contents

Executive Summary ........................................................................................................................................ES-1

1.0 Introduction and Background..................................................................................................................1-1

1.1 Project Description...............................................................................................................................1-1

1.2 Overview of Modeling Approach.........................................................................................................1-4

1.2.1 Modeling Systems .................................................................................................................1-4

1.3 Development of Emissions Inventories and Pollutants of Interest.....................................................1-5

1.4 Assessment Approach ........................................................................................................................1-6

2.0 Study Area and Background for Air Quality Analyses.........................................................................2-1

2.1 Regional Setting for Air Quality...........................................................................................................2-1

2.2 Recent Development in the Region ....................................................................................................2-3

2.3 Background Air Quality........................................................................................................................2-3

2.4 Standards and Evaluation ...................................................................................................................2-5

2.4.1 National Ambient Air Quality Standards ...............................................................................2-5

2.4.2 Prevention of Significant Deterioration..................................................................................2-7

2.4.3 Nonattainment New Source Review .....................................................................................2-9

2.4.4 Conformity for General Federal Actions ...............................................................................2-9

2.4.5 New Source Performance Standards ...................................................................................2-9

2.4.6 National Emission Standards for Hazardous Air Pollutants...............................................2-11

2.5 Carbon Dioxide and Other Greenhouse Gases ...............................................................................2-11

3.0 Emissions Data ..........................................................................................................................................3-1

3.1 Current and Projected Baseline Emissions Input Procedures...........................................................3-1

3.1.1 Development of Uinta Basin 2018 Projected Baseline Emissions.......................................3-3

3.1.2 Development of CMAQ-ready Emissions Inventories........................................................3-13

3.1.3 Set-up of SMOKE for the Baseline Emissions Development.............................................3-14

3.1.4 Development of Point Source Emissions............................................................................3-14

3.1.5 Development of Area and Non-road Source Emissions ....................................................3-15

3.1.6 Development of On-road Mobile Source Emissions ..........................................................3-15

3.1.7 Development of Biogenic Source Emissions......................................................................3-16

3.1.8 Wildfires and Prescribed Burns...........................................................................................3-16

3.1.9 Products of the Emissions Inventory Development Process .............................................3-16

3.2 Determination of Cumulative Impacts...............................................................................................3-18

3.3 Construction Emissions.....................................................................................................................3-18

3.4 Drilling Emissions ..............................................................................................................................3-19

3.4.1 Emissions from Drill Rig Operation .....................................................................................3-19

3.4.2 Criteria Pollutant Emissions from Drilling and Completion Traffic .....................................3-21

3.4.3 Drilling Emissions Summary................................................................................................3-23
ii March 2012

3.5 Production Emissions........................................................................................................................3-24

3.5.1 VOC and HAP Emissions from Condensate Flashing .......................................................3-24

3.5.2 Emissions from Separator Heaters .....................................................................................3-26

3.5.3 Fugitive Emissions...............................................................................................................3-27

3.5.4 Production Traffic.................................................................................................................3-28

3.5.5 Summary..............................................................................................................................3-30

3.6 Operation Emissions .........................................................................................................................3-31

3.6.1 Water Tank Battery Operation ............................................................................................3-31

3.6.2 Water Injection Facility Operation .......................................................................................3-33

3.6.3 Gas-fired Compression Engines .........................................................................................3-33

3.7 Modeling Inventory Development for Project Alternatives ...............................................................3-37

4.0 Modeling Procedures ................................................................................................................................4-1

4.1 CALPUFF Modeling.............................................................................................................................4-1

4.1.1 Model Options and Computational Domain..........................................................................4-1

4.1.2 Assessment Areas and Receptor Grids................................................................................4-2

4.1.3 CALPUFF Emission Inputs....................................................................................................4-4

4.1.4 CALMET Processing and Meteorological Data Development.............................................4-4

4.1.5 CALPUFF Background Air Quality Data...............................................................................4-6

4.2 CMAQ Ozone Modeling ......................................................................................................................4-8

4.2.1 CMAQ Modeling Setup..........................................................................................................4-8

4.2.2 Modeling Domains.................................................................................................................4-8

4.2.3 Model Input Preparation Procedures ..................................................................................4-12

4.2.4 CMAQ Science and Input Configurations...........................................................................4-13

4.3 AERMOD Near-field Modeling ..........................................................................................................4-15

4.3.1 Criteria Pollutant Analysis....................................................................................................4-15

4.3.2 Meteorological Data Development......................................................................................4-25

4.3.3 HAPs Analysis .....................................................................................................................4-25

5.0 Assessment and Reporting of Air Quality Impacts...............................................................................5-1

5.1 CALPUFF Impact Assessment for Class I and Sensitive Class II Areas ..........................................5-1

5.1.1 Ambient Air Quality Impact Assessment – Criteria Pollutants .............................................5-1

5.1.2 Impact Assessment Air Quality Related Values – Regional Haze.......................................5-8

5.1.3 Acid Deposition and Lake Chemistry..................................................................................5-14

5.2 CMAQ Ozone Impact Assessment...................................................................................................5-19

5.2.1 CMAQ 2005/2006 Base Case Modeling Results ...............................................................5-19

5.2.2 CMAQ Ozone Impact Assessment of Alternatives.............................................................5-21

5.2.3 Impact Assessment at Monitors..........................................................................................5-22

5.2.4 Impact Assessment in Areas Removed from Monitors ......................................................5-26

5.2.5 Ozone Projections Using Absolute Modeling Results........................................................5-34

5.2.6 Ozone Impact Assessment Summary ................................................................................5-34
iii March 2012

5.3 AERMOD Impact Assessment for Near-Field Receptors ................................................................5-41

5.3.1 Criteria Pollutant Analysis....................................................................................................5-41

5.3.2 HAP Analysis .......................................................................................................................5-41

6.0 Greenhouse Gas Emissions.....................................................................................................................6-1

6.1 General Quantification Methods .........................................................................................................6-1

6.2 Well Count ...........................................................................................................................................6-1

6.3 Combustion Sources ...........................................................................................................................6-1

6.3.1 Fuels.......................................................................................................................................6-2

6.3.2 Stationary Combustion Sources............................................................................................6-2

6.3.3 Mobile Combustion Sources .................................................................................................6-3

6.4 Flaring ..................................................................................................................................................6-8

6.5 Flashing Emissions..............................................................................................................................6-8

6.5.1 Condensate Flashing.............................................................................................................6-8

6.5.2 Water Flashing.......................................................................................................................6-9

6.6 Fugitive Emissions...............................................................................................................................6-9

6.7 Indirect Emissions..............................................................................................................................6-10

6.8 Venting...............................................................................................................................................6-11

6.8.1 Pneumatics ..........................................................................................................................6-11

6.8.2 Workovers............................................................................................................................6-11

6.8.3 Completions .........................................................................................................................6-11

6.9 Summary of GHG Emissions ............................................................................................................6-12

7.0 Air Quality Summary .................................................................................................................................7-1

7.1 Impact on Class I and II Areas – Air Quality.......................................................................................7-1

7.2 Impact at Class I and II Areas – Visibility............................................................................................7-1

7.3 Impacts at Class I and II areas – Acid Deposition..............................................................................7-2

7.4 Impacts on Ambient Ozone Levels .....................................................................................................7-2

7.5 Localized Impacts on Air Quality.........................................................................................................7-2

7.6 Greenhouse Gas Emissions ...............................................................................................................7-3

8.0 References..................................................................................................................................................8-1
iv March 2012

List of Appendices

Appendix A Projected Baseline Emissions Calculations Supporting Data

Appendix B Project-specific Emissions Calculations Supporting Data

Appendix C Spatially Distributed Project Alternatives Emissions Inventories

Appendix D Project Alternatives Emissions Inputs to CALPUFF

Appendix E Project Alternatives Compression Inventories

Appendix F SANGEA Output for Analysis of Greenhouse Gases
v March 2012

List of Tables

Table 1-1 Applicant-committed Environmental Protection Measures Considered in Modeling .................1-3

Table 2-1 Period of Record Monthly Climate Summary ..............................................................................2-1

Table 2-2 Background Ambient Air Quality Data .........................................................................................2-3

Table 2-3 Applicable Ambient Air Quality Standards...................................................................................2-7

Table 2-4 Class I and Sensitive Class II Areas of Concern for Air Quality Impact Analysis ......................2-8

Table 2-5 PSD Increments for Class I and Class II Areas...........................................................................2-8

Table 3-1 Summary of Baseline Inventory Development............................................................................3-2

Table 3-2 Summary of New Well Development for Proposed Projects in the Uinta Basin ........................3-3

Table 3-3 Activity Parameters Used for Emissions Scaling by Source Category Code.............................3-4

Table 3-4 Projected Total New and Cumulative Well Count by Year and County .....................................3-5

Table 3-5 Project Spud Count for 2018 by County......................................................................................3-6

Table 3-6 Projected 2018 Gas and Condensate Production for Uintah County.........................................3-6

Table 3-7 Projected 2018 Gas and Condensate Production for Duchesne County...................................3-7

Table 3-8 Projected 2018 Gas Production for Carbon County....................................................................3-8

Table 3-9 Historic and Projected 2018 Gas and Condensate Production for Carbon County...................3-9

Table 3-10 Historic and Projected 2018 Oil Production for Uintah and Duchesne Counties .......................3-9

Table 3-11 Summary of Projected Activity Parameters and 2018 Scaling Ratios......................................3-10

Table 3-12 Baseline Emissions Control Efficiencies from Promulgated Federal Rules .............................3-11

Table 3-13 Baseline Emissions Control Efficiency from Consent Decrees ................................................3-11

Table 3-14 Summary of Projected Baseline NOX Emissions for 2018........................................................3-12

Table 3-15 Summary of Projected Baseline CO Emissions for 2018 .........................................................3-12

Table 3-16 Summary of Projected Baseline SO2 Emissions for 2018 ........................................................3-13

Table 3-17 Summary of Projected Baseline PM10 Emissions for 2018.......................................................3-13

Table 3-18 Summary of Projected Baseline VOC Emissions for 2018.......................................................3-13

Table 3-19 2006 Weeks Representing On-road Mobile Sources................................................................3-14

Table 3-20 Pollutant Emissions from Rig Engines per Well Drilled.............................................................3-20

Table 3-21 Pollutant Emissions from Rig Boilers per Well Drilled...............................................................3-21

Table 3-22 PM Emissions from Unpaved Roads for Drilling Traffic............................................................3-22

Table 3-23 PM Emissions from Unpaved Roads for Completion Traffic ....................................................3-22

Table 3-24 PM Emissions from Unpaved Roads for Rig Hauling Traffic ....................................................3-22

Table 3-25 Heavy Truck Criteria Pollutant Emissions from Well Drilling, Completion, and 

Rig Hauling .................................................................................................................................3-23

Table 3-26 Summary of Pollutant Emissions for Well Installation...............................................................3-23

Table 3-27 Condensate Flashing Calculation Process Physical Characteristics .......................................3-24
vi March 2012

Table 3-28 Condensate Flashing Calculation Chemical Characteristics ....................................................3-25

Table 3-29 Emissions of VOC and HAP from Condensate Flashing..........................................................3-26

Table 3-30 Emissions from Separator Heaters at Production Wells...........................................................3-26

Table 3-31 Emissions of VOC from Fugitive Leaks at Production Wells ....................................................3-27

Table 3-32 Emissions of Selected HAP from Fugitive Leaks at Production Wells .....................................3-28

Table 3-33 PM Emissions from Unpaved Roads for Production Traffic per Operational Well...................3-29

Table 3-34 Criteria Pollutant Emissions from Tanker Truck Traffic.............................................................3-30

Table 3-35 Summary of Criteria Pollutant Emissions for Production Wells ................................................3-30

Table 3-36 Physical Properties of Tank Condensate ..................................................................................3-31

Table 3-37 Produced Water and Condensate Throughput for Water Tank Batteries ................................3-32

Table 3-38 VOC and HAP Emissions from Water Tank Batteries ..............................................................3-32

Table 3-39 Criteria Pollutant Emissions from Water Injection Engines.......................................................3-33

Table 3-40 Criteria Pollutant Emissions from Gas-fired Compression Engines (1,265 hp) .......................3-34

Table 3-41 Criteria Pollutant Emissions from Gas-fired Compression Engines (1,340 hp) .......................3-34

Table 3-42 Criteria Pollutant Emissions from Gas-fired Compression Engines (2,370 hp) .......................3-34

Table 3-43 Summary of Criteria Pollutant Emissions from Gas-fired Compression for the 

Proposed Action .........................................................................................................................3-35

Table 3-44 Summary of Criteria Pollutant Emissions from Gas-fired Compression for the 

Optimal Recovery Alternative.....................................................................................................3-36

Table 3-45 Summary of HAPs from Gas-Fired Compression for the Proposed Action .............................3-37

Table 3-46 Summary of HAPs from Gas-Fired Compression for the Optimal Recovery Alternative.........3-37

Table 3-47 Summary of Criteria Pollutant Emissions for the Proposed Action ..........................................3-39

Table 3-48 Summary of Criteria Pollutant Emissions for Optimal Recovery Alternative............................3-39

Table 3-49 Summary of Hazardous Air Pollutant Emissions for the Proposed Action...............................3-40

Table 3-50 Summary of Hazardous Air Pollutant Emissions for Optimal Recovery Alternative ................3-40

Table 4-1 Preliminary CALMET User-defined Fields Not Specified in IWAQM Appendix A......................4-6

Table 4-2 Lambert Conformal Projection Definition for the GNB Modeling Grid ......................................4-10

Table 4-3 Grid Definitions for SMOKE and CMAQ....................................................................................4-11

Table 4-4 Vertical Layer Definition for MM5 Simulations and Approach for Reducing CMAQ 

Layers by Collapsing Multiple MM5 Layers...............................................................................4-12

Table 4-5 CMAQ Model Configuration .......................................................................................................4-14

Table 4-6 Project Source Modeling Parameters and Emission Rates......................................................4-20

Table 4-7 HAP Emission Rates ..................................................................................................................4-28

Table 5-1 2017 Proposed Action CALPUFF Modeled Concentrations – Criteria Pollutants .....................5-2

Table 5-2 2026 Optimal Recovery Alternative CALPUFF Modeled Concentrations – Criteria 

Pollutants ......................................................................................................................................5-5

Table 5-3 2017 Proposed Action CALPUFF Modeled Results – Regional Haze.....................................5-10
vii March 2012

Table 5-4 2026 Optimal Recovery Alternative CALPUFF Modeled Results – Regional Haze ................5-12

Table 5-5 2017 Proposed Action CALPUFF Modeled Results – Acid Deposition ...................................5-16

Table 5-6 2026 Optimal Recovery Alternative CALPUFF Modeled Results – Acid Deposition...............5-17

Table 5-7 Modeled Impacts on Acid Sensitive Lakes................................................................................5-18

Table 5-8 Ozone Model Performance Bias and Error Statistics................................................................5-19

Table 5-9 Annual Monitoring Station 8-hour Ozone Design Values and Future Year Design 

Values for 2005 Meteorological Year.........................................................................................5-24

Table 5-10 Annual Monitoring Station 8-hour Ozone Design Values and Future Year Design 

Values for 2006 Meteorological Year.........................................................................................5-25

Table 5-11 AERMOD Near-field Criteria Pollutants Assessment Modeling Result 

Summary – Single Source Impact Analysis ..............................................................................5-42

Table 5-12 AERMOD Near-field Criteria Pollutants Modeling Results – Well Pad Production 

Analysis.......................................................................................................................................5-43

Table 5-13 AERMOD Near-field Criteria Pollutants Modeling Results – Well Drilling Analysis .................5-44

Table 5-14 AERMOD HAPs Near-field Assessment Modeling Result Summary – Single Source 

Impact Analysis...........................................................................................................................5-47

Table 5-15 AERMOD HAPs Near-field Modeling Results – Well Pad Production Analysis.......................5-48

Table 5-16 AERMOD HAPs Near-field Modeling Results – Well Drilling Analysis.....................................5-49

Table 6-1 Estimated Number of Wells Drilled and Operating in Maximum Production Year.....................6-1

Table 6-2 Local Fuel Gas Specifications......................................................................................................6-2

Table 6-3 Annual Consumption of Uinta Fuel Gas for Separator Heaters per Project Alternative ............6-3

Table 6-4 Annual Consumption of Uinta Fuel Gas for Produced Water Injection per Project 

Alternative.....................................................................................................................................6-3

Table 6-5 Annual Consumption of Diesel Fuel for Drill Rig Engines and Boilers .......................................6-4

Table 6-6 Load Adjusted Engine Operation for Well Pad Construction......................................................6-5

Table 6-7 Load Adjusted Engine Operation for Construction of Mancamps, Injection Facilities, 

and Linear Facilities......................................................................................................................6-5

Table 6-8 Load Adjusted Engine Operation for Well Drilling .......................................................................6-5

Table 6-9 Diesel Fuel Consumption Factor for Mobile Equipment by Activity............................................6-6

Table 6-10 Annual Diesel Fuel Consumption for Mobile Equipment by Alternative and Activity .................6-6

Table 6-11 Diesel Fuel Consumption Factor by Activity................................................................................6-6

Table 6-12 Annual Diesel Fuel Consumption for Heavy Truck Traffic by Alternative and Activity...............6-7

Table 6-13 Gasoline Consumption Factor by Activity....................................................................................6-7

Table 6-14 Annual Gasoline Consumption for Light Duty Vehicle Traffic by Alternative and Activity..........6-7

Table 6-15 Gas Flaring by Alternative............................................................................................................6-8

Table 6-16 Summary of Condensate Physical Characteristics .....................................................................6-8

Table 6-17 Maximum Condensate Production by Alternative .......................................................................6-9

Table 6-18 Produced Water by Alternative ....................................................................................................6-9
viii March 2012

Table 6-19 Emissions Factors and Operating Parameters for Estimating Fugitive CH4 Emissions ..........6-10

Table 6-20 GHG Emissions Factors for Imported Utah-based Electric Consumption ...............................6-10

Table 6-21 Summary of Estimated Electricity Consumption for Added Electric Compression ..................6-10

Table 6-22 Summary of Venting Parameters for GHG Emissions Calculations.........................................6-11

Table 6-23 Maximum Projected Annual GHG Emissions Increase by Alternative.....................................6-12

Table 6-24 Detailed Summary of Annual GHG Emissions by Source for the No Action Alternative.........6-12

Table 6-25 Detailed Summary of Annual GHG Emissions by Source for the Proposed Action ................6-13

Table 6-26 Detailed Summary of Annual GHG Emissions by Source for the Optimal Recovery 

Alternative...................................................................................................................................6-13

Table 6-27 Summary of Input Parameters for GHG Calculations ...............................................................6-14
ix March 2012

List of Figures

Figure 1-1 Location of GNBPA .................................................................................................................. 1-2

Figure 2-1 Wind Rose from Vernal, Utah, Airport ..................................................................................... 2-2

Figure 2-2 Ouray and Redwash Ozone Monitoring Data ......................................................................... 2-6

Figure 4-1 Modeling Domain and Location of Class I and Class II Receptors ........................................ 4-3

Figure 4-2 2018 CALPUFF Modeled Point and Area Sources................................................................. 4-5

Figure 4-3 Meteorological Stations Selected for Input to CALMET.......................................................... 4-7

Figure 4-4 36- and 12-km Domains for the GNB Study............................................................................ 4-9

Figure 4-5 12-km CMAQ Domain for the GNB Study............................................................................. 4-10

Figure 4-6 12-km WRAP MM5 with 12-km CMAQ Domain in the GNB Study...................................... 4-11

Figure 4-7 Ouray Diurnal Ozone Profile of Maximum Hourly Values by Season .................................. 4-16

Figure 4-8 Ouray Diurnal Ozone Profile of 98th Percentile Maximum Hourly Values by Season.......... 4-18

Figure 4-9 Single Source Impact Analysis Model Setup and Receptor Location .................................. 4-19

Figure 4-10 10-Acre Well Pad Production Analysis Model Setup and Receptor Location...................... 4-22

Figure 4-11 20-Acre Well Pad Production Analysis Model Setup and Receptor Location...................... 4-23

Figure 4-12 40-Acre Well Pad Production Analysis Model Setup and Receptor Location...................... 4-24

Figure 4-13 Short-term Drill Rig Analysis Model Setup and Receptor Location (400-m spacing) .......... 4-26

Figure 4-14 Annual Drill Rig Analysis Model Setup and Receptor Location............................................ 4-27

Figure 5-1 Sensitive Lakes Analyzed in the Acid Neutralizing Capacity Analysis ................................. 5-15

Figure 5-2 Depiction of Predicted and Observed Fourth highest Daily Maximum 8-hour Ozone 

Concentrations for 2005 and 2006 ........................................................................................ 5-20

Figure 5-3 Ozone Monitoring Stations..................................................................................................... 5-23

Figure 5-4 Baseline 8-hour Ozone Design Values.................................................................................. 5-27

Figure 5-5 Annual 8-hour Ozone Future Design Values for 2018 Projected Baseline.......................... 5-28

Figure 5-6 Annual 8-hour Ozone Future Design Values for 2017 Proposed Action.............................. 5-29

Figure 5-7 Annual 8-hour Ozone Future Design Values for 2026 Optimal Recovery Alternative......... 5-30

Figure 5-8 Annual 8-hour Ozone Future Design Value Differences for Proposed Action Minus 

2018 Projected Baseline ........................................................................................................ 5-31

Figure 5-9 Annual 8-hour Ozone Future Design Value Differences for Optimal Recovery Minus 

2018 Projected Baseline ........................................................................................................ 5-32

Figure 5-10 Annual 8-hour Ozone Future Design Value Differences for Optimal Recovery Minus 

Proposed Action ..................................................................................................................... 5-33

Figure 5-11 Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone Concentration (ppb) 

for 2018 Projected Baseline................................................................................................... 5-35

Figure 5-12 Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone Concentration (ppb) 

for 2017 Proposed Action....................................................................................................... 5-36
x March 2012

Figure 5-13 Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone Concentration 

(ppb) for 2026 Optimal Recovery........................................................................................... 5-37

Figure 5-14 Difference in Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone 

Concentration (ppb) for Proposed Action Minus 2018 Projected Baseline .......................... 5-38

Figure 5-15 Difference in Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone 

Concentration (ppb) for Optimal Recovery Minus 2018 Projected Baseline........................ 5-39

Figure 5-16 Difference in Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone 

Concentration (ppb) for Optimal Recovery Minus Proposed Action..................................... 5-40

Figure 5-17 1-hour NO2 Impacts from Well Drilling with Tier 2 Engines (400-m spacing)....................... 5-45

Figure 5-18 1-hour NO2 Impacts from Well Drilling with Tier 4 Engines (400-m spacing)....................... 5-46
1-1 March 2012

1.0 Introduction and Background

Kerr-McGee Oil & Gas Onshore LP (KMG), a wholly owned subsidiary of Anadarko Petroleum Corporation, 

proposes to conduct infill drilling to develop the hydrocarbon resources underlying oil and gas leases owned, 

at least in part, by KMG within the Greater Natural Buttes Project Area (GNBPA) in Uintah County, Utah. KMG 

plans to explore and develop all potentially productive subsurface formations underlying the GNBPA. KMG is 

the designated operator or owns contractual leasehold rights for more than 85 percent of the lands within the 

GNBPA boundary. The oil and gas leases were issued by the Bureau of Land Management (BLM), State of 

Utah, Bureau of Indian Affairs (BIA), and private owners. 

The BLM is analyzing the environmental impacts of the proposed project by preparing an Environmental 

Impact Statement (EIS) as required by the National Environmental Policy Act (NEPA). In support of NEPA 

requirements, this document presents a technical analysis of air quality issues related to development of the 

resources within the GNBPA. The purpose of this analysis is to provide the details of the air quality technical 

data and assumptions that were used to develop the air quality review and evaluation of impacts as required 

under NEPA. 

In response to comments on the Draft EIS, a supplemental air quality analysis was conducted in 

December 2010. This analysis addresses potential air quality impacts from the project relative to new 

National Ambient Air Quality Standards (NAAQS) promulgated in 2010 subsequent to the analysis 

conducted for the Draft EIS. Further, additional analysis was conducted to determine ambient air 

concentrations of selected hazardous air pollutants (HAPs). The supplemental analysis also discloses

additional air quality monitoring data collected in 2010 from stations near the GNBPA.

1.1 Project Description

KMG proposes to drill and produce natural gas supplies in the GNBPA shown in Figure 1-1. This project area 

consists of approximately 162,911 acres in an existing gas producing area located in T8S/R20-23E, 

T9S/R20-24E, T10S/R20-23E, and T11S/R21-22E in Uintah County, Utah. The GNBPA encompasses

88,565 acres of federal land administered by the BLM; 39,399 acres of land owned by the Northern Ute Tribe 

and administered by the BIA; 32,755 acres of land owned by the State of Utah; and 2,192 acres of privately 

owned land. 

KMG’s proposed development plan, referred to in this document as the Proposed Action, is to drill additional 

wells at an average rate of approximately 358 wells per year over a period of about 10 years or until the 

resource base is fully developed, with a maximum total of 3,675 wellbores. The total number of wells drilled 

during the life of the project or during any particular year would depend largely on factors outside of KMG’s 

control such as permit approvals, production success, engineering technology, economic factors, commodity 

prices, rig availability, and lease stipulations. The productive life of each well is estimated to be 30 to 50 years. 

Infill drilling would be performed on 40-acre and 20-acre surface spacing throughout the GNBPA (i.e., 16 to 

32 surface well pads per square mile, respectively). KMG defines a 40-acre well pad as the first well pad 

located in a 40-acre quarter-quarter of a square mile section of land. A 20-acre pad is defined as the second 

well pad located in a 40-acre quarter-quarter section. Downhole well spacing would be based on reservoir 

engineering evaluation on an on-going basis and would be site-dependent, potentially ranging from 16 wells 

per section (40-acre spacing) to 64 wells per section (10-acre spacing). In areas where the gas resources in 

the reservoirs warrant a downhole spacing of less than 20 acres based on reservoir engineering evaluation, 

KMG would test and attempt to utilize directional drilling technology to drill from nearby 20-acre or 40-acre 

pads, if such is technically and economically viable. In general, the surface density of the KMG well pads 

would not exceed 32 pads per section. This equates to an average spacing between pads of approximately 

285 meters (m), a distance that is incorporated into air modeling procedures described in this document.
1-2 March 2012

Figure 1-1 Location of GNBPA
1-3 March 2012

KMG has committed to a number of environmental protection measures to reduce emissions of criteria and 

HAPs from the proposed project. Those measures that were quantified in the modeling analysis are 

summarized in Table 1-1.

Table 1-1 Applicant-committed Environmental Protection Measures Considered in Modeling

Source Type Proposed Control Considerations in Modeling Analysis

Natural Gas Fired 

Engines

For engines greater than 500 

horsepower (hp), install lean burn 

engines or engines equipped to 

achieve comparable emissions 

reduction.

All stationary engines considered for the project 

are greater than 500 hp, and therefore will be 

considered lean burn. KMG provided 

manufacturer specified emission rates for 

compression engines. 

Install catalyst on all natural gas 

fired compression.

Because all compression engines

considered in the analysis are lean burn, the 

analysis assumes the use of oxidation 

catalysts for carbon monoxide (CO) and volatile 

organic compound (VOC) reduction. Nonselective catalytic reduction is appropriate for 

rich burn engines only and therefore is not 

considered.

Install approximately 50 percent 

electric compression, where 

feasible.

The analysis considers 57 percent of the 

compression to be electric based on 

information on compression to be installed as 

provided by KMG.

Non-road Diesel 

Engines

Phase in Tier 2 drill rig engines (90

percent by 2010 and 100 percent 

by 2012).

1

The use of both Tier 2 and Tier 4 engines 

was considered in the near-field impact 

analysis. The far-field and regional analyses 

were specific to a project year past the 

implementation of Tier 4 engines. Therefore, 

the far-field analysis only considered the 

use of Tier 4 engines.

Dehydrators Install low-emission dehydration 

units.

Consistent with low emission dehydrators, 

venting emissions were not considered; 

however, combustion emissions from 

production heaters were included in the 

analysis.

Pneumatics Install low-bleed pneumatic

controllers on all new equipment.

The fugitive emission calculations consider lowbleed pneumatics. The projected future 

baseline emissions considered the 

replacement of existing pneumatic 

controllers with low-bleed pneumatics. 

Condensate Tanks Install controls on new condensate 

tanks with potential to emit VOC 

greater than 20 tons per year (tpy)

The analysis considers controls on tanks 

greater than 20 tpy VOC.

Completions Use “green completion” best 

management practices.

No VOC from completions and “green 

completions” assumed for greenhouse gas 

analysis.

1 The implementation of Tier 2 engine standards as specified in 40 Code of Federal Regulations (CFR) 89.112 supersedes this 

Applicant-committed Environmental Protection Measure.
1-4 March 2012

1.2 Overview of Modeling Approach

The focus of the air quality analysis was to assess local and regional air quality impacts from reasonably

foreseeable development in the Uinta Basin region, in conjunction with the proposed project. The study area 

covers large portions of eastern Utah and western Colorado, and is discussed in detail in Chapter 4.0. 

The general approach was to develop a sound emissions inventory for a project base year to tabulate 

emissions, conduct modeling for future year scenarios, and evaluate results from the proposed modeling tools. 

The modeling efforts included use of the CALPUFF modeling system to investigate impacts on visibility 

(regional haze), air quality, and acid deposition in areas that are 50 kilometers (km) or more from the GNBPA. 

The guideline air quality model AERMOD was used to evaluate impacts on air quality in the near field of the 

GNBPA. The Models-3 Community Multiscale Air Quality (CMAQ) model was used to evaluate impacts on 

ambient air ozone in the region. 

The emissions inventory used for the AERMOD and CALPUFF modeling focused on criteria pollutants using 

actual emissions for analysis of compliance with the NAAQS, for depicting visibility impacts (regional haze 

only), and sulfur and nitrogen deposition. Comparison of impacts to Prevention of Significant Deterioration 

(PSD) increment levels are provided, but the study did not include developing a PSD increment consuming 

inventory.1

 The inventory for the CMAQ ozone modeling considered project emissions in concert with 

emissions from other sources (i.e., electric generation, motor vehicles, biogenics, etc.).

The nature of proposed development was based on the KMG proposed project description. The analysis 

incorporated the planned development and a prepared set of emissions data for project modeling, to include 

project development alternatives and reasonably foreseeable development as discussed below. Those 

emissions data were incorporated into the modeling system developed for the project base year, and used to 

predict impacts on visibility, acid deposition, and air quality, including ozone. Critical impacts on resources 

evaluated were identified, and the major source or source groups that contribute to those impacts were 

characterized. 

Emissions data for 2006 were used as the basis for comparing emissions and impacts for the base year. This 

selection was appropriate primarily because of data availability for 2006 from the Western Regional Air 

Partnership (WRAP). WRAP used 2006 as the base year for their regional haze planning and put significant 

effort into preparing the meteorological simulation and emissions data that were necessary to carry out a 

detailed CMAQ simulation. 

1.2.1 Modeling Systems

1.2.1.1 CALPUFF Modeling

An air quality modeling analysis was being conducted for the current proposed study to assess potential 

impacts on ambient air quality and Air Quality-Related Values (AQRVs) in the modeling domain from existing 

and projected sources in the study area. The CALPUFF modeling system (Scire et al. 2000a,b) was 

promulgated on April 15, 2003, and is the United States (U.S.) Environmental Protection Agency’s (USEPA’s) 

preferred/recommended model for long-range transport and for complex winds at short-range distances. As 

appropriate, the modeling procedure follows recommendations in the Interagency Workgroup on Air Quality 

Modeling and Federal Land Managers’ (FLM) Air Quality Related Values Workgroup (FLAG) documents for 

the assessment of both near- and far-field impacts (USEPA 1998a; FLAG 2000). This analysis uses the 

current USEPA-approved version of the CALPUFF modeling suite (Version 5.8) to address the air quality 

impacts and AQRVs.

 

1 This analysis does not differentiate between increment-consuming and non-increment-consuming sources, and therefore, the model results cannot be used to 

demonstrate compliance with PSD increment consumption. However, the results of modeling are compared to applicable Class I or Class II increment levels.
1-5 March 2012

1.2.1.2 CMAQ Modeling

For more than a decade, USEPA has been developing the CMAQ modeling system with the overarching aim 

of producing a ‘One-Atmosphere’ air quality modeling system capable of addressing ozone, particulate matter 

(PM), visibility, and acid deposition within a common platform (Byun and Schere 2006; USEPA 1999). The

original justification for the Models-3 development emerged from the challenges posed by the 1990 Clean Air 

Act (CAA) Amendments and USEPA’s desire to develop an advanced modeling framework for ‘holistic’ 

environmental modeling utilizing state-of-science representations of atmospheric processes in a high 

performance computing environment. USEPA completed the initial stage of development with Models-3 and 

released CMAQ in mid-1999 as the initial operating science model under the Models-3 framework. The most

recent rendition is CMAQ Version 4.6, publicly released in October 2006. 

CMAQ consists of a core Chemical Transport Model (CTM) and several preprocessors including the 

Meteorological-Chemistry Interface Processor (MCIP), initial and boundary conditions processors (ICON and 

BCON), and a photolysis rates processor (JPROC). 

Byun and Schere (2006) described the newest features implemented in CMAQ Version 4.5. In addition to 

those mentioned above, others pertained to details in the model’s chemistry, transport, computer 

implementation, and model operation. This latest version of CMAQ was used to develop predictions of ground 

level ozone concentrations in the region. In accord with the nature of the ambient ozone standard, the annual 

fourth highest daily 8-hour concentrations were provided for comparison to air quality standards. The same 

grid area that was used for the CALPUFF modeling was used for CMAQ. 

1.2.1.3 AERMOD Modeling

AERMOD is a refined dispersion model for simple and complex terrain for receptors within 50 km of a modeled 

source. The AERMOD (USEPA 2004) model was adopted by USEPA in a final rule (Federal Register [FR]

November 9, 2005) and replaced the Industrial Source Complex (ISC) model. The rule became effective on 

December 9, 2005, and the ISC model was phased out as of December 9, 2006. The AERMOD model was 

developed by the American Meteorological Society/USEPA Regulatory Model Improvement Committee 

(AERMIC) work group and was intended to incorporate improved understanding of air dispersion calculations. 

The AERMOD modeling system consists of two preprocessors and the dispersion model. AERMET is the 

meteorological preprocessor component and AERMAP is the terrain preprocessor component that 

characterizes the terrain and generates receptor elevations along with critical hill heights for those receptors.

The promulgated version of AERMOD (Version 07026) was used for the near-field modeling for this study and 

was run with default model options. AERMOD was used to assess air quality impacts from project-related 

sources in the local area for comparison to applicable air quality standards and PSD Class II increments, but 

not as a regulatory evaluation. This near-field analysis focused on oil and gas development and operations, 

and did not directly address impacts from other major sources in the region because it focused on the 

project-only impacts. 

1.3 Development of Emissions Inventories and Pollutants of Interest

Emissions inventory scenarios were developed for the base year operating scenario and three forecast year 

scenarios that include reasonable foreseeable development, the proposed project, and maximum production. 

These four scenarios are identified as follows:

• 2006 Baseline – 2006 base year actual emissions;

• 2018 Projected Baseline – 2018 projected emissions without the proposed project;

• 2017 Proposed Action – 2018 Projected Baseline emissions with project emissions from the proposed 

development alternative in 2017; and

• 2026 Optimal Recovery Alternative – 2018 Projected Baseline emissions with project emissions from 

the maximum recovery development alternative in 2026. 
1-6 March 2012

The NEPA analysis also considers a Resource Protection Alternative, which focuses on minimizing land 

disturbance for the installation and operation of wells and other support facilities. From an air emissions 

perspective, ambient impacts from the Resource Protection Alternative are well-characterized by the impacts 

from the Proposed Action; therefore, the Resource Protection Alternative was not modeled as a separate 

evaluation. 

Air emissions inventories were developed from the WRAP emissions inventories and project-specific data 

provided by KMG. The WRAP inventories were compiled using data provided by state and tribal regulatory 

agencies, as well as industry partners, and include data for point, area, non-road mobile, and on-road mobile 

sources. All or portions of multiple WRAP inventories were used to develop emissions for the 2006 Baseline 

and 2018 Projected Baseline scenarios. These WRAP inventories include:

• 2002 Plan2d – original WRAP baseline inventory for all sources (used non oil and gas portion only);

• 2018 PRP18a – original WRAP forecasted inventory for non-road mobile and on-road mobile sources;

• 2018 PRP18b – updated WRAP forecasted inventory for point and area sources;

• 2002 Phase II – 2002 base year inventory for oil and gas sources only, updated to address visibility 

and regional haze (focus on oxides of nitrogen [NOX]);

• 2018 Phase II – 2018 forecasted inventory for oil and gas sources only, updated to address visibility 

and regional haze (focus on NOX);

• 2006 Draft Phase III – 2006 base year inventory for oil and gas sources only, updated to address 

ozone (focus on VOCs); and

• 2012 Draft Phase III – 2012 base year inventory for oil and gas sources only, updated to address 

ozone (focus on VOCs).

The 2006 Baseline and 2018 Projected Baseline scenarios primarily used the 2002 Plan2d, 2018 PRP18a, 

and 2018 PRP18b inventories for non oil and gas emissions only, supplemented with the Phase II and Draft 

Phase III inventories for oil and gas emissions as available. Emissions inventories of criteria pollutants and 

source characteristics for the 2017 Proposed Action and 2026 Optimal Recovery Alternative scenarios were 

based on project data provided by KMG. Sources were grouped as necessary to facilitate modeling and 

analysis. See Chapter 3.0 for greater detail regarding inventory development.

1.4 Assessment Approach

The outputs from the air quality modeling were used to assess potential impacts on near-field and far-field air 

quality and far-field AQRVs. Air quality impact assessments were conducted by making the following 

comparisons:

• Air quality impacts resulting only from the Proposed Action or Optimal Recovery Alternative alone

were compared to predicted impacts from the 2018 Projected Baseline. 

• Direct cumulative air quality impacts were compared to the applicable NAAQS and State Ambient Air 

Quality Standards (SAAQS) and applicable PSD increments (Class I or Class II, depending on 

receptor location). While the impacts were numerically compared to PSD increments for each 

emissions scenario to determine the change over time of the modeled impacts, there was no formal 

assessment of increment-consuming emissions or of expected increment consumption.

AQRVs evaluated included visibility and atmospheric deposition. Visibility impacts were assessed at the 

far-field receptors located in sensitive receptor areas using two different procedures.

1. The primary method for assessing regional haze impacts was based on USEPA’s Best Available 

Retrofit Technology (BART) guideline (also referred to as Method 6). This method also is used for 

tracking progress under the Regional Haze Rule (USEPA 2003a) and is similar to the FLAG 2010
1-7 March 2012

update (FLAG 2010). Method 6 results were presented as consistent with the BART guideline. That is, 

the 98th percentile (or eighth highest day per year) model results were presented in addition to the 

number of days of impacts above 1.0 change in deciviews (dv) and the maximum change in dv. Data 

for 0.5 change in dv were provided for information purposes only.

2. The second method was based on the FLAG guidance document (also referred to as Method 2). This 

method used an assumed natural background visibility reference level and visibility parameter 

equations recommended by FLAG (FLAG 2000). Under the FLAG method, estimated visibility 

degradation was compared to the established significance thresholds.

The FLAG recommended background values were used for both Method 2 and Method 6 assessments. 

Results of both analyses were reported. 

Atmospheric deposition impacts were assessed by comparing predicted net change in annual total 

atmospheric deposition fluxes to sensitive lakes in terms of acid neutralizing capacity (ANC), and with the 

threshold based on U.S. Forest Service (USFS)-recommended prediction methods (USFS 2000) and the total 

terrestrial deposition loading method in Fox et al. (1989).

Future 8-hour ozone impacts were estimated from the CMAQ modeling following the USEPA-recommended 

approach of using the photochemical grid model in a relative sense to scale observed 8-hour design values 

(USEPA 2007). The analysis focused on the fourth highest daily 8-hour reading using 1 year of meteorological 

data developed for modeling. Since there were no current complete monitoring data in or representative of the 

GNBPA, spatial depictions of the differences in future year ozone levels with and without the project emissions 

were provided. However, without concurrent meteorological data, emissions data, and monitored ozone levels 

that represent impacts in the area, it was impossible to assess the adequacy of the model simulations in the 

GNBPA. The focus of the ozone evaluation was on the projected change in ozone levels resulting from the 

Projected Baseline scenario compared to either the Proposed Action or Optimal Recovery Alternative.
2-1 March 2012

2.0 Study Area and Background for Air Quality Analyses

Air quality within the Uinta Basin has the potential to be affected by activities such as emissions from the 

construction and operation of oil and gas facilities, access roads, and other elements of the proposed project. 

Regional air quality also is affected by natural events such as windstorms and wildfires. These natural events 

generally are short lived, lasting from several hours to perhaps several days. The effects during the event may 

impact human health and the environment, and generally are considered part of the natural environment.

2.1 Regional Setting for Air Quality

Three important meteorological factors influence the dispersion of pollutants in the atmosphere: mixing height, 

atmospheric stability, and wind (speed and direction). Mixing height is the height above ground within which 

rising warm air from the surface will mix by convection and turbulence. Local atmospheric conditions, terrain 

configuration, and source location determine dilution of pollutants in this mixed layer.

The Uinta Basin in eastern Utah is part of a high, broad plateau area that is surrounded by higher terrain on 

virtually all sides, with rugged and rolling terrain features embedded in the plateau. The GNBPA extends along 

the White River Valley within Uintah County. South of that valley, the GNBPA extends over a large region that 

includes terrain with numerous creeks and washes that generally are north-south in orientation. Elevations 

range from about 4,700 feet above mean sea level along the White River to 5,500 feet along the benches and 

ridges in the southern part of the GNBPA. 

With a dry intermountain climate, the region usually has relatively clear days and nights with wide swings in 

daily temperature as well as a wide range of seasonal conditions from winter to summer. Table 2-1 provides a 

climatological summary for two sites that are located to the west (Ouray 4 NE) and east (Bonanza) of the 

GNBPA (Western Regional Climate Center 2007); therefore, representing conditions in the region. 

Precipitation is relatively light across the region (6.77 to 8.85 inches per year), but does occur throughout the 

year with no clearly defined dry or wet season. Summertime maximum temperatures reach into the 90s 

(degrees Fahrenheit [°F]) with winter lows near zero (°F).

Table 2-1 Period of Record Monthly Climate Summary

Ouray 4 NE, Utah (426568) – Period of Record: 6/1/1941 to 12/31/2007

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Average Max. Temperature (°F) 29.0 37.7 54.1 66.0 76.9 87.6 94.7 91.7 81.3 67.9 48.0 33.1 64.0 

Average Min. Temperature (°F) 2.4 10.0 23.7 33.5 42.5 50.2 56.1 54.0 43.9 32.5 20.5 7.9 31.4 

Average Total Precipitation (in.) 0.37 0.33 0.46 0.67 0.69 0.51 0.59 0.67 0.76 0.93 0.43 0.37 6.77 

Average Total Snowfall (in.) 4.4 2.7 1.5 0.6 0.0 0.0 0.0 0.0 0.0 0.4 1.6 4.0 15.1 

Average Snow Depth (in.) 3 2 0 0 0 0 0 0 0 0 0 1 1

Bonanza, Utah (420802) – Period of Record: 3/16/1938 to 2/25/1993

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Average Max. Temperature (°F) 30.7 37.3 50.1 63.4 73.9 85.0 92.5 89.7 80.8 66.2 48.1 35.5 62.8 

Average Min. Temperature (°F) 7.1 13.2 24.9 34.2 42.6 50.0 57.1 54.9 46.3 35.5 23.0 12.7 33.5 

Average Total Precipitation (in.) 0.59 0.42 0.66 0.83 0.93 0.76 0.72 0.91 0.91 1.12 0.49 0.50 8.85 

Average Total Snowfall (in.) 6.7 5.1 4.2 1.2 0.0 0.0 0.0 0.0 0.0 0.4 2.3 5.1 24.9 

Average Snow Depth (in.) 4 3 1 0 0 0 0 0 0 0 0 1 1

Representative wind data for climatological conditions are available from the National Climatic Data Center’s 

Integrated Surface Hourly data set for the airport monitoring station located at Vernal. This site is in relatively

open terrain and is not influenced by very local topographic features; therefore, the wind pattern at this location 

should be representative of surface conditions in the Uinta Basin region (Figure 2-1). As shown in the
2-2 March 2012

Figure 2-1 Wind Rose from Vernal, Utah, Airport
2-3 March 2012

Resource Management Plan and Final EIS for the BLM Vernal Field Office (BLM 2008a), wind patterns from 

specific Remote Air Weather Stations show some variability in prevailing wind directions. 

Figure 2-1 depicts the wind direction and wind speed measured at 10 m above ground level for a 5-year 

period including calendar year 2003 through calendar year 2007 for the airport site in Vernal, Utah. The pattern 

shows a distinctly prevailing wind from the west (at 10 m above ground level), while light winds can occur from 

any of the indicated directions. The pattern can be used to develop impacts associated with local sources, but 

each individual source would have a distinct impact pattern based on the indicated prevailing wind direction.

2.2 Recent Development in the Region

Other developmental projects are completed or underway in the Uinta Basin that must be considered in the 

cumulative impact analysis of the proposed project. These projects required air quality reviews and were 

included in the WRAP Phase III inventory, which was used to estimate future Projected Baseline emissions. 

Sections 3.1 and 3.2 provide a more detailed discussion of how the WRAP Phase III data is incorporated into 

this study.

2.3 Background Air Quality

Air quality in a given location is defined by pollutant concentrations in the atmosphere and generally is 

expressed in units of parts per million (ppm) or micrograms per cubic meter (μg/m3

). The existing air quality in 

the proposed development area is compliant with both the NAAQS and SAAQS or has insufficient data to 

establish compliance. Representative ambient background levels of pollutants measured in Uintah and Salt 

Lake counties, Utah, and Sweetwater County, Wyoming, are shown in Table 2-2. Data for this table were

obtained from the USEPA Air Quality System (AQS) website. 

Table 2-2 Background Ambient Air Quality Data

Averaging Concentration 1 Pollutant Period Ranking Year (μg/m3

) County State

Nitrogen Dioxide (NO2) 1-hour 98th Percentile 2009/2010 69.62 Uintah Utah

98th Percentile 2010/2011 52.72 Uintah Utah

98th Percentile 2009/2010 58.33 Uintah Utah

98th Percentile 2010/2011 60.23 Uintah Utah

AQIA4 Seasonal Diurnal

5 Uintah Utah

Annual H 2009/2010 9.02 Uintah Utah

H 2010/2011 6.82 Uintah Utah

H 2009/2010 7.83 Uintah Utah

H 2010/2011 8.13 Uintah Utah

AQIA 9.0 Uintah Utah

CO 1-hour H2H 2004 6,210 Salt Lake Utah

H2H 2005 6,325 Salt Lake Utah

H2H 2006 6,325 Salt Lake Utah

AQIA 6,325 Salt Lake Utah

8-hour H2H 2004 3,680 Salt Lake Utah

H2H 2005 3,910 Salt Lake Utah

H2H 2006 3,450 Salt Lake Utah

AQIA 3,910 Salt Lake Utah

Sulfur Dioxide (SO2)

6 1-hour 99th Percentile 2007 21.7 Sweetwater Wyoming

99th Percentile 2008 19.7 Sweetwater Wyoming

99th Percentile 2009 19.0 Sweetwater Wyoming

AQIA 21.7 Sweetwater Wyoming
2-4 March 2012

Table 2-2 Background Ambient Air Quality Data

Pollutant

Averaging 

Period Ranking1 Year

Concentration 

(μg/m3) County State

SO2

6 (Continued) 3-hour H2H 2007 16.0 Sweetwater Wyoming

H2H 2008 16.7 Sweetwater Wyoming

H2H 2009 10.1 Sweetwater Wyoming

AQIA 16.7 Sweetwater Wyoming

24-hour H2H 2007 5.9 Sweetwater Wyoming

H2H 2008 5.6 Sweetwater Wyoming

H2H 2009 3.9 Sweetwater Wyoming

AQIA 5.9 Sweetwater Wyoming

Annual H 2007 1.5 Sweetwater Wyoming

H 2008 1.5 Sweetwater Wyoming

H 2009 0.8 Sweetwater Wyoming

AQIA 1.5 Sweetwater Wyoming

PM with an aerodynamic diameter of 24-hour H2H 2004 14.0 Uintah Utah

10 microns or less (PM10) H2H 2005 18.0 Uintah Utah

H2H 2006 16.0 Uintah Utah

AQIA 18.0 Uintah Utah

Annual H 2004 5.0 Uintah Utah

H 2005 7.0 Uintah Utah

H 2006 7.0 Uintah Utah

AQIA 7.0 Uintah Utah

PM with an aerodynamic diameter of 24-hour 98th percentile 2009/2010 19.52 Uintah Utah

2.5 microns or less (PM2.5) 98th percentile 2010/2011 23.62 Uintah Utah

98th percentile 2009/2010 16.33 Uintah Utah

98th percentile 2010/2011 17.83 Uintah Utah

AQIA 21.67 Uintah Utah

Annual H 2009/2010 7.32 Uintah Utah

H 2010/2011 12.32 Uintah Utah

H 2009/2010 6.33 Uintah Utah

H 2010/2011 9.43 Uintah Utah

AQIA 12.3 Uintah Utah

Ozone 8-hour H4H 2009/2010 1172,8 Uintah Utah

H4H 2010/2011 1162,8 Uintah Utah

H4H 2009/2010 983,8 Uintah Utah

H4H 2010/2011 1003,8 Uintah Utah

AQIA N/A Uintah Utah

1 H = Highest value recorded; H2H = High Second High (second highest value from the highest receptor site); H4H = High Fourth High (fourth highest value 

from the highest receptor site). 2 Ouray Monitoring Station Data (USEPA AQS Database). 2009/2010 data period = 7/30/09 to 6/30/2010. 20010/2011 period = 7/1/2010 to 6/30/2011. 3 Redwash Monitoring Station Data (USEPA AQS Database). 2009/2010 data period = 7/30/09 to 6/30/2010. 20010/2011 period = 7/1/2010 to 6/30/2011. 4 AQIA = Air Quality Impact Assessment (representative of ambient background). The AQIA selected for each averaging period for a specific pollutant is the 

maximum ranked value from the period. 5 One-hour NO2 background for modeling was based on seasonal hour of day diurnal profiles. 6 Wamsutter Monitoring Station Data (USEPA AQS Database).

7 AQIA value for PM2.5 24-hour is 2-year average from the Ouray monitor. 8 Ozone is measured in parts per billion (ppb).
2-5 March 2012

The USEPA collected, and is still in the process of collecting, ozone and NO2 data at monitoring 

stations near Ouray and Redwash starting July 30, 2009. For this analysis, monitoring data through 

June 30, 2011, is being used, which constitutes essentially 2 years of data. These data show 

monitored 8-hour ambient concentrations of ozone that are above the 75 ppb NAAQS; however, 

compliance with the NAAQS for ozone is established by the 3-year average of the fourth highest daily 

8-hour maximum ozone reading. The data also indicate a seasonal variation in which the high values 

occur exclusively during the December to March winter period. As shown in Figure 2-2, the summer 8-

hour daily maximum values at either station do not exceed 75 ppb.

2.4 Standards and Evaluation

The CAA of 1970 (42 United States Code 7401) as amended in 1977 and 1990 is the basic federal statute 

governing air pollution. Provisions of the CAA that potentially are relevant to the GNBPA are listed and 

discussed below:

• NAAQS;

• PSD;

• Nonattainment New Source Review;

• Conformity Regulations;

• New Source Performance Standards; and

• National Emissions Standards for Hazardous Air Pollutants (NESHAP).

2.4.1 National Ambient Air Quality Standards

The federal CAA amendments of the 1990s require all states to control air pollution emissions sources so that 

NAAQS are met and maintained. The NAAQS establishes maximum acceptable concentrations for nitrogen 

(NO2/NOX), CO, SO2, PM10, PM2.5, ozone, and lead. Given the extremely low levels of lead emissions from 

project sources, the lead standards were not addressed in this analysis. These pollutants are known as criteria 

pollutants. The NAAQS are established by USEPA and are outlined in 40 CFR 50. These standards represent 

the maximum allowable atmospheric concentrations that may occur without jeopardizing public health and 

welfare, and include a reasonable margin of safety to protect the more sensitive individuals in a population. 

The NAAQS represent maximum acceptable concentrations that generally may not be exceeded more than 

once per year; the annual standards may never be exceeded. An area that does not meet the NAAQS is 

designated as a nonattainment area on a pollutant-by-pollutant basis. 

The USEPA announced a 1-hour NO2 NAAQS of 100 ppb (188 μg/m3) in the FR on January 22, 2010, 

which was finalized on February 9, 2010 (75 FR 6474-6537). Further, the USEPA announced a 1-hour 

SO2 NAAQS of 75 ppb (197 μg/m3) on June 2, 2010, which was finalized on June 22, 2010 (FR 35520-

35603). The NO2 and SO2 standards became effective on April 12 and August 23, 2010, respectively.

Compliance with the standard is attained for 1-hour NO2 when the 3-year average of the 98th percentile 

of the annual distribution of daily maximum 1-hour concentrations does not exceed the standard 

within an area. For 1-hour SO2, the standard is attained when the 3-year average of the 99th percentile 

of the annual distribution of daily maximum 1-hour concentrations does not exceed the standard 

within an area. The State of Utah has adopted the NAAQS as the SAAQS; however, Wyoming and 

Colorado have not incorporated these new standards into the State Implementation Plan. Applicable 

federal and state criteria are presented in Table 2-3.
2-6 March 2012

Figure 2-2 Ouray and Redwash Ozone Monitoring Data
2-7 March 2012

Table 2-3 Applicable Ambient Air Quality Standards

Averaging Ambient Air Quality Standards1

Pollutant Period National Wyoming Utah Colorado

NO2 (μg/m3) 1-hour2 188 --3 188 --3

Annual4 100 100 100 100

CO (μg/m3) 1-hour5 40,000 40,000 40,000 40,000

8-hour5 10,000 10,000 10,000 10,000

SO2 (μg/m3) 1-hour6 197 --3 197 --3

3-hour5,7 1,300 1,300 1,300 1,300

24-hour5,7 365 260 365 365

Annual4 80 60 80 80

PM10 (μg/m3) 24-hour8 150 150 150 150

Annual4 --9 50 50 50

PM2.5 (μg/m3) 24-hour10 35 35 35 35

Annual11 15 15 15 15

Ozone (ppb) 8-hour12 75 75 75 75

1 Sources: USEPA 2009, Wyoming Department of Environmental Quality 2008, Utah Division of Air Quality (UDAQ) 2010, and Colorado 

Department of Public Health and Environment 2007. 2 Three-year average of the 98th percentile of the daily maximum 1-hour average. 3 No state standard has been incorporated into the State Implementation Plan. 4 Never to be exceeded. 5 Not to be exceeded more than once per year. 6 Three-year average of the 99th percentile of daily maximum 1-hour average. 7 Secondary standard only. 8 Not to be exceeded more than once per year. 9 The annual PM10 NAAQS of 50 μg/m3 was revoked by USEPA on September 21, 2006. See FR Volume 71, Number 200, October 17, 2006. 10 Three-year average of the 98th percentile of 24-hour concentrations at each population-oriented monitor within an area must not exceed 

the standard. 11 Three-year average of the weighted annual mean concentrations from single or multiple community-oriented monitors must not exceed 

this standard. 12 Three-year average of the fourth highest daily maximum 8-hour average measured at each monitor within an area over each year must 

not exceed this standard.

2.4.2 Prevention of Significant Deterioration

PSD regulations restrict the degree of ambient air quality deterioration allowed and apply to proposed new or 

modified major stationary sources located in an attainment area that have the potential to emit criteria 

pollutants in excess of predetermined de minimis values (40 CFR 51). Increments for criteria pollutants are 

based on the PSD classification of the area. Class I area status is assigned to federally protected wilderness 

areas and allows the lowest amount of permissible deterioration. This designation essentially precludes 

development near these areas. Class II areas are designed to allow for moderate, controlled growth, and 

Class III areas allow for heavy industrial use.

As defined in 40 CFR 51, a source is considered a major stationary source if it:

• Can be classified in one of 28 named source categories listed in Section 169 of the CAA and it emits 

or has the potential to emit 100 tpy of any pollutant regulated by the Act; or

• Is any other stationary source that emits or has the potential to emit 250 tpy or more of any pollutants 

regulated by the CAA (USEPA 1990).

Compressor stations and other upstream oil and gas sources are not listed as one of the 28 named source 

types in Section 169 of the Act; therefore, 250 tpy is the threshold for major source status.
2-8 March 2012

Federal PSD Class I areas, which include certain national wilderness areas, national memorial parks, and 

national parks, are afforded the highest level of protection. Ambient air criteria that apply within Class I areas 

are more stringent than those that apply to other areas. In addition to more stringent ambient air increments, 

Class I areas also are protected by the regulation of AQRVs within their borders. FLMs are responsible for the 

management of PSD Class I areas. Table 2-4 provides a list of federal Class I and sensitive Class II areas 

considered in this analysis.

Table 2-4 Class I and Sensitive Class II Areas of Concern for Air Quality Impact Analysis

National Park Service (NPS) Class I Areas

Arches National Park

Black Canyon of the Gunnison National Park

Canyonlands National Park

Capitol Reef National Park

Mesa Verde National Park

USFS Class I Areas

Eagles Nest Wilderness Area

Flat Tops Wilderness Area

La Garita Wilderness Area

Maroon Bells-Snowmass Wilderness Area

Mount Zirkel Wilderness Area

Weminuche Wilderness Area

West Elk Wilderness Area

NPS Class II Areas

Colorado National Monument

Dinosaur National Monument

USFS Class II Areas

Flaming Gorge National Recreation Area

High Uintah Wilderness Area

Holy Cross Wilderness Area

Hunter/Frying Pan Wilderness Area

Raggeds Wilderness Area

U.S. Fish and Wildlife Service Class II Areas

Browns Park National Wildlife Refuge

Allowable deterioration to air quality can be expressed as the incremental increase to ambient concentration of 

criteria pollutants, or PSD increment. Modeled air concentration of NO2, SO2, and PM10 predicted at near-field 

receptors that result from project emissions were compared to the threshold of allowable PSD increments. This 

comparison to PSD Class II increments did not represent a regulatory PSD increment consumption analysis 

because the focus of this study was the Proposed Action and alternatives under NEPA, not incrementaffecting sources that were not relevant under NEPA. The allowable PSD increments for Class II areas also 

are given in Table 2-5. 

Table 2-5 PSD Increments for Class I and Class II Areas

3 Allowable Increment (μg/m )

PSD Class Pollutant Annual Arithmetic Mean 24-hour Maximum 3-hour Maximum

Class I NO2 2.5 - -

SO2 2 5 25

PM10 4 8 -
2-9 March 2012

Table 2-5 PSD Increments for Class I and Class II Areas

3 Allowable Increment (μg/m )

PSD Class Pollutant Annual Arithmetic Mean 24-hour Maximum 3-hour Maximum

Class II NO2 25 - -

SO2 20 91 512

PM10 17 30 -

On June 3, 2010, the USEPA issued the final rule that “tailors” the applicability of PSD requiring 

USEPA and/or permitting authorities to implement PSD permitting requirements for greenhouse gases 

(GHGs) (75 FR 31514). The “Tailoring Rule” takes effect on January 21, 2011, for new or modified 

sources that have the potential to emit (PTE) or net increase in emissions more than 75,000 tpy of 

carbon dioxide (CO2) equivalents (CO2e) and would be considered major for other PSD pollutants. On 

or after July 1, 2011, this rule will apply to any new source with the PTE of 100,000 tpy CO2e and 

exceeds the major source threshold of any GHG on a mass basis regardless of the PTE of other PSD 

pollutants. Further, modification at an existing major source that results in a net emissions increase of 

75,000 tpy CO2e also will be reviewed under the PSD rules.

2.4.3 Nonattainment New Source Review

Nonattainment New Source Review is required for major stationary sources locating or expanding in 

nonattainment areas. The areas potentially impacted by the proposed project are currently in attainment for all 

criteria pollutants; therefore, this review would not apply.

2.4.4 Conformity for General Federal Actions

According to Section 176(c) of the CAA (40 CFR 51.853), a federal agency must make a conformity 

determination in the approval of a project having air emissions that exceed specified thresholds in 

nonattainment and/or maintenance areas. The proposed project does not pass through a nonattainment or 

maintenance area; therefore, a general conformity analysis would not apply to the proposed or alternative 

actions.

2.4.5 New Source Performance Standards

The regulation of new sources, through the development of standards applicable to a specific category of 

sources, was a significant step taken by the CAA (PL 91-604). The USEPA was to publish a proposed 

regulation establishing a standard of performance for any new source that fell into any category. The 

significant feature of the law is that it applies to all new, modified, or reconstructed sources within a given 

category, regardless of geographic location or the existing ambient air quality. The standards defined emission 

limitations that would be applicable to a particular source group. The New Source Performance Standards 

potentially applicable to the project include the following subparts of 40 CFR Part 60:

• Subpart A – General Provisions;

• Subpart Kb – Standards of Performance for Volatile Organic Storage Vessels;

• Subpart KKK – Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas 

Processing Plants;

• Subpart LLL – Standards of Performance for Onshore Natural Gas Processing: SO2 Emissions;

• Subpart JJJJ – Standards of Performance for Stationary Spark-Ignition Internal Combustion Engines; 

and

• Subpart KKKK – Standards of Performance for Stationary Combustion Turbines.
2-10 March 2012

2.4.5.1 Subpart A – General Provisions

Certain provisions of Subpart A apply to the owner or operator of any stationary source subject to a New 

Source Performance Standard. Provisions of Subpart A potentially could apply depending on the applicability 

of other subparts of 40 CFR Part 60.

2.4.5.2 Subpart Kb – Volatile Organic Liquid Storage Vessels

Subpart Kb is applicable to storage vessels containing volatile organic liquids with a capacity greater than 

75 m3 (approximately 19,800 gallons). This subpart potentially would be applicable to storage tanks for natural 

gas liquids and pipeline liquids tanks located at pump or meter stations.

2.4.5.3 Subpart KKK – Equipment Leaks from Onshore Natural Gas Processing Plants

Subpart KKK dictates emissions standards, operating procedures, and work practice standards to control 

emissions of VOC from leaks in equipment during handling of gas or natural gas liquids at onshore processing 

plants. The provisions of Subpart KKK apply to all equipment at an onshore natural gas processing plant 

handling VOC or wet gas that is constructed, modified, or reconstructed on or after January 20, 1984. This 

includes all compressor stations, dehydration units, sweetening units, underground storage tanks, field gas 

gathering systems, or liquefied natural gas handling located at the processing plant, but excludes any of these 

activities conducted at field sites. The scope of the proposed project does not include natural gas processing 

plants, so the provisions of the Subpart would not apply.

2.4.5.4 Subpart LLL – SO2 Emissions from Onshore Natural Gas Processing

Subpart LLL provides emissions standards, operating procedures, and work practice standards to control 

emissions of SO2 from sweetening units, including those followed by a sulfur recovery unit that is constructed, 

modified, or reconstructed after January 20, 1984. Facilities processing less than 2 metric tons/day are 

required to comply only with 40 CFR 60.647(c). The proposed project may include sweetening units at a major 

stationary source to which this Subpart may apply.

2.4.5.5 Subpart JJJJ – Stationary Spark-ignition Internal Combustion Engines

On January 18, 2008, USEPA published in the Federal Register the finalized rule for NOX, CO, and 

non-methane hydrocarbons from certain new stationary spark-ignited internal combustion (IC) engines that 

commence construction, modification, or reconstruction after the date the particular standard for a specified 

engine is identified. For the purposes of this Subpart, the date that construction commences is the date that 

the engine is ordered by the owner or operator. The requirements of this Subpart apply to owners or operators 

of stationary spark-ignition IC engines that commence construction after June 12, 2006, where IC engines 

greater than or equal to 500 hp are manufactured on or after July 1, 2007, and where emergency generator 

engines are manufactured on or after January 1, 2009.

2.4.5.6 Subpart KKKK – Stationary Combustion Turbines

On February 18, 2005, USEPA published proposed rules in the Federal Register for NOX and SO2 from new 

stationary combustion turbines larger than 1 megawatt that commence construction, modification, or 

reconstruction after February 18, 2005. The preamble to the proposed rule states that new stationary 

combustion turbines subject to the proposed standards are exempt from the requirements of the 40 CFR 60 

Subpart GG. Combustion turbines that operate in emergency situations are exempt from the regulations. 

USEPA promulgated the new construction turbine Subpart KKKK rule on July 6, 2006.
2-11 March 2012

2.4.6 National Emission Standards for Hazardous Air Pollutants

Under the NESHAP, USEPA promulgated Maximum Achievable Control Technology (MACT) standards 

pursuant to Section 112 of the 1990 CAA Amendments, and those rules are provided in 40 CFR 63. The 

MACT standards potentially applicable to the proposed project include:

• Subpart A – General Provisions;

• Subpart HH – Oil and Natural Gas Production Facilities;

• Subpart YYYY – Stationary Combustion Turbines; and

• Subpart ZZZZ – Stationary Reciprocating Internal Combustion Engines.

2.4.6.1 Subpart A – General Provisions

The general provisions for all sources affected by a MACT standard are promulgated under Subpart A. Each 

of the promulgated standards contains a detailed list of Subpart A provisions that are applicable to the affected 

facility. The critical sections of Subpart A are summarized in 40 CFR 63.6, specifically including 40 CFR 

63.6(e), which provides operation and maintenance requirements.

2.4.6.2 Subpart HH – Oil and Natural Gas Production Facilities

In the January 3, 2007, Federal Register, the USEPA promulgated a rule to amend 40 CFR 63 Subpart HH to 

include area sources rather than just major sources of HAPs. An affected source under this final rule is each 

tri-ethylene glycol dehydration unit located at an area source oil and natural gas production facility.

2.4.6.3 Subpart YYYY – Stationary Combustion Turbines

USEPA published this final stationary combustion turbine MACT in the Federal Register on March 5, 2004. 

New lean premix and diffusion flame gas- and oil-fired turbines at major HAP facilities are required to limit 

formaldehyde emissions to 91 ppb volume dry at 15 percent oxygen. On April 7, 2004, USEPA published two 

proposed rules affecting natural gas-fired lean premix combustion turbines and three other subcategories. On 

August 18, 2004, USEPA issued a final rule to stay the effectiveness for two categories of stationary 

combustion turbines: lean pre-mix gas-fired turbines and diffusion flame gas-fired turbines.

2.4.6.4 Subpart ZZZZ – Stationary Reciprocating Internal Combustion Engines

On January 18, 2008, the USEPA published finalized rules in the Federal Register to amend 40 CFR 63 

Subpart ZZZZ. An affected source under this amended Subpart is any existing, new, or reconstructed 

stationary reciprocating internal combustion engine with a site-rating of more than 25 brake hp (bhp), located 

at either a major source or area source of HAP.

On August 20, 2010, the USEPA published further revisions to this rule (71 FR 51570 et. seq) to 

address emissions from existing stationary spark-ignition (SI) engines less than or equal to 500 hp at 

major sources and all existing stationary SI engines located at area sources.

2.5 Carbon Dioxide and Other Greenhouse Gases

In Massachusetts v. EPA, the U.S. Supreme Court (April 7, 2007) held that CO2 satisfies the definition of “air 

pollutant” and that USEPA has authority to regulate emissions of CO2 and other GHG from new motor vehicles 

under the CAA. The Supreme Court remanded the case to USEPA to determine whether such motor vehicle 

emissions contribute to global climate change, and thereby endanger public health or welfare. The ruling, 

however, did not require the USEPA to create any emission control standards or ambient air quality standards 

for GHG. 

CO2 and other GHG are naturally occurring gases in the atmosphere whose status as a pollutant is not related 

to their toxicity, but to the added long-term impacts they may have on climate because of their increased 
2-12 March 2012

incremental levels in the earth’s atmosphere. Because they are non-toxic and non-hazardous at normal 

ambient concentrations, CO2 and other naturally occurring GHG are, therefore, not regulated under the major 

environmental regulatory programs that primarily address toxic and hazardous substances.

On October 30, 2009, the USEPA promulgated the final mandatory reporting rule for GHGs under 

40 CFR Part 98, which requires a wide range of sources to record and report selected GHG emissions 

including CO2, methane (CH4), nitrous oxide (N2O), and some halogenated compounds. A CO2e value 

is calculated for combined emissions of these gases based on their comparative global warming 

potential. This rule applies to sources that emit 25,000 tpy or more CO2e. Further, the USEPA issued 

the final reporting GHG requirements for petroleum and natural gas production on November 30, 2010 

(40 CFR Part 98 Subpart W) (75 FR 74458). The rule specifically identifies monitoring and reporting 

requirements for natural gas systems including combustion units (Subpart C) as well as on-shore gas 

production, storage, processing, and transmission (Subpart W).

The rule does not require any controls or establish any emission limits related to GHG emissions. Therefore, 

there is no requirement at this time that would affect development of the proposed project under this rule, 

other than the requirement for the operator to develop a monitoring plan and maintain recordkeeping, 

and reporting of GHG emissions. Chapter 6.0 provides a detailed GHG emission calculation for the Proposed 

Action and Optimal Recovery Alternative.
3-1 March 2012

3.0 Emissions Data

This chapter provides a detailed discussion of the air emissions inventories for the base year and each project 

alternative. The four emissions inventories developed and analyzed for this study include the:

• 2006 Baseline – 2006 base year actual emissions;

• 2018 Projected Baseline – 2018 projected emissions without the proposed project;

• 2017 Proposed Action – 2018 Projected Baseline emissions with project emissions from the proposed 

development alternative in 2017; and

• 2026 Optimal Recovery Alternative – 2018 Projected Baseline emissions with project emissions from 

the maximum recovery development alternative in 2026. 

The 2006 inventory was developed from the WRAP Phase III inventories for model validation and as the 

foundation of projected baseline development. This inventory represented existing conditions for that year 

only. To create the 2018 Projected Baseline inventory, the 2006 inventory was extrapolated as described in 

Section 3.1 to include emissions increases that include ongoing and approved projects as well as reasonably

foreseeable future development. This Projected Baseline was incorporated into the cumulative analysis for the 

Proposed Action and the Optimal Recovery Alternative.

Development of project alternatives would include additional activities that must be added to the Projected 

Baseline inventory. These activities included drilling, completion, compression, and production-related

activities. Analysis of the project alternatives included quantification of criteria air pollutants and selected 

HAPs. Benzene, toluene, ethylbenzene, xylenes, formaldehyde, and n-hexane were selected for 

quantification. Of the 187 HAPs regulated under Section 112 of the CAA, these 6 have the greatest

contribution, while emissions factors of the remaining HAPs are negligible.

Emissions for each activity were developed on a per unit basis and were based on approved emissions 

factors, mass balance, or process simulation where appropriate. Supporting information such as operation 

schedules, equipment specification, and physical and chemical properties of fuel and materials were provided 

by KMG where available. Where site-specific information was not available, the analysis used published 

references or assumptions based on professional experience. A detailed discussion of these parameters 

appears in Sections 3.3 through 3.6 in the relevant sections for each activity.

Emissions for the project alternatives were tabulated based on the intensity of each activity as identified in the 

project description for each alternative. Criteria pollutant emissions were allocated by township, range, and 

section to generate a spatial distribution of emissions for modeling. This is described in detail in Section 3.7. 

These emissions comprised the air emissions inventory for the Proposed Action for cumulative analysis of 

ambient air quality and AQRV impacts as described in Chapter 5.0.

3.1 Current and Projected Baseline Emissions Input Procedures

The baseline emissions inventories utilized for this study were based on several sources. The ozone modeling 

required CMAQ-ready emissions estimates for 2006 and an additional future modeling year. The year 2018 

was selected as the future baseline year modeling inventory because it coincided with the WRAP inventory 

and was representative of the year 2017 when the GNB field development is projected to reach the maximum 

emissions associated with the Proposed Action.

As discussed in Section 1.3, the WRAP inventories maintain the oil- and gas-related emissions as separate 

source categories. The 2006 Baseline CMAQ-ready emissions were developed from the WRAP 2002 Plan2d 

and 2018 PRP18a inventories using the same methodology as followed by the Uinta Basin Air Quality Study 

(UBAQS) (ENVIRON 2009). For the 2006 Baseline, the draft 2006 WRAP Phase III oil and gas emissions for 
Table 3-1 Summary of Baseline Inventory Development

Emissions Source Category Inventory Used for 2006 Baseline

Inventory Used for 2018 Projected 

Baseline

Oil and Gas – Uinta Basin WRAP Oil and Gas Phase III 2006 Projected from WRAP Phase III Oil and 

Gas 2006 based on projected 

cumulative activity in 2018

Oil and Gas – Piceance Basin WRAP Oil and Gas Phase III 2006 Projected from WRAP Phase III Oil and 

Gas 2006 and 2012

Oil and Gas – All Other Basins Interpolated from WRAP Phase II Oil and 

Gas 2002 and 20181

WRAP Oil and Gas Phase II 2018

Point Sources – Non Oil and Gas Interpolated from WRAP 2002 Plan2d and 

WRAP 2018 PRP18a1

WRAP 2018 PRP18b 

Area Sources – Non Oil and Gas Interpolated from WRAP 2002 Plan2d and 

WRAP 2018 PRP18a1

WRAP 2018 PRP18b

Non-Road Motor Vehicle Interpolated from WRAP 2002 Plan2d and 

WRAP 2018 PRP18a1

WRAP 2018 PRP18a

On-Road Motor Vehicle Calculated with 2005/2006 meteorology and 

2006 VMT interpolated from WRAP 2002 

Plan2d and WRAP 2018 PRP18a VMT1

Calculated with 2005/2006 Meteorology 

and WRAP 2018 PRP18a VMT

Biogenic Model of Emissions of Gases and Aerosols 

from Nature (MEGAN) with 2005/2006 

meteorology

MEGAN with 2005/2006 meteorology 

(held steady from 2005/2006)

3-2 March 2012

the Piceance and Uinta basins were used. For the area, non-road and non-Continuous Emission Monitor 

(CEM) point source emissions, the 2006 emission rates were directly interpolated from the 2002 and 2018 

values. The 2006 on-road motor vehicle emissions were calculated using VMT values interpolated from the 

2002 and 2018 VMT totals combined with mobile source emissions factors and meteorological data specific for 

the 2006 episodes. Day-specific emissions for the 2006 episodes were obtained for the CEM point sources 

and fire emissions and were calculated for the biogenic emissions.

The 2018 future year emissions estimates were based mainly on the WRAP 2018 PRP18a and PRP18b 

inventories. For non oil and gas related sources, the predicted emissions for the 2018 forecast year for 

non-road and on-road mobile sources were directly from the WRAP 2018 PRP18a inventory. The WRAP 2018

PRP18b inventory update was incorporated for area sources and point sources. Fire and biogenic source 

categories were maintained at 2006 levels, which is consistent with the WRAP Phase II 2018 PRP18a 

development approach.

In the Uinta basin, the 2018 oil and gas emissions were projected based on predicted growth in key operating 

activity parameters by county from 2006 to 2018. These growth rates were applied to specific oil and gas 

sources by Source Classification Codes (SCC) and control efficiencies were applied for control measures 

being adopted by operators under federal rule or consent decree. This is discussed in detail in Section 3.1.1.

In the Piceance Basin, the 2018 oil and gas emissions were estimated by developing a growth rate from the 

2006 and 2012 WRAP III estimates for the basin, applying the growth rates by county and SCC code, and then 

accounting for control measures being adopted in Colorado. For oil and gas emissions in areas outside of the 

Uinta and Piceance basins, the 2018 WRAP Phase II oil and gas emissions were used directly. Note that the 

growth of oil and gas development is uncertain and highly dependent on economic and market factors. The 

emission source categories and the development of these baseline inventories for 2006 and 2018 are

summarized in Table 3-1. 
3-3 March 2012

Table 3-1 Summary of Baseline Inventory Development

Emissions Source Category Inventory Used for 2006 Baseline

Inventory Used for 2018 Projected 

Baseline

Wildfire 2006 Wildfire Inventory 2006 Wildfire Inventory (held steady 

from 2006)

1 Same as used for the 2006 UBAQS emission inventory (ENVIRON 2009).

To address project-related impacts, the 2018 baseline emissions inventories were supplemented with local oil

and gas-related emissions data for each of the two action alternatives analyzed. The oil and gas-related 

emissions data were converted into Sparse Matrix Operator Kernel Emissions (SMOKE)-ready input files, and 

maintained as an individual processing stream to allow easy update of the oil and gas emissions data, detailed 

quality assurance, and reporting. 

3.1.1 Development of Uinta Basin 2018 Projected Baseline Emissions

The 2018 projected baseline was estimated based on the growth of five operating parameters in each of the 

five counties within the Uinta Basin. The level of each of these parameters was based on the reasonably 

foreseeable future development demonstrated by pending or proposed projects filed with the BLM. These 

projects and associated well counts are summarized in Table 3-2. These parameters included:

• Total well count – total number of operating wells for all operators in each county;

• Spud count – number of wells drilled by all operators in each county;

• Total gas production – total gas produced by all operators in each county;

• Total condensate production – total condensate produced by all operators in each county; and

• Total oil production – total oil produced by all operators in each county.

Table 3-2 Summary of New Well Development for Proposed Projects in the Uinta Basin

Total Natural Natural Gas Wells per County by 2018

Proposed Project Gas Wells Wells by 2018 Uintah Duchesne Carbon

BBC West Tavaputs Plateau EIS 807 807 20 23 764

Berry Petroleum ANF South Unit EIS 400 140 -- 140 --

Enduring Resources Big Pack 

Environmental Assessment (EA)

664 490 490 -- --

Enduring Resources Southam Canyon EA 249 225 225 -- --

EOG Greater Chapita Wells EIS 7,028 3,752 3,752 -- --

EOG North Alger EA 44 44 44 -- --

Gasco Uinta Basin EIS 1,538 900 301 599 --

Newfield Monument Butte EIS 2,500 700 272 428 --

XTO Hill Creek Unit EA 144 144 144 -- --

XTO Little Canyon EA 510 510 510 -- --

XTO River Bend Unit Infill EA 484 484 484 -- --

In reviewing proposed projects, no reasonably foreseeable future development was anticipated for Grand or 

Emery counties; therefore, these counties were maintained at their 2006 uncontrolled emissions levels for the 

purposes of this analysis.
3-4 March 2012

Uncontrolled emissions of criteria pollutants for 2018 were calculated for each source category as the product 

of the 2006 emissions and the ratio of 2018 predicted activity level to the historic 2006 level for that parameter. 

The list of the source categories and the relevant activity parameter are summarized in Table 3-3. A control 

efficiency was applied to the predicted uncontrolled emissions for certain source categories based on 

implementation of more stringent federal emission standards or installation of additional controls required by 

consent decree. Determination of these control efficiencies is discussed in detail in Section 3.1.1.7.

Table 3-3 Activity Parameters Used for Emissions Scaling by Source Category Code

SCC Description Scaling Parameter

2310000100 Heaters Total well count

2310000220 Drill rigs Spud count

2310000230 Workover rigs Total well count

2310000300 Pneumatic devices Total well count

2310000330 Artificial lift Total oil production

2310000700 Unpermitted fugitives Total well count

2310000800 Truck loading of condensate Total condensate production

2310000801 Truck loading of oil Total oil production

2310000820 Gas plant truck loading Total condensate production

2310001610 Venting - initial completions Spud count

2310001611 Initial completion flaring Spud count

2310001620 Venting - recompletions Spud count

2310001630 Venting - blowdowns Total gas production

2310001640 Venting - compressor startup Total gas production

2310001650 Venting - compressor shutdown Total gas production

2310002230 Condensate tank Total condensate production

2310002231 Condensate tank flaring Total condensate production

2310002240 Oil tank Total oil production

2310003100 Miscellaneous engines Total well count

2310003200 Pneumatic pumps Total well count

2310020600 Compressor engines Total gas production

2310021410 Dehydrator Total gas production

2310021411 Dehydrator flaring Total gas production

3.1.1.1 Development of Total Well Counts

Additional conventional well counts were taken from the proposed projects listed in Table 3-2 and were 

spatially allocated to each county on an annual basis based on the fraction of the project area in each county 

and the estimated start date, drilling rate, and schedule. This information was taken from pending EA or EIS 

documents for each project and was accumulated with recorded total well counts for each county for 2009 

from the IHS, Inc. Exploration and Production Information database. Although development of many projects 

will continue beyond 2018, for the purposes of this study, a summary of the incremental and cumulative well 

counts from 2008 to 2018 is provided in Table 3-4.
3-5 March 2012

Table 3-4 Projected Total New and Cumulative Well Count by Year and County

Project/Activity

Year

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Uintah County

Existing Wells (Conventional and Coal 

Bed Methane [CBM])

5,103 -- -- -- -- -- -- -- -- -- --

Remaining Ongoing and Approved -- 192 192 192 192 94 -- -- -- -- --

BBC West Tavaputs Plateau EIS -- -- 4 3 3 2 2 2 2 2 --

Enduring Resources Big Pack EA -- -- 70 70 50 50 50 50 50 50 50

Enduring Resources Southam Canyon EA -- -- 25 25 25 25 25 25 25 25 25

EOG Greater Chapita Wells EIS -- -- -- 469 469 469 469 469 469 469 469

EOG North Alger EA -- -- 10 10 10 10 4 -- -- -- --

Gasco Uinta Basin EIS -- -- 34 34 34 34 33 33 33 33 33

Newfield Monument Butte EIS -- -- -- -- 39 39 39 39 39 39 38

XTO Hill Creek Unit EA -- -- 17 17 24 24 24 24 14 -- --

XTO Little Canyon EA -- -- 60 60 60 60 60 60 60 60 30

XTO River Bend Unit Infill EA -- -- 46 60 93 57 66 64 61 37 --

New Wells Per Year -- 192 458 940 999 864 772 766 753 715 645

Cumulative Total 5,103 5,295 5,753 6,693 7,692 8,556 9,328 10,094 10,847 11,562 12,207

Duchesne County

Existing Wells (Conventional and CBM) 1,791 -- -- -- -- -- -- -- -- -- --

Remaining Ongoing and Approved -- -- -- -- -- -- -- -- -- -- --

BBC West Tavaputs Plateau EIS -- -- 5 4 3 3 2 2 2 2 --

Berry Petroleum ANF South Unit EIS -- -- -- -- 20 20 20 20 20 20 20

Gasco Uinta Basin EIS -- -- 66 66 66 66 67 67 67 67 67

Newfield Monument Butte EIS -- -- -- -- 61 61 61 61 61 61 62

New Wells Per Year -- 0 71 70 150 150 150 150 150 150 149

Cumulative Total 1,791 1,791 1,932 1,932 2,082 2,232 2,382 2,532 2,682 2,832 2,981

Carbon County

Existing Wells (Conventional and CBM) 851 -- -- -- -- -- -- -- -- -- --

Remaining Ongoing and Approved -- -- -- -- -- -- -- -- -- -- --

BBC West Tavaputs Plateau EIS -- -- 159 120 114 76 76 76 76 67 --

New Wells Per Year -- 0 159 120 114 76 76 76 76 67 0

Cumulative Total 851 851 1,010 1,130 1,244 1,320 1,396 1,472 1,548 1,615 1,615

3.1.1.2 Development of Projected Spud Counts

Spud counts were estimated based on the change in total wells (conventional and CBM) from 2017 to 2018 in 

each county. An additional 5 percent spud to well rate was assumed to account for unsuccessful holes and 

ancillary drilling activities including monitoring and injection wells. Table 3-5 summarizes the estimated spud 

rate for each county.
3-6 March 2012

Table 3-5 Project Spud Count for 2018 by County

County

Total Completed Wells

Spud/Well Ratio

Spud Count

2017 2018 Change 2018

Uintah 11,562 12,207 645

1.05

677

Carbon 1,615 1,615 0 0

Duchesne 2,832 2,981 149 156

3.1.1.3 Development of Projected Total Gas Production

Gas production in 2018 from each county was predicted using a county-specific estimated well production 

decline over time as shown for each county in Tables 3-6, 3-7, and 3-8. The number of wells at each given

age was estimated as the number of new wells in each year based on data shown in Table 3-4 and historical 

data. Gas production in each year is the product of the number of new wells and the assigned gas production 

rate for a well of that age; the total 2018 gas production is the sum of these products. New well production 

must account for wells that begin production throughout the year and the “average” would be one-half of the 

calculated new well production rate. Therefore, only one-half of the production rate is considered due to well 

completion and shakedown for year 2018.

Table 3-6 Projected 2018 Gas and Condensate Production for Uintah County

Conventional Wells Gas Production Condensate Production

Year Age Installed1 (MMscf2/well-yr) (MMscf/yr) (bbl3/well-yr) (bbl/yr)

2018 1 645 215.0 69,346 3,242.3 1,045.6 

2017 2 715 106.0 75,780 1,448.5 1,035.7 

2016 3 753 80.8 60,846 1,007.0 758.3 

2015 4 766 67.7 51,872 770.1 589.9 

2014 5 772 59.4 45,828 616.0 475.5 

2013 6 864 53.4 46,173 506.1 437.3 

2012 7 999 49.0 48,914 423.3 422.9 

2011 8 940 45.4 42,700 358.8 337.2 

2010 9 458 43.0 19,692 309.8 141.9 

2009 10 192 40.7 7,820 268.2 51.5 

2008 11 648 38.3 24,809 30.1 149.1 

2007 12 420 36.0 15,115 97.3 82.9 

2006 13 577 33.8 19,519 169.2 97.6 

2005 14 431 31.8 13,705 145.3 62.6 

2004 15 349 29.9 10,432 125.0 43.6 

2003 16 236 28.1 6,631 107.3 25.3 

2002 17 209 26.4 5,520 91.6 19.2 

2001 18 280 24.8 6,952 78.6 22.0 

2000 19 219 23.3 5,111 67.7 14.8 

1999 20 95 21.9 2,084 57.8 5.5 

1998 21 140 20.6 2,887 50.0 7.0 

1997 22 70 19.4 1,357 42.7 3.0 

1996 23 15 18.2 273 36.4 0.5 

1995 24 60 17.1 1,028 31.2 1.9 

1994 25 17 16.1 274 27.1 0.5 

1993 26 140 15.1 2,119 23.4 3.3 

1992 27 85 14.2 1,209 19.8 1.7 

1991 28 93 13.4 1,244 17.2 1.6 

1990 29 6 12.6 75 14.6 0.1 
3-7 March 2012

Table 3-6 Projected 2018 Gas and Condensate Production for Uintah County

Conventional Wells Gas Production Condensate Production

Year Age Installed1 (MMscf2/well-yr) (MMscf/yr) (bbl3/well-yr) (bbl/yr)

1989 30 9 11.8 106 12.5 0.1 

1988 31 8 11.1 89 10.9 0.1 

1987 32 -41 10.4 0 9.4 0.0

1986 33 -15 9.8 0 7.8 0.0

1985 34 102 9.2 941 6.8 0.7 

1984 35 394 8.7 3,417 5.7 2.3 

1983 36 70 8.2 571 5.2 0.4 

1982 37 115 7.7 881 4.2 0.5 

1981 38 135 2.5 331 1.0 0.1

Total Production by 2018 595,651 5,842

1 Negative values are based on records of wells shut down.

2 MMscf = million standard cubic feet.

3 bbl = barrel.

Table 3-7 Projected 2018 Gas and Condensate Production for Duchesne County

Conventional Wells Gas Production Condensate Production

Year Age Installed1 (MMscf/well-yr) (MMscf/yr) (bbl/well-yr) (bbl/yr)

2018 1 149 70.3 5,240 1,263.5 94.1

2017 2 150 34.7 5,201 564.5 84.7

2016 3 150 26.4 3,965 392.4 58.9

2015 4 150 22.2 3,323 300.1 45.0

2014 5 150 19.4 2,913 240.0 36.0

2013 6 150 17.5 2,622 197.2 29.6

2012 7 150 16.0 2,403 165.0 24.7

2011 8 70 14.9 1,040 139.8 9.8

2010 9 71 14.1 999 120.7 8.6

2009 10 0 13.3 0 104.5 0.0

2008 11 181 12.5 2,267 89.7 16.2

2007 12 136 11.8 1,601 76.9 10.5

2006 13 193 11.1 2,136 65.9 12.7

2005 14 147 10.4 1,529 56.6 8.3

2004 15 158 9.8 1,545 48.7 7.7

2003 16 39 9.2 358 41.8 1.6

2002 17 -12 8.6 0 35.7 0.0

2001 18 39 8.1 317 30.6 1.2

2000 19 1 7.6 8 26.4 0.0

1999 20 -45 7.2 0 22.5 0.0

1998 21 24 6.7 162 19.5 0.5

1997 22 115 6.3 729 16.6 1.9

1996 23 102 6.0 608 14.2 1.4

1995 24 7 5.6 39 12.2 0.1

1994 25 10 5.3 53 10.6 0.1

1993 26 2 5.0 10 9.1 0.0

1992 27 13 4.7 60 7.7 0.1

1991 28 1 4.4 4 6.7 0.0

1990 29 7 4.1 29 5.7 0.0

1989 30 -5 3.9 0 4.9 0.0

1988 31 1 3.6 4 4.3 0.0
3-8 March 2012

Table 3-7 Projected 2018 Gas and Condensate Production for Duchesne County

Conventional Wells Gas Production Condensate Production

Year Age Installed1 (MMscf/well-yr) (MMscf/yr) (bbl/well-yr) (bbl/yr)

1987 32 -22 3.4 0 3.7 0.0

1986 33 13 3.2 42 3.0 0.0

1985 34 76 3.0 229 2.6 0.2

1984 35 85 2.8 241 2.2 0.2

1983 36 74 2.7 197 2.0 0.2

1982 37 52 2.5 130 1.6 0.1

1981 38 26 0.8 21 0.4 0.0

Total Production by 2018 40,025 455

1 Negative values are based on records of wells shut down.

Table 3-8 Projected 2018 Gas Production for Carbon County

Gas Production

Year Age Conventional Wells Installed (MMscf/well-yr) (MMscf/yr)

2018 1 0 769 0

2017 2 67 379 25,393

2016 3 76 248 18,848

2015 4 76 183 13,908

2014 5 76 145 11,020

2013 6 76 119 9,044

2012 7 114 101 11,514

2011 8 120 87 10,440

2010 9 159 77 12,243

2009 10 0 68 0

2008 11 65 62 4,030

2007 12 35 55 1,925

2006 13 26 50 1,300

2005 14 21 45 945

2004 15 0 40 0

2003 16 16 36 576

2002 17 6 32 192

2001 18 7 29 203

2000 19 3 26 78

1999 20 6 24 144

Total Production by 2018 121,803

3.1.1.4 Development of Projected Total Condensate Production

For Uintah and Duchesne counties, condensate production in 2018 was predicted using a county-specific 

estimated well condensate production decline over time. The number of wells at each given age was 

estimated as the number of new wells in each year based on data shown in Table 3-4 and historical data. 

Condensate production in each year was the product of the number of new wells and the condensate 

production for a well of that age; the total 2018 gas production is the sum of these products. For year 2018, 

only one-half of the production from new wells was considered due to well completion activities throughout the 

year. Calculations of total gas production in Uintah and Duchesne counties are summarized in Tables 3-6 and 

3-7, respectively. However, for Carbon County, condensate production data was not available. Therefore, 

condensate production in Carbon County was predicted based on the historical ratio of the change in 
3-9 March 2012

condensate production to the change in gas production of 0.0012. Table 3-9 summarizes the projected 

condensate production for Carbon County based on this approach.

Table 3-9 Historic and Projected 2018 Gas and Condensate Production for Carbon County

Gas Production (MMscf/year) Condensate Production (bbl/year)

Year Volume Change Year-to-Year Volume Change Year-to-Year

Historic

2003 3,236,826 1,883,762 1,885 1,839 

2004 7,122,169 3,885,343 6,224 4,339 

2005 8,772,841 1,650,672 9,307 3,083 

2006 20,496,544 11,723,703 43,078 33,771 

2007 34,974,657 14,478,113 47,020 3,942 

2008 39,955,400 4,980,743 49,692 2,672 

Projected

2009 44,192,000 4,236,600 54,776 5,084 

2010 92,638,500 48,446,500 112,912 58,136 

2011 131,003,000 38,364,500 158,949 46,037 

2012 148,923,000 17,920,000 180,453 21,504 

2013 148,364,000 -559,000 179,782 -671

2014 146,057,000 -2,307,000 177,014 -2,768

2015 147,010,000 953,000 178,158 1,144 

2016 149,287,000 2,277,000 180,890 2,732 

2017 148,277,500 -1,009,500 179,679 -1,211

2018 121,803,000 -26,474,500 147,909 -31,769

3.1.1.5 Development of Projected Total Oil Production

The Newfield Monument Butte EIS indicated there will be 3,250 oil wells installed in Uintah and Duchesne 

counties over the life of the project; however, no data were available to predict oil production based on well 

schedule. Therefore, oil production in these counties was linearly forecast based on historical data. For each 

county, the linear increase was based on the growth rate from the last upturn in production (2001 for Uintah 

County and 2002 for Duchesne County). Projected oil production for the remaining counties in the Uinta Basin 

was held at their 2006 levels. A summary of projected oil production in Uintah and Duchesne counties is 

provided in Table 3-10.

Table 3-10 Historic and Projected 2018 Oil Production for Uintah and Duchesne Counties

Oil Production (103 bbl/yr)

Year Uintah Duchesne

Historic

2002 2,573 4,295 

2003 2,665 4,344 

2004 3,085 5,841 

2005 3,338 6,671 

2006 3,399 6,402 

2007 3,291 7,565 

2008 3,567 8,340 

Projected

2009 3,781 8,942 

2010 3,805 9,625 

2011 3,933 10,309 

2012 4,061 10,992 

2013 4,189 11,676 

2014 4,317 12,359

2015 4,444 13,043 

2016 4,572 13,726 

2017 4,700 14,409 

2018 4,828 15,093 
3-10 March 2012

3.1.1.6 Summary of Projected Activity Parameters and 2018 Scaling Ratios

Table 3-11 summarizes the historical 2006 activity parameter data and the projected 2018 activity levels. The 

ratio of 2018 to 2006 levels was used to develop a scaling ratio for uncontrolled emissions to predict 2018 

emissions by source category for each county.

Table 3-11 Summary of Projected Activity Parameters and 2018 Scaling Ratios

Total Well Count Spud Count Total Gas Production

Total Condensate 

Production Total Oil Production

(total wells) (spuds/yr) (MMscf/yr) (103 bbl/yr) (103 bbl/yr)

County 2006 2018

Scaling 

Ratio 2006 2018

Scaling 

Ratio 2006 2018

Scaling 

Ratio 2006 2018

Scaling 

Ratio 2006 2018

Scaling 

Ratio

Uintah 4,035 12,207 3.03 685 677 0.99 203,391 595,651 2.93 1,554 5,842 3.76 3,399 4,828 1.42

Carbon 730 1,615 2.21 58 0 0.00 20,497 121,803 5.94 43 148 3.43 0.3 0.3 1.00

Duchesne 1,474 2,981 2.02 277 156 0.56 22,526 40,025 1.77 163 455 2.79 6,402 15,093 2.36

Grand 368 368 1.00 27 27 1.00 6,855 6,855 1.00 9 9 1.00 116 116 1.00

Emery 56 56 1.00 23 23 1.00 951 951 1.00 4 4 1.00 4 4 1.00

3.1.1.7 Baseline Emissions Control Efficiency from Federal Rule and Consent Decree

Several existing federal rules will require more stringent emission standards on existing sources. Furthermore, 

some operators have entered into consent decrees with the U.S. Department of Justice that require them to 

install additional controls. This analysis reviewed and determined emissions reductions to baseline emissions 

for selected source categories based on these rules or agreements. For rules that affect only new sources, 

these controls were applied only to the portion of emissions above 2006 levels. Control efficiencies derived 

from retroactive rules or requirements were applied to all emissions for the relevant source category.

Baseline Emissions Control Efficiency from Federal Rule

Table 3-12 summarizes the analysis of existing and pending federal rules. As shown in this table, enforceable 

emissions reductions occur with the stationary and non-road engine requirements under 40 CFR Part 60, 

Subpart JJJJ and 40 CFR 89, respectively. VOC reductions from dehydrators at area sources under 40 CFR 

Part 63, Subpart HH are not likely to be required since these standards apply to area sources with a gas 

throughput of 3 MMscf/day. Based on the decline curve, the average production of a new well under the 

proposed project is 215 MMscf/yr (0.59 MMscf/day). Therefore, there is no expected applicability or 

enforceability of these reductions at area sources, and thus, reductions from this rule were not considered.

Baseline Emissions Control Efficiency from Consent Decree

The U.S. District Court recently entered into the following 3 Consent Decrees with 7 operators in the Uinta 

Basin requiring controls on selected dehydrators, compressor engines, selected condensate tanks, and 

pneumatic devices:

• U.S. v. Wind River Resources Corporation and Bill Barrett Corporation;

• U.S. v. Dominion Exploration and Production, Inc. and XTO Energy, Inc.; and

• U.S. v. Miller, Dyer, & Co., LLC, Chicago Energy Associates, and Whiting Oil and Gas Corporation.

As shown in Table 3-13, the only requirement under these consent decrees to have measurable and 

enforceable impact to baseline emissions is the installation of low-bleed pneumatics. Since low bleed 

pneumatics reduce the maximum release of actuating gas by 50 percent, emissions of VOC were assumed to 

be reduced by 50 percent as well. The total control efficiency for a county for pneumatic pumps and devices 

was then calculated as the product of this 50 percent control and the fraction of operator control of future 

assets.
3-11 March 2012

Table 3-12 Baseline Emissions Control Efficiencies from Promulgated Federal Rules

Rule Applicability

Potentially Affected

Source Categories

Emissions Standards 2018

∆CE (%)1 Pollutant 2006 2018

40 CFR 60 

Subpart JJJJ

Stationary Spark 

Ignition ICE

Miscellaneous Engines

Compression Engines

Artificial Lift Engines

NOX 12-15 g/bhp-hr2 1.0 g/bhp-hr 90.02,3

CO 7-13 g/bhp-hr2 2.0 g/bhp-hr 803

VOC 0.6-1.0 g/bhp-hr2 1.0 g/bhp-hr 03

40 CFR 63 

Subpart HH

Onshore Natural 

Gas Processing

Dehydrators – Area Sources VOC (HAP) None 95%

Reduction

04

40 CFR 63 

Subpart ZZZZ

Stationary RICE Miscellaneous Engines

Compression Engines

CO 7-13 g/bhp-hr2 93%5 03

VOC 0.6-1.0 g/bhp-hr2 76%5 03

40 CFR 89 Non-road engines Drill Rigs

Workover Rigs

Tier Tier 1 Tier 4

NOX 6.9 g/bhp-hr 2.6 g/bhp-hr 62.36

CO 8.5 g/bhp-hr 2.6 g/bhp-hr 69.46

SO2 500 ppm weight 

(ppmw) fuel

15 ppmw fuel 97.06

PM 0.4 g/bhp-hr 0.03 g/bhp-hr 92.56

VOC 1.0 g/bhp-hr 0.14 g/bhp-hr 86.06

1

 ∆CE is used to adjust 2018 baseline emissions from the 2006 WRAP Phase III emissions by source category. Projected emissions for modeling are based on 

increased activity (well count, spud count, gas production, condensate production, and oil production). These projected emissions are reduced based on this 

improved control effectiveness from promulgated federal standards that impact future activity. 

For non-retroactive sources, this is applied as: 2006 Emissions + [(2018 Emissions-2006 Emissions)(1-∆CE)]

For retroactive sources, this is applied as: 2018 Emissions (1-∆CE)

2

 Pre-control (2006) emissions determined from preamble to Standards of Performance for Stationary Spark Ignition Internal Combustion Engines and National 

Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines; Proposed Rule. 71 Federal Register 33815-3816, Section 

IV.B.1.c.-d.

3

 Rule is not retroactive; reductions apply to emissions from sources installed after 2006 only. 

4

 The area source provisions for this rule apply to glycol dehydrators with an actual annual average gas throughput rate of 85,000 scf/day (3 MMscf/day) and

emissions of benzene greater than 1.0 tpy. Based on the production decline curve, the highest annual average production for a well is 215 MMscf/yr, which is 

an annual average of 0.59 MMscf/day. This indicates that this rule will not apply to dehydrators in this basin. 

5

 Applies to engines >500 hp at major sources of HAP only; area sources and engines <500 hp would demonstrate compliance by complying with the emission 

standards of 40 CFR 60 Subpart JJJJ. 

6

 Calculated as [1 – (Tier 4/Tier 1)]; rule applies to operating equipment and is therefore retroactive.

Table 3-13 Baseline Emissions Control Efficiency from Consent Decrees

Potentially 

Affected Source 

Category 1 Operator

Consent Decree 

Requirement

Estimated Operator 

Control of Future 2 Assets by County Pollutant

Anticipated Control from 

Consent Decree (CE)

∆CE

2018

by County

(%)3

Dehydrators Wind River

Bill Barrett

Selected existing compressor 

stations subject to the MACT 

HH major source standards 

(95% VOC control). New 

dehydrators with uncontrolled 

VOC emissions >20 tpy must 

install controls at 95% DRE or 4 better.

0.3% Uintah

100.0% Carbon

1.9% Duchesne

All 0% - with controls limited to 

sources >20 tpy and the option to 

remove controls after 1 year; 

VOC controls are not likely or 

quantifiable.

0% All 

Dominion

XTO Energy

16% Uintah

0% Other 

Compressor 

Engines

Wind River

Bill Barrett

Selected existing compressor 

engines must install NSCR 

and AFR and meet MACT 

ZZZZ standards and NOX

standards of 1 g/bhp-hr (2 

g/bhp-hr for Miller Dyer et al.). 

New facilities must comply 

with MACT ZZZZ.

0.3% Uintah

100.0% Carbon

1.9% Duchesne

NOX

VOC

0% - NOX and VOC controls on 

future assets are already 

included in the rule effectiveness 

for New Source Performance 

Standard JJJJ. VOC reductions 

under MACT ZZZZ apply only to 

selected existing facilities that are 

not likely to provide quantifiable 

reductions.

0% All 

Dominion

XTO Energy

16% Uintah

0% Other 

Storage Tanks Wind River

Bill Barrett

Existing tanks at compression 

facilities and new facilities >14 

bbl/day must meet 95% 5 control.

0.3% Uintah

100.0% Carbon

1.9% Duchesne

VOC 0% - with controls limited to 

sources >14 bbl/day and the 

option to remove controls after 1 

year; VOC controls are not likely 

or quantifiable.

0% All 
3-12 March 2012

Table 3-13 Baseline Emissions Control Efficiency from Consent Decrees

Potentially 

Affected Source 

Category Operator1

Consent Decree 

Requirement

Estimated Operator 

Control of Future 

Assets by County2 Pollutant

Anticipated Control from 

Consent Decree (CE)

2018

∆CE by County

(%)3

Pneumatics Wind River

Bill Barrett

Retrofit existing high bleed 

pneumatics with low bleed 

pneumatics. All new facilities 

must install low bleed 

pneumatics.

0.3% Uintah

100.0% Carbon

1.9% Duchesne

VOC 50% - high bleed pneumatics are 

classed as >6 scf/day; low bleed 

pneumatics are classified as <3 

scf/day. This ratio of maximum to 

minimum specification is 

considered conservative.

8.2% Uintah6

50% Carbon6

1% Duchesne6

Dominion

XTO Energy

16% Uintah

0% Other 

1 Miller, Dyer & Co., Chicago Energy Associates and Whiting O&G have no future assets in the list of proposed action and are not considered for controls.

2 Percent operator control (%O) of future assets determined as the fraction of planned new wells in each county in 2018 for each operator divided by the 

total new wells in each county in 2018.

3 ∆CE = Σ(%O x CE) for each operator in each county.

4 Controls may be removed from a facility after 1 year provided that uncontrolled VOC emissions can be shown to be less than 5 tpy.

5 Controls may be removed from a facility after 1 year provided that uncontrolled VOC emissions can be shown to be less than 10 tpy.

6 Since the consent decrees mandate retrofits to existing assets, this control efficiency will be applied retroactively under the assumption that the operator’s

stake in future assets is equal to its existing stake.

3.1.1.8 Summary of Projected Baseline Controlled Emissions for 2018

Tables 3-14 through 3-18 show the emissions of each pollutant as well as the ratio of the controlled 2018 

Projected Baseline emissions to the historical 2006 emissions for each county. Detailed calculations appear in 

Appendix A. WRAP Phase III emissions for 2006 were multiplied by the appropriate emissions scaling 

factors, and control efficiencies were applied. Note that non-road engines and pneumatics controls were 

retroactive while controls to stationary engines only applied to the portion of emissions greater than the 2006 

emissions levels. 

Table 3-14 Summary of Projected Baseline NOX Emissions for 2018

Historical WRAP 2018 Projected Baseline

County 2006 Uncontrolled Controlled Projected/Historical Ratio

Uintah 6,096 10,841 5,888 0.97

Carbon 995 3,823 1,322 1.33

Duchesne 3,053 4,797 2,512 0.82

Grand 337 337 213 0.63

Emery 273 273 204 0.75

Total 10,754 20,071 10,138 0.94

Table 3-15 Summary of Projected Baseline CO Emissions for 2018

Historical WRAP 2018 Projected Baseline

County 2006 Uncontrolled Controlled Projected/Historical Ratio

Uintah 4,133 8,589 5,136 1.24

Carbon 814 3,855 1,550 1.90

Duchesne 2,448 4,768 2,723 1.11

Grand 207 207 154 0.74

Emery 199 199 170 0.85

Total 7,800 17,618 9,732 1.25
3-13 March 2012

Table 3-16 Summary of Projected Baseline SO2 Emissions for 2018

Historical WRAP 2018 Projected Baseline

County 2006 Uncontrolled Controlled Projected/Historical Ratio

Uintah 247 275 20 0.08

Carbon 22 7 2 0.08

Duchesne 96 58 6 0.07

Grand 16 16 1 0.05

Emery 9 9 1 0.06

Total 391 365 30 0.08

Table 3-17 Summary of Projected Baseline PM10 Emissions for 2018

Historical WRAP 2018 Projected Baseline

County 2006 Uncontrolled Controlled Projected/Historical Ratio

Uintah 344 523 284 0.83

Carbon 40 86 81 2.02

Duchesne 173 235 186 1.08

Grand 22 22 7 0.34

Emery 14 14 6 0.44

Total 592 879 565 0.95

Table 3-18 Summary of Projected Baseline VOC Emissions for 2018

Historical WRAP 2018 Projected Baseline

County 2006 Uncontrolled Controlled Projected/Historical Ratio

Uintah 45,646 130,489 126,425 2.77

Carbon 2,747 14,027 13,553 4.93

Duchesne 19,019 41,663 41,495 2.18

Grand 2,360 2,360 2,345 0.99

Emery 453 453 444 0.98

Total 70,226 188,040 184,262 2.62

It should be noted that emission controls utilized to address ozone precursor emissions from oil and gas 

activities also would control PM2.5 levels. The condensable fraction of PM2.5 is formed largely by sulfates and 

nitrates that are formed in the atmosphere from SO2 and NOX emissions. Therefore, the combined effect of low 

SO2 emissions from oil and gas activities, along with the controls on NOX emissions, will act to limit the 

formation of PM2.5 in the atmosphere.

3.1.2 Development of CMAQ-ready Emissions Inventories

Emissions inventory development for CMAQ modeling addressed several source categories including: 

a) stationary point sources, b) area sources, c) non-road mobile sources, d) on-road mobile sources, 

e) biogenic sources, and f) fire sources. For this analysis, CMAQ-ready emissions input files were created 

using SMOKE Version 2.2 for the 2006 and 2018 annual periods over the 36- and 12-km grids. The modeling 

grids are defined in Section 4.2.2. SMOKE Version 2.2 was used because several of the WRAP-developed 

emissions files were not directly compatible with SMOKE Version 2.4, the newest version of SMOKE. 

CMAQ required emission input files containing hourly emission estimates, distributed both vertically and 

horizontally in the modeling domain. For ozone modeling alone, hourly emissions were required for nitrogen 

oxide (NO), NO2, CO, several classes of VOCs, and other chemicals as available. The VOC classes used 
3-14 March 2012

depended upon the chemical mechanism selected, which for this study was the Carbon Bond 2005 speciation 

methodology (CB-05) with updates to the isoprene chemistry. 

3.1.3 Set-up of SMOKE for the Baseline Emissions Development

For this analysis, SMOKE Version 2.2 was configured to generate point, area, non-road, highway, and 

biogenic source emissions. In addition, certain subcategories, such as fires and electric generating units 

(EGU) were maintained in separate source category files to allow maximum flexibility in producing alternate 

emissions modeling strategies. Domain-specific oil- and gas-related emissions also were maintained as a 

separate source category. Pre-computed annual emissions were processed using the month, day, and 

hour-specific temporal profiles of the SMOKE model, with the exception of biogenic and highway mobile 

source emissions. These emissions were generated using the MEGAN biogenics model and USEPA’s 

guideline model for mobile source emissions (MOBILE6) modules in SMOKE. 

Producing 365 day-specific input files for all source categories would place a burden on available computing 

facilities and data management systems, but would not provide a more refined analysis given the nature of the 

input data. Selecting representative model days for some or all of the source categories reduced the 

processing and file handling requirements to a more manageable level, and for the purposes here, did not 

compromise the accuracy of the emissions files. Other current or recent projects undertaken by USEPA, 

WRAP, and the Lake Michigan Air Directors Consortium have used representative weekday/Saturday/Sunday 

emissions estimates for all source categories except biogenics for either each month or each season. 

In an attempt to better represent the level of temporal and spatial detail available for each source category, a 

more detailed strategy was adopted. Biogenic emissions were modeled for each episode day using the daily 

meteorology. Point sources, including CEM and fire emissions, were modeled for each episode day to take 

advantage of the available day-specific emissions and meteorology. All sources were treated by SMOKE as 

potentially elevated. In conformance with the modeling strategies provided in Section 4.2, no plume-in-grid 

sources were modeled. Wildfire emissions were handled as point sources using plume rise calculations to 

place emissions into appropriate vertical layers. 

Area sources, including non-road mobile and dust emissions that did not utilize meteorological data, were 

temporally allocated by the monthly, daily, and hourly profiles contained in SMOKE. Review of these temporal 

profiles indicated that maximum temporal definition was achieved by selecting representative Thursday, 

Friday, Saturday, Sunday, and Monday profiles for each month. A single week per month was selected to 

model emissions from on-road mobile sources. To best represent the average temperature ranges for that 

month, this week was selected from mid-month and adjusted to exclude holidays that would have required 

atypical processing. To simplify data handling procedures, the area source modeling dates also were selected 

from these weeks. The selected weeks for area source and on-road mobile source emissions modeling are 

shown in Table 3-19.

Table 3-19 2006 Weeks Representing On-road Mobile Sources

January 15-21 February 11-17

March 12-18 April 16-22

May 14-20 June 11-17

July 16-22 August 13-19

September 17-23 October 15-21

November 12-18 December 17-23

3.1.4 Development of Point Source Emissions

Stack parameter data frequently are not verified and careful attention is required to ensure that the point 

source emissions are properly located both horizontally and vertically on the modeling grid. This is especially 

true in some of the current regional modeling inventories. To screen for simple, but potentially serious 
3-15 March 2012

inventory errors such as these, the study team modified procedures originally developed by USEPA to provide 

a quality check. Where necessary, stack parameters were reviewed to evaluate the accuracy of the point 

source emissions, and procedures were standardized to identify and correct stack data errors. SMOKE has a 

number of built-in quality assurance procedures invoked in the processing of the point source data that are 

designed to catch missing or out-of-range stack parameters.

Point source emissions were separated into EGU and non-EGU categories. The non-EGU category did not 

include day- or hour-specific emissions. All non-EGU point source emissions were temporally allocated to 

month, day, and hour using annual emissions and SCC-based allocation factors. These factors were based on 

the cross-reference and profile data supplied with SMOKE Version 2.2 and supplemented with relevant data 

developed during the WRAP and Visibility Improvement States and Tribal Association of the Southeast 

(VISTAS) modeling studies. 

The EGU point source emissions were temporally allocated for an actual and a typical modeling scenario. The 

actual emission scenarios reflected the temporal distribution of CEM measured emissions values that occurred 

in 2005 or 2006. The actual emissions scenarios were used for model validation and performance evaluation.

All point sources were spatially allocated in the domain based on the stationary source geographic 

coordinates. If a point source was missing its latitude/longitude coordinates, the source was placed in the 

center of its respective county.

The typical 2005 and 2006 modeling inventories were developed to reflect an average temporal distribution of 

emissions from EGU point sources. This approach created a set of temporal profiles by averaging CEM

emissions distributions over a number of years in order to remove exceptional operating conditions, such as 

upsets or shutdowns. These temporal profiles were applied to the 2005 and 2006 emissions totals, as well as 

to any future year scenarios. The typical emissions modeling scenarios were used as a basis of comparison 

for baseline and future year emissions.

3.1.5 Development of Area and Non-road Source Emissions

All area and non-road source emissions were temporally allocated to month, day, and hour using annual 

emissions and SCC-based allocation factors. These factors were based on the cross-reference and profile 

data supplied with SMOKE Version 2.2 and supplemented with relevant data developed during the WRAP and 

VISTAS studies. Area and non-road sources were spatially allocated in the domain based on SCC-based 

spatial surrogate allocation factors. If an area or non-road source SCC did not have an existing cross 

reference profile assigned to it, the county-level emissions were allocated by population density in the 

respective county.

A PM transport factor was applied to fugitive dust emission sources identified in USEPA modeling to have only 

a portion of its mass transported from the source of the emissions generation. The USEPA studies indicated 

that 60 to 90 percent of PM emissions from fugitive dust sources are rapidly deposited to near-source locales, 

and hence, do not participate in the physicochemical processes on the spatial scales that are typically used in 

air quality modeling simulations. For this reason, county-specific fugitive dust emissions transport factors 

(i.e., ratios) were applied to these sources to adjust PM emissions prior to the SMOKE modeling. 

3.1.6 Development of On-road Mobile Source Emissions

The MOBILE6 module of SMOKE was used to develop the base year on-road mobile source emissions 

estimates for NOX, CO, PM, and VOC emissions. The MOBILE6 parameters, vehicle fleet descriptions, and 

VMT estimates were combined with gridded, episode-specific temperature data to calculate the gridded, hourly 

emission estimates. For the proposed project 36- and 12-km modeling, no link based data were used. The
3-16 March 2012

MOBILE6 emissions factors were based on episode-specific temperatures predicted by the meteorological 

model. Further, the MOBILE6 emissions factors model accounted for the following:

• Hourly and daily minimum/maximum temperatures;

• Traffic speeds;

• Locale-specific inspection and maintenance control programs, if any;

• Adjustments for running losses;

• Splitting of evaporative and exhaust emissions into separate source categories; and

• VMT, fleet turnover, and changes in fuel composition and Reid vapor pressure (RVP).

The primary input to MOBILE6 was the MOBILE shell file, which contains the various options (e.g., type of 

inspection and maintenance program in effect, type of oxygenated fuel program in effect, alternative vehicle 

mix profiles, RVP of in-use fuel, operating mode) that direct the calculation of the MOBILE6 emissions factors.

3.1.7 Development of Biogenic Source Emissions

Biogenic emissions were generated using MEGAN, which uses high resolution Geographic Information 

System data on plant types and biomass loadings and the Fifth Generation National Center for Atmospheric 

Research/ Penn State Mesoscale Model (MM5) surface temperature fields, and solar radiation (modeled or 

satellite-derived) to develop hourly emissions for biogenic species on the 36- and 12-km grids. MEGAN was 

selected over BEIS as the biogenics model of choice to maintain consistency with the UBAQS emissions 

inventory development.

3.1.8 Wildfires and Prescribed Burns

Wildfire and prescribed burn emissions were handled separately from the standard area source input files. 

This study used nation-wide fire emissions for the 2006 year, developed by the National Center for 

Atmospheric Research. Spatial and temporal distributions of the fire emissions were calculated based on this 

information rather than relying on standard distribution profiles. Vertical distribution of the fire emissions also 

was calculated based on fire size and biomass involvement. SMOKE Version 2.2 can model fire plume rise if 

provided with the following variables:

• PTOP – Top of the fire plume profile (meters above ground level); 

• PBOT – Bottom of the fire plume profile (meters above ground level); and

• Lay1 – The percent of the emissions entrained in the first modeling layer.

The WRAP Fire Emissions Joint Forum Emissions Inventory Report (2002) provides an approach to estimate 

these plume descriptors. In this method, fires are assigned to one of five size categories based on the total 

burn acreage and the biomass fuel loading. These categories are then used to calculate representative hourly 

plume profiles used by SMOKE Version 2.2 to distribute the vertical emissions for the fires.

3.1.9 Products of the Emissions Inventory Development Process

In addition to the CMAQ-ready input files generated for each hour of the days modeled in the annual run, a 

number of quality assurance files were prepared and used to check for gross errors in the emissions inputs. 

Importing the model-ready emissions into the Package for Analysis and Visualization of Environmental Data 

and looking at both the spatial and temporal distribution of the emissions, provided insight into the quality and 
3-17 March 2012

accuracy of the emissions inputs. It also allowed for the following quality assurance checks on the emissions 

estimated using SMOKE Version 2.2:

• Visualizing the model-ready emissions with the scale of the plots set to a very low value allows for 

corrections to areas where emissions are omitted from the raw inventory or are erroneously located 

(such as area source industrial emission in water cells); 

• Normalizing the emissions by population for each state illustrates where the inventories may have 

been deficient and provides a reality check of the inventories vis-à-vis a spatial evaluation of the 

population weighted emissions estimates; and

• Spot-checking vertical allocation of point source emissions estimates.

State inventory summaries were prepared prior to the emissions processing to compare against SMOKE 

output report totals generated after each major step of the emissions generation process. To check the vertical 

allocation of the emissions estimates, reports were created by source, hour, and layer for the domain. 

Quantitative quality assurance analyses often reveal deficiencies in the input data or the model setup. 

Sometimes, tailored procedures are necessary to track down the source of each problem. Some of the reports 

that are generated to review the processed emissions estimates include the following:

• State and county totals from inventory for each source category;

• State and county totals after spatial allocation for each source category;

• State and county totals by day after temporal allocation for each source category for representative 

days;

• State and county totals by model species after chemical speciation for each source category;

• State and county model-ready totals (after spatial allocation, temporal allocation, and chemical 

speciation) for each source category and for all source categories combined;

• If elevated source selection is chosen, the report indicating which sources have been selected as 

elevated and plume-in-grid will be included;

• Totals by SCC from the inventory for area, mobile, and point sources;

• Totals by state and SCC from the inventory for area, mobile, and point sources;

• Totals by county and SCC from the inventory for area, mobile, and point sources;

• Totals by SCC and spatial surrogates code for area and mobile sources;

• Totals by speciation profile code for area, mobile, and point sources;

• Totals by speciation profile code and SCC for area, mobile, and point sources;

• Totals by monthly temporal profile code for area, mobile, and point sources;

• Totals by monthly temporal profile code and SCC for area, mobile, and point sources;

• Totals by weekly temporal profile code for area, mobile, and point sources;

• Totals by weekly temporal profile code and SCC for area, mobile, and point sources;

• Totals by diurnal temporal profile code for area, mobile, and point sources; and

• Totals by diurnal temporal profile code and SCC for area, mobile, and point sources.

These reports and data were used to validate the emissions modeling process.
3-18 March 2012

3.2 Determination of Cumulative Impacts

As discussed in Section 3.1, the emissions estimate for the 2018 Projected Baseline was calculated from a 

combination of the WRAP II data for 2018 sources and from the WRAP III data for 2006 scaled up in a manner 

identical to the WRAP II ratio of 2006 to 2018 data for oil and gas sources. Although 2017 is identified as the 

year of maximum emissions for the Proposed Action, the projected 2018 emissions are considered 

representative of the 2017 non-project emissions. These emissions represent the currently approved and 

reasonably foreseeable future actions in the Uinta Basin. 

Study-specific emission inventories are described in more detail in Section 3.7. These emissions were 

developed for the GNBPA for both the Proposed Action and Optimal Recovery Alternative and were added to 

the 2018 Projected Baseline to estimate cumulative total emissions from each alternative. These action 

alternative inventories included the construction, drilling and completion, production, and operation emissions 

calculated for the last year of construction and the year when the proposed project is expected to be fully

developed – 2017 for the Proposed Action and 2026 for the Optimal Recovery Alternative. Because the 

Proposed Action is expected to be fully developed in 2018, the WRAP 2018 inventory could be used, thus 

allowing for the inclusion of the most precise emissions estimates for the future year.

3.3 Construction Emissions

The project descriptions for both the Proposed Action and the Optimal Recovery Alternative include the 

construction of well pads and additional infrastructure in fixed and linear facilities. Well pads consist of single 

well pads built to house one new well, or twin/multi-well pads constructed by expanding an existing single well 

pad to accommodate one or more additional wells. Other fixed facilities that would be constructed include:

• Worker camps for housing construction personnel (man camp);

• Compressor stations for processing and transporting additional production;

• Water tank batteries for storage and handling of additional produced water; and

• Water injection facilities (injection wells) for disposal of produced water.

Linear facilities and infrastructure that would be constructed for these project alternatives include:

• Access roads to wells and support facilities;

• Gas pipelines for gathering and transport of produced natural gas;

• Water pipelines for gathering and transport of produced water to tank batteries and injection wells; and

• Electric power lines to provide electrical power to wells, compressors, and other facilities.

Gas and water pipelines would include both surface and buried lines. Surface lines installed in existing 

rights-of-way are assumed to have minimal disturbance or resulting construction emissions.

The primary pollutants of concern relative to construction emissions are PM, PM10, and PM2.5 from surface 

disturbance, wind erosion, and vehicle traffic. Additionally, emissions of all PM species as well as other criteria 

pollutants such as NOX, CO, SO2, VOC, and HAP result from the operation of heavy mobile equipment. These 

emissions are difficult to quantify due to the uncertainty and variability in the scale and duration of construction 

activity. Furthermore, emissions from construction activities are temporary and localized making definitive 

quantification of emissions and impacts impossible. Finally, no regulatory standards exist to evaluate impacts 

of construction activities. For these reasons, this analysis did not include modeling of construction emissions 

from the proposed project.
3-19 March 2012

3.4 Drilling Emissions

All project action alternatives include the installation of new production wells in two phases. The first phase 

would consist of operating the diesel-fired drill rig and associated equipment. In the second phase, the well 

would be completed by installation of the well casing and injection of a fracturing liquid to enhance production. 

In both phases, equipment would be hauled or serviced by heavy and light duty vehicles. These operations 

emit criteria pollutants from fuel combustion and PM from vehicle traffic. Each of these sources of emissions 

are described and quantified in the following sections.

3.4.1 Emissions from Drill Rig Operation

Based on data provided by KMG, each rig was assumed to be driven by up to three Caterpillar 

G3512LE diesel-fired engines or equivalent. These engines would run in tandem with only two of the 

engines operating at a time. Further, drilling would be concluded at each well by the operation of a 

workover rig equipped with a Caterpillar C13 engine or equivalent to complete the well.

Although the peak production year would occur after the compliance date for Tier 4 engines, KMG has 

only committed to the use of Tier 2 engines. The regional emissions inventory for the analysis only 

considered the use of Tier 4 engines because this inventory is used to determine regional impacts to 

ambient air quality in a specific projected year that is well past the Tier 4 compliance date for all 

alternatives. The near-field modeling analysis must consider the use of both Tier 2 and Tier 4 engines 

in the field because drilling would commence prior to the Tier 4 compliance date. Therefore, emissions 

estimates were calculated using emissions factors of NOX, CO, PM10, PM2.5, and VOCs for both Tier 2 

and Tier 4 engine standards from Table 1 of 40 CFR 1089.101 to meet the needs for both action 

alternatives. 

The emission factor for SO2 was derived using Equation 3-1 assuming 15 ppm weight (ppmw) of sulfur in the 

fuel per fuel sulfur standards in 40 CFR 89. HAP emission factors were taken from the National Mobile 

Inventory Model database (USEPA 2005a). Emissions from the drill rig engine for each well drilled are 

calculated using Equation 3-2 and shown in Table 3-20.

Equation 3-1 Calculation of SO2 Emission Factor Based on Fuel Sulfur

Equation 3-2 Calculation of Criteria Pollutant Emissions from Diesel Fired Drill Rig Engines

x g hp hr

lb

g

x

lb S

lb SO

x

hp hr

Btu

x

Btu

gal

x

gal

lb fuel

x

lb fuel

lb S EFSO = − − = − 4.6 10 / 453.6

32.06

7,000 64.06

140,000

6.8

10

15 2 3

2 6

lb

ton x glb x LoadFactor x day

rig hour x well

days x rig

hp E tons well EF g hp hr x 453.6 2000

24 ( / ) ( / ) − = −
3-20 March 2012

Table 3-20 Pollutant Emissions from Rig Engines per Well Drilled

Drill Rig Engine Emissions

Rig Size = 1,476 hp

Annual Utilization = 0.67 (2 of 3 engines)

Daily Load Factor = 0.65

Overall Load Factor = 0.43 (for 24-hour and annual emissions); 1.00 for hourly emissions

Duration = 15 days/well; 24 hours/day

Pollutant

Tier 2 Tier 4

Emission 

Factor

Emission Rate Emission 

Factor

Emission Rate

Hourly 24-hour Annual Hourly 24-hour Annual

(g/hp-hr) (lb/hr) (lb/hr) (tons/well) (g/hp-hr) (lb/hr) (lb/hr) (tons/well)

NOX 4.8 15.6 10.2 3.7 2.6 8.5 5.5 2.0

CO 2.6 8.5 5.5 2.0 2.6 8.5 5.5 2.0

SO2 0.0046 0.02 0.001 0.004 0.0046 0.02 0.001 0.004

PM10/2.5 0.15 0.5 0.3 0.1 0.015 0.05 0.03 0.01

VOC 0.14 0.5 0.3 0.1 0.14 0.5 0.3 0.1

Benzene 2.9E-03 9.3E-03 6.0E-03 2.2E-03 2.9E-03 9.3E-03 6.0E-03 2.2E-03

Toluene 2.1E-03 6.8E-03 4.4E-03 1.6E-03 2.1E-03 6.8E-03 4.4E-03 1.6E-03

Ethylbenzene 4.3E-04 1.4E-03 9.2E-04 3.3E-04 4.3E-04 1.4E-03 9.2E-04 3.3E-04

Xylene 1.5E-03 4.8E-03 3.1E-03 1.1E-03 1.5E-03 4.8E-03 3.1E-03 1.1E-03

Formaldehyde 1.7E-02 5.4E-02 3.5E-02 1.3E-02 1.7E-02 5.4E-02 3.5E-02 1.3E-02

n-Hexane 2.2E-04 7.3E-04 4.7E-04 1.7E-04 2.2E-04 7.3E-04 4.7E-04 1.7E-04

Completion Rig Engine Emissions

Rig Size = 475 hp

Annual Utilization = 1.00 (1 of 1 engine)

Daily Load Factor = 0.65

Overall Load Factor = 0.65 (for 24-hour and annual emissions); 1.00 for hourly emissions

Duration = 3 days/well; 12 hours/day

Pollutant

Tier 2 Tier 4

Emission 

Factor

Emission Rate Emission 

Factor

Emission Rate

Hourly 24-hour Annual Hourly 24-hour Annual

(g/hp-hr) (lb/hr) (lb/hr) (tons/well) (g/hp-hr) (lb/hr) (lb/hr) (tons/well)

NOX 4.8 5.0 3.3 0.06 2.6 2.7 1.8 0.03

CO 2.6 2.7 1.8 0.03 2.6 2.7 1.8 0.03

SO2 0.005 0.005 0.003 0.00006 0.005 0.003 0.00006 0.005

PM10/2.5 0.15 0.2 0.1 0.0018 0.015 0.0016 0.010 0.00018

VOC 0.14 0.2 0.1 0.0017 0.14 0.2 0.1 0.0017

Benzene 2.9E-03 3.0E-03 1.9E-03 3.5E-05 2.9E-03 3.0E-03 1.9E-03 3.5E-05

Toluene 2.1E-03 2.2E-03 1.4E-03 2.6E-05 2.1E-03 2.2E-03 1.4E-03 2.6E-05

Ethylbenzene 4.3E-04 4.5E-04 3.0E-04 5.3E-06 4.3E-04 4.5E-04 3.0E-04 5.3E-06

Xylene 1.5E-03 1.6E-03 1.0E-03 1.8E-05 1.5E-03 1.6E-03 1.0E-03 1.8E-05

Formaldehyde 1.7E-02 1.7E-02 1.1E-02 2.0E-04 1.7E-02 1.7E-02 1.1E-02 2.0 E-04

n-Hexane 2.2E-04 2.3E-04 1.5E-04 2.7E-06 2.2E-04 2.3E-04 1.5E-04 2.7E-06

Each rig would be equipped with a diesel-fired boiler to provide heat and steam during cold periods. It was 

assumed that the boilers would run at 2.8 million British thermal units (MMBtu)/hr per boiler (20.0 gal/hr based 

on 140,000 Btu/gal) and operate 4,380 hr/yr. Emissions factors were taken from AP-42, Table 1.3-1 and 

Table 1.3-9 for distillate oil fired boilers (USEPA 1998b). Emissions per rig are the product of the emission 

factor, fuel use, and operating time. SO2 emissions are based on the use of diesel fuel with 15 ppmw 

sulfur content. Because each rig was estimated to drill 2 wells per month, the emissions per well drilled equal 

the annual emissions per rig divided by 24 wells per rig. A summary of emissions from rig boilers is provided in 

Table 3-21.
3-21 March 2012

Table 3-21 Pollutant Emissions from Rig Boilers per Well Drilled

Design Firing Rate = 2.8 MMBtu/hr

= 20.0 gallons/hour1

Annual Operating Hours = 4,380

Pollutant

Emission

Factor

Emission Rate

Hourly Annual

(lb/103 gal) (lb/hr-rig) (tpy/rig) (tons/well)

NOX 18.0 0.4 0.8 0.03

CO 5.0 0.1 0.2 0.009

SO2 0.2 0.004 0.009 0.0004

PM10 (PM2.5) 2.0 0.04 0.09 0.004

VOC 0.34 0.007 0.01 0.0006

Benzene 2.1E-04 4.3E-06 9.4E-06 3.9E-07

Toluene 6.2E-03 1.2E-04 2.7E-04 1.1E-05

Ethylbenzene 6.4E-05 1.3E-06 2.8E-06 1.2E-07

Xylene 1.1E-04 2.2E-06 4.8E-06 2.0E-07

Formaldehyde 3.3E-02 6.6E-04 1.4E-03 6.0E-05

n-Hexane No data No data No data No data

1 Based on 140,000 Btu per gallon.

3.4.2 Criteria Pollutant Emissions from Drilling and Completion Traffic

Light and heavy duty vehicles would move on unpaved roads during drilling and completion. Emission factors 

for PM10 and PM2.5 emissions from the unpaved roadways were developed from Equation 1a in Section 13.2.2 

of AP-42 (USEPA 2006a) for industrial sites, as shown in Equation 3-3. Emissions factors for PM10 and PM2.5

from light duty vehicle traffic on publicly accessible unpaved roads were developed using Equation 1b in 

Section 13.2.2 of AP-42 (USEPA 2006a), as shown in Equation 3-4. The silt loading value of 5.1 was taken 

from AP-42, Table 13.2.2-1 (USEPA 2006a). For emission calculation purposes, total VMT per site and control 

efficiencies were benchmarked from similar calculations from the Pinedale Anticline EIS (BLM 2008b). No 

added controls were assumed from naturally occurring precipitation events, as controls are based on routine 

watering operations. The k factors used for PM2.5 in Equations 3-3 and 3-4 were based on a 2003 version of 

AP-42, which is slightly higher than the 2006 version and was used here to be conservative.

Equation 3-3 Calculation of Uncontrolled PM Emission Factors from Unpaved Roads at Industrial Sites

Where: k (unitless) = 1.5 for PM10 and 0.27 for PM2.5

Equation 3-4 Calculation of Uncontrolled PM Emission Factors from Publicly Accessible Unpaved 

Roads

Where: k (unitless) = 1.8 for PM10 and 0.23 for PM2.5

C (lb/VMT) = 0.00047 for PM10 and 0.00036 for PM2.5

A summary of traffic PM emissions is provided in Tables 3-22 through 3-24. Data were provided where 

needed for emissions calculations. The total emissions were calculated for each well site that is drilled, 

0.9 0.45

3

( )

12

(5.1%) ( / ) 



 



 



 



 = W tons

x

sL E lb VMT k x PM

C

M

S mph x sL

EPM lb VMT k x −





 









 



 



 





= 0.2

0.5

0.5

30

( )

12

(5.1%)

( / )
3-22 March 2012

Table 3-22 PM Emissions from Unpaved Roads for Drilling Traffic

Vehicle Type

Dust

Control

Method

Mean

Weight

Mean

Speed

Moisture

Content

Estimated

Round

Trips

Round

Trip

Distance

Vehicle

Miles

Traveled

Uncontrolled 

PM10Emission

Factor

Uncontrolled 

PM2.5Emission

Factor

Control

Efficiency

Controlled

PM10

Emissions

Controlled

PM2.5

Emissions

(ton) (mph) (%) (round trip/well) (miles) (VMT/well) (lb/VMT) (lb/VMT) (%) (lb/well) (lb/well)

Heavy Trucks Chemical 22.0 N/A N/A 360 10 3600 1.70 0.26 85 919.22 140.95

Water 360 1 360 1.70 0.26 50 306.41 46.98

Light Trucks Chemical N/A 20 2.4 540 10 5400 0.46 0.07 85 369.32 55.16

Water 20 540 1 540 0.46 0.07 50 123.11 18.39

Total 1,718.06 261.48

Table 3-23 PM Emissions from Unpaved Roads for Completion Traffic

Vehicle Type

Dust

Control

Method

Mean

Weight

Mean

Speed

Moisture

Content

Estimated

Round

Trips

Round

Trip

Distance

Vehicle

Miles

Traveled

Uncontrolled 

PM10Emission

Factor

Uncontrolled 

PM2.5Emission

Factor

Control

Efficiency

Controlled

PM10

Emissions

Controlled

PM2.5

Emissions

(ton) (mph) (%) (round trip/well) (miles) (VMT/well) (lb/VMT) (lb/VMT) (%) (lb/well) (lb/well)

Heavy Trucks Chemical 22.0 N/A N/A 300 10 3000 1.70 0.26 85 766.02 117.46

Water 300 1 300 1.70 0.26 50 255.34 39.15

Light Trucks Chemical N/A 20 2.4 450 10 4500 0.46 0.07 85 307.77 45.97

Water 20 450 1 450 0.46 0.07 50 102.59 15.32

Total 1,431.72 217.90

Table 3-24 PM Emissions from Unpaved Roads for Rig Hauling Traffic

Vehicle Type

Dust

Control

Method

Mean

Weight

Mean

Speed

Moisture

Content

Estimated

Round

Trips

Round

Trip

Distance

Vehicle

Miles

Traveled

Uncontrolled 

PM10Emission

Factor

Uncontrolled 

PM2.5Emission

Factor

Control

Efficiency

Controlled

PM10

Emissions

Controlled

PM2.5

Emissions

(ton) (mph) (%) (round trip/well) (miles) (VMT/well) (lb/VMT) (lb/VMT) (%) (lb/well) (lb/well)

Heavy Trucks Chemical 22.0 N/A N/A 26 10 260 1.70 0.26 85 66.39 10.18

Water 26 1 26 1.70 0.26 50 22.13 3.39

Light Trucks Chemical N/A 20 2.4 9 10 90 0.46 0.07 85 6.16 0.92

Water 20 9 1 9 0.46 0.07 50 2.05 0.31

Total 96.72 14.80
3-23 March 2012

including drilling, completion, and rig hauling. The calculations were based on the assumption of a 10-mile 

industrial site road controlled by chemical surfactants and a 1-mile on-site haul road controlled by water 

sprays. The total number of round trips, distance traveled, control effectiveness, and total controlled and 

uncontrolled emissions are shown in Tables 3-22 through 3-24. 

Emissions of criteria pollutants from rig hauling also were included since there would be a large volume of haul 

traffic per well. Emissions factors for heavy equipment hauling were taken from AP-42 for mobile sources for 

high altitude heavy-duty diesel powered vehicle traffic (USEPA 1995a). Emission factors were based on the 

2018 inventory year with a 2013 model year emission rate. Emission rates for SO2 for these sources were 

taken from the earlier version of AP-42. Total hauling traffic is the sum of drilling, completion, and rig haul 

heavy truck traffic. A summary of hauling emissions is provided in Table 3-25. 

Table 3-25 Heavy Truck Criteria Pollutant Emissions from Well Drilling, Completion, and Rig Hauling

Haul Truck Round Trips = 686 round trips/well

Round Trip Distance = 11 miles/round trip

Total Distance per Well = 7,546 VMT/well

Emission Factor Emission Rate

Pollutant (g/VMT) (lb/well)

NOX 6.5 108.1

CO 18.2 302.8

SO2 0.18 3.0

VOC 4.7 78.2

3.4.3 Drilling Emissions Summary

The emissions of criteria pollutants and HAP per well installed are summarized in Table 3-26. Note that when 

PM2.5 emission factors were unavailable, PM10 was used as a surrogate. Annual emissions are presented 

for both Tier 2 and Tier 4 engines. The regional emissions inventory uses Tier 4 emissions because 

development under the project alternatives would occur after the Tier 4 implementation date. The 

near-field modeling uses both Tier 2 and Tier 4 emissions to evaluate impacts from both options.

Table 3-26 Summary of Pollutant 

Activity NOX

Tier 2 Engines

Drill Rig 3.7

Completion Rig 0.06

Rig Boiler 0.03

Drill Road Traffic -

Completion Road Traffic -

Rig Hauling Traffic -

Hauling Tailpipe 0.05

Total 3.8

Tier 4 Engines

Drill Rig 2.0

Completion Rig 0.03

Rig Boiler 0.03

Drill Road Traffic -

Completion Road Traffic -

Rig Hauling Traffic -

Hauling Tailpipe 0.05

Total 2.1

Emissions for Well Installation

Criteria Pollutant Emissions (tons/well)

CO SO2 PM10

2.0 0.004 0.1

0.03 0.00006 0.0002

0.009 0.0004 0.004

- - 0.9

- - 0.7

- - 0.05

0.2 0.002 -

2.2 0.005 1.7

2.0 0.004 0.01

0.03 0.00006 0.0002

0.009 0.0004 0.004

- - 0.9

- - 0.7

- - 0.05

0.2 0.002 -

2.2 0.006 1.6

PM2.5

0.1

0.0002

0.004

0.1

0.1

0.007

-

0.4

0.01

0.0002

0.004

0.1

0.1

0.007

-

0.3

VOC

0.1

0.002

0.0006

-

-

-

0.04

0.1

0.1

0.002

0.0006

-

-

-

0.04

0.1
3-24 March 2012

Table 3-26 Summary of Pollutant Emissions for Well Installation

Criteria Pollutant Emissions (tons/well)

Activity NOX CO SO2 PM10 PM2.5 VOC

Hazardous Air Pollutant Emissions (tons/well)

Activity Benzene Toluene Ethylbenzne Xylene Formaldehyde n-Hexane

Tier 2 and Tier 4 Engines

Drill Rig 232E-03 1.6E-03 3.3E-04 1.1E-03 1.3E-02 1.7E-04

Completion Rig 3.5E-05 2.6E-05 5.3E-06 1.8E-05 2.0E-04 2.7E-06

Rig Boiler 3.9E-07 1.1E-05 1.2E-07 2.0E-07 6.0E-05 No data

Total 2.2E-03 1.6E-03 3.4E-04 1.1E-03 1.3E-02 1.7E-04

3.5 Production Emissions

Criteria pollutants are emitted during the operation of a production well. Primarily, emissions of VOC result 

from the volatilization of light organic liquids in the separator, known as flashing. Wells installed as part of 

these project alternatives would be equipped with zero emissions dehydrators. Additionally, each well would 

operate a small gas-fired heater during the cold season to prevent freezing. Fugitive emissions of VOC result 

from leaks in flanges, pneumatic devices, and connectors at the well site. Finally, PM and gaseous pollutants

are emitted from the traffic of tanker trucks hauling produced water and light duty vehicles transporting crews 

servicing the well. Each of these sources of emissions are described and quantified in the following sections.

3.5.1 VOC and HAP Emissions from Condensate Flashing

The gas extracted from a production well also contains various other components including large non-methane 

or non-ethane hydrocarbons. Most of these hydrocarbons are in liquid phase under the well pressure and 

volatilize when returned to ambient pressure in the phase separator. These hydrocarbons are emitted as VOC 

(and selected HAP). Calculating the emission rate is complex and depends on numerous process variables 

including the physical and chemical characteristics of the condensate as well as changes in pressure and 

temperature between the separator vessel and ambient conditions.

American Petroleum Institute’s (API’s) process simulator E&P Tanks Version 2.0 was used to determine 

emissions from condensate flashing. KMG provided high pressure condensate analytical information (see 

Appendix B). Table 3-27 summarizes the project input and physical data for the process simulation, while 

Table 3-28 shows the condensate mole fraction of each organic compound and the calculated process stream 

data from the simulation. The simulation was run for two process rates to account for anticipated well 

production decline over time. 

Table 3-27 Condensate Flashing Calculation Process Physical Characteristics

Setup Information

Flowsheet Selection Oil Tank with Separator

Calculation Method RVP Distillation

Separator Stream High Pressure Oil

Data Input 1

Separator Pressure (psig) 90

Separator Temperature (°F) 78

Ambient Pressure (psia) 14.7

Ambient Temperature (°F) 70

C10+ Specific Gravity 0.74

C10+ Molecular Weight 159.67

Days of Annual Operation (days/year) 365

API Gravity 61.28

Reid Vapor Pressure (psia) 7.25

1 See Appendix B for analytical data.
3-25 March 2012

Table 3-28 Condensate Flashing Calculation Chemical Characteristics

Condensate Chemical Characteristics Stream Data (E&P Tanks Version 2.0 Output)

Chemical Component Mol%

Molecular 

Weight

LP Oil Flash Oil Sale Oil Flash Gas

Working and 

Standing Gas

Total 

Emission Molar Wt % Wt

mol% mol% mol% mol% mol% mol% g/mol Wt %

H2S 0.0000 34.8 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.00 0.00

O2 0.0000 32 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.00 0.00

CO2 0.4190 44.01 0.3769 0.0840 0.0484 5.2604 4.3922 5.1881 13.41 0.14

N2 0.0000 28.01 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.00 0.00

C1 4.0438 16.04 3.0671 0.2776 0.0764 49.5796 16.1487 46.7933 113.27 1.21

C2 1.9669 30.07 1.8755 0.7128 0.5332 21.2616 24.7510 21.5524 31.55 0.34

C3 1.9609 44.1 1.9500 1.3882 1.2657 11.3178 19.5050 12.0002 58.96 0.63

i-C4 0.9410 58.12 0.9460 0.8468 0.8174 2.5996 5.4619 2.8382 41.50 0.44

n-C4 1.7049 58.12 1.7176 1.6152 1.5774 3.4243 7.7374 3.7837 99.09 1.06

i-C5 1.6679 72.15 1.6854 1.7044 1.6948 1.3689 3.6023 1.5550 96.94 1.03

n-C5 2.1989 72.15 2.2232 2.2764 2.2705 1.3361 3.7528 1.5375 158.65 1.69

C6 6.2227 86.16 6.2976 6.5962 6.6208 1.3189 4.3371 1.5705 448.97 4.79

C7 17.1271 100.2 17.3395 18.3079 18.4224 1.1933 4.6814 1.4840 1,475.67 15.75

C8 15.6182 114.23 15.8140 16.7422 16.8634 0.3374 1.5895 0.4418 1,564.94 16.71

C9 12.5804 128.28 12.7386 13.4971 13.5994 0.0921 0.5165 0.1275 1,437.06 15.34

C10+ 17.2661 159.67 17.4836 18.5312 18.6571 0.0163 0.1260 0.0255 2,214.90 23.65

Benzene 0.9069 78.11 0.9180 0.9649 0.9696 0.1354 0.4661 0.1630 144.80 1.55

Toluene 5.6567 92.13 5.7273 6.0569 6.0982 0.2326 0.9761 0.2946 441.84 4.72

Ethyl benzene 0.4490 106.17 0.4546 0.4815 0.4851 0.0060 0.0296 0.0079 41.37 0.44

Xylenes 6.5727 106.17 6.6553 7.0499 7.1026 0.0756 0.3871 0.1016 697.82 7.45

n-Hexane 2.6969 86.18 2.7297 2.8668 2.8797 0.4440 1.5392 0.5352 286.33 3.06

2,2,4-Trimethylpentane 0.0000 114.24 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.00 0.00
3-26 March 2012

Estimated condensate production was 10 barrels (bbl)/day during the first year of production, while wells over 

a year old were assumed to only produce 3 bbl/day of condensate. Table 3-29 provides a summary of VOC 

emissions for each well type. Raw output from the E&P Tanks Version 2.0 simulation is provided in 

Appendix B. 

Table 3-29 Emissions of VOC and HAP from Condensate Flashing

Chemical Component Mol%

New Well1 Old Well1 

(tpy) (lb/hr) (tpy) (lb/hr)

C3 1.9609 1.422 0.325 0.427 0.097

i-C4 0.9410 0.443 0.101 0.133 0.030

n-C4 1.7049 0.591 0.135 0.177 0.040

i-C5 1.6679 0.301 0.069 0.090 0.021

n-C5 2.1989 0.298 0.068 0.089 0.020

C6 6.2227 0.354 0.081 0.106 0.024

C7 17.1271 0.387 0.088 0.116 0.026

C8 15.6182 0.132 0.030 0.040 0.009

C9 12.5804 0.042 0.010 0.013 0.003

C10+ 17.2661 0.011 0.003 0.003 0.001

Benzene 0.9069 0.034 0.008 0.010 0.002

Toluene 5.6567 0.073 0.017 0.022 0.005

Ethyl benzene 0.4490 0.002 0.000 0.001 0.000

Xylenes 6.5727 0.029 0.007 0.009 0.002

n-Hexane 2.6969 0.124 0.028 0.037 0.008

2,2,4-Trimethylpentane 0.0000 0.000 0.000 0.000 0.000

Total VOC Emissions 4.243 0.970 1.273 0.288

1 Production at a new well is assumed to be 10 bbl/day; at an old well 3 bbl/day.

3.5.2 Emissions from Separator Heaters

Each separator would be equipped with a gas-fired heater to provide heat during cold periods. It was assumed 

that these boilers would run at 0.5 MMBtu/hr each and operate 4,380 hr/yr. Emissions factors were taken from 

AP-42, Tables 1.4 1, 1.4-2 and 1.4-3 for small uncontrolled boilers (USEPA 1998c). Emission factors for SO2

were derived from fuel sulfur content. It was assumed that there is no more than 20 ppmw (0.012 gr/scf) in the 

fuel gas, yielding an emission factor of 3.4 lb/MMscf as shown in Equation 3-5. Emissions per well are the 

product of the emission factor, fuel use, and operating time as shown in Table 3-30. 

Equation 3-5 SO2 Emissions Factor from Combustion of Fuel Gas in Heaters

Table 3-30 Emissions from Separator Heaters at Production Wells

Annual Operating Hours = 4,380

Heat Content = 950 Btu/scf

Fuel Sulfur Content = 0.012 gr/scf

Design Firing Rate = 0.5 MMBtu/hr

= 0.00053 MMscf/hr

Emission Factor Emission Rate (per well)

Pollutant (lb/MMscf) (lb/hr) (tpy)

NOX 100.0 0.053 0.12

lb MMscf MMscf

scf x

lb S

lb SO

x

gr

lb

x

fuelscf

Sgr EFSO /4.3 10

06.32

06.64

000,7

012.0 6

2

2 = =
3-27 March 2012

Table 3-30 Emissions from Separator Heaters at Production Wells

Annual Operating Hours = 4,380

Heat Content = 950 Btu/scf

Fuel Sulfur Content = 0.012 gr/scf

Design Firing Rate = 0.5 MMBtu/hr

= 0.00053 MMscf/hr

Emission Factor Emission Rate (per well)

Pollutant (lb/MMscf) (lb/hr) (tpy)

CO 84.0 0.044 0.097

SO2 3.4 0.0018 0.0039

Total PM 7.6 0.0040 0.0088

VOC 5.5 0.0029 0.0063

Benzene 0.002 1.11E-06 2.42E-06

Toluene 0.003 1.79E-06 3.92E-06

Ethylbenzene No data No data No data

Xylene No data No data No data

Formaldehyde 0.08 0.00004 0.00008

n-Hexane 1.80 0.0009 0.002

3.5.3 Fugitive Emissions

Emissions of VOC and HAP also result from gas and light oil (condensate) leaking from flanges and other 

connections. Total leakage of gas and VOC from light oil was estimated using the USEPA Protocol for 

Equipment Leak Estimates (USEPA 1995b) based on assumptions regarding component counts at each well 

site. VOC emissions were calculated based on the VOC (non-methane and non-ethane) weight fraction in the 

respective material stream. For gas leaks, this also was reduced by the weight fraction of gas in the 

condensate stream; 10 percent was assumed for this analysis. Table 3-31 summarizes the emissions of VOC 

for fugitive leaks for each well based on the individual number of components at each well site.

Table 3-31 Emissions of VOC from Fugitive Leaks at Production Wells

Gas and Condensate Data

Gas = 10.0% Total Organic Compounds (TOC) by weight

Methane = 92.5% of TOC by weight

Ethane = 3.7% of TOC by weight

Condensate = 98.31% of VOC by weight

VOC Emissions

Source Service TOC Emission Factor TOC Emissions VOC1, 2

Components Type Quantity (kg/hr/component) (lb/hr) (lb/hr) (tpy)

Valves

Gas 20 0.004 0.02 0.0008 0.003

Light Oil 5 0.002 0.03 0.03 0.12

Flanges

Gas 30 0.0004 0.003 0.0001 0.0004

Light Oil 10 0.0001 0.002 0.002 0.01

Connections

Gas 275 0.0002 0.01 0.0005 0.002

Light Oil 100 0.0002 0.05 0.05 0.20

Pump seals

Gas 2 0.002 0.001 0.00004 0.0002

Light Oil 2 0.013 0.06 0.06 0.25
3-28 March 2012

Table 3-31 Emissions of VOC from Fugitive Leaks at Production Wells

Gas and Condensate Data

Gas = 10.0% Total Organic Compounds (TOC) by weight

Methane = 92.5% of TOC by weight

Ethane = 3.7% of TOC by weight

Condensate = 98.31% of VOC by weight

VOC Emissions

Source Service Quantity TOC Emission Factor TOC Emissions VOC1, 2

Open ended lines 

Gas 3 0.002 0.001 0.00005 0.0002

Light Oil 3 0.001 0.009 0.009 0.04

All Sources

Gas 0.04 0.001 0.006

Light Oil 0.14 0.14 0.62

Total Emissions/Well 0.14 0.62 

1 Egas

2 Elt oil

(tpy) = TOC EF

(tpy) = TOC EF 

* Quantity * Gas 

* Quantity * Gas 

Weight Fraction * (1 -

Weight Fraction

(Methane + Ethane Weight Fraction))

HAP emissions were based on the fraction in the total organic carbon of the selected HAP in both gas and light 

oil. Gas fractions were taken from the condensate analysis presented in Table 3-28 while light oil fractions are 

taken from WDEQ guidance (WDEQ 2007). These results are presented in Table 3-32. 

Table 3-32 Emissions of Selected HAP from Fugitive Leaks at Production Wells

Pollutant

Light Oil Gas Total

Weight1 lb/well-hr lb/well-yr Fraction of TOC2 lb/well-hr lb/well-yr tpy/well

Benzene 1.55% 0.002 19 2.30E-04 8.5E-06 0.07 0.01

Toluene 4.72% 0.007 59 3.90E-04 1.4E-05 0.13 0.03

Ethylbenzene 0.44% 0.0006 5.5 2.00E-05 7.4E-07 0.006 0.003

Xylene 7.45% 0.01 93 1.00E-03 3.7E-05 0.32 0.05

Formaldehyde 3.06% 0.004 38 0.00 0.00 0.00 0.02

n-Hexane No data 1 Fugitive HAPs Weight % of TOC is from condensate analysis.

2 Fugitive HAPs Fraction of TOC is from WDEQ 2007.

3.5.4 Production Traffic

Each well would be serviced by well operators in light duty vehicles as well as water tank trucks collecting 

produced water. Emissions factors for PM10 and PM2.5 emissions from the unpaved roadways were developed 

from Equation 1a in Section 13.2.2 of AP-42 (USEPA 2006a) for industrial sites, as shown in Equation 3-3. 

Emissions factors for PM10 and PM2.5 from light duty vehicle traffic on publicly accessible unpaved roads were 

developed using Equation 1b in Section 13.2.2 of AP-42 (USEPA 2006a), as shown in Equation 3-4. Silt 

loading was assumed to be 5.1 percent based on AP-42 as described in Section 3.4.2 and a moisture content 

of 2.4 percent as discussed in Section 3.4.2. A summary of traffic PM emissions is provided in Table 3-33. 
3-29 March 2012

Table 3-33 PM Emissions from Unpaved Roads for Production Traffic per Operational Well

Vehicle Type

Dust

Control

Method

Mean

Weight

Mean

Speed

Moisture

Content

Estimated

Round

Trips

Round

Trip

Distance

Vehicle

Miles

Traveled

Uncontrolled 

PM10 Emission

Factor

Uncontrolled 

PM2.5 Emission

Factor

Control

Efficiency

Controlled

PM10

Emissions

Controlled

PM2.5

Emissions

(ton) (mph) (%) (round trip/well-yr) (miles) (VMT/well-yr) (lb/VMT) (lb/VMT) (%) (lb/well-yr) (lb/well-yr)

Heavy Trucks

Chemical

27.0 N/A N/A

365 1.3 474.5 1.87 0.29 85 132.85 20.37

Water 365 0.1 36.5 1.87 0.29 50 34.07 5.22

Light Trucks

Chemical

N/A

35

2.4

156 2.6 405.6 0.60 0.09 85 36.71 5.49

Water 20 156 0.3 46.8 0.46 0.07 50 10.67 1.59

Total 214.30 32.68
3-30 March 2012

Emissions of criteria pollutants from tanker traffic also was included due to the volume of tanker traffic per well. 

Emissions factors for tanker truck hauling were taken from AP-42 for mobile sources (USEPA 1995a) for high 

altitude heavy vehicle traffic identical to the factors applied in Table 3-25. A summary of hauling emissions is 

provided in Table 3-34. Table 3-34 also demonstrates that criteria pollutant emissions are negligible for 

production traffic for NOX, CO, SO2, and VOC.

Table 3-34 Criteria Pollutant Emissions from Tanker Truck Traffic

Tanker Truck Round Trips = 365 round trips/well

Round Trip Distance = 1.4 miles/round trip

Distance = 511 VMT/well

Emission Factor Emission Rate

Pollutant (g/VMT) (lb/well)

NOX 6.5 7.32

CO 18.2 20.50

SO2 0.18 0.20

VOC 4.7 5.29

3.5.5 Summary

The emissions of criteria pollutants per well installed are summarized in Table 3-35. Note that when PM2.5

emission factors were not available, PM10 is used as a surrogate.

Table 3-35 Summary of Criteria Pollutant Emissions for Production Wells

Criteria Pollutant Emissions (tpy per well)

Activity – New Well NOX CO SO2 PM10 PM2.5 VOC

Condensate Flashing - New Well - - - - - 4.2

Separator Heaters 0.12 0.097 0.0039 0.0088 0.0088 0.0063

Fugitive Emissions - - - - - 0.62

Production Traffic - - - 0.1 0.016 -

Production Traffic (Tailpipe) 0.0037 0.01 0.0004 - - 0.0026

Total 0.12 0.11 0.0043 0.11 0.025 4.9

Activity – Old Well

Condensate Flashing - Old Well 1.3

Separator Heaters 0.12 0.097 0.0039 0.0088 0.0088 0.0063

Fugitive Emissions - - - - - 0.62

Production Traffic - - - 0.1 0.016 -

Production Traffic (Tailpipe) 0.0037 0.01 0.0004 - - 0.0026

Total 0.121 0.1 0.0043 0.11 0.025 1.9

Hazardous Air Pollutant Emissions (tpy per well)

Activity – New Well Benzene Toluene Ethyl Benzene Xylene Formaldehyde n-Hexane

Condensate Flashing - New Well 0.034 0.073 0.002 0.029 - 0.124

Separator Heaters 2.42E-06 3.92E-06 - - 8.64E-05 0.002

Fugitive Emissions 0.010 0.030 0.003 0.047 - 0.019

Total 0.044 0.103 0.005 0.076 8.64E-05 0.145

Activity – New Well Benzene Toluene Ethyl Benzene Xylene Formaldehyde n-Hexane

Condensate Flashing - Old Well 0.010 0.022 0.001 0.009 - 0.037

Separator Heaters 2.42E-06 3.92E-06 - - 8.64E-05 0.002

Fugitive Emissions 0.010 0.030 0.003 0.047 - 0.019

Total 0.020 0.052 0.004 0.056 8.64E-05 0.058
3-31 March 2012

3.6 Operation Emissions

The Proposed Action and Optimal Recovery Alternative would include the installation and operation of facilities 

to manage produced water and provide gas compression. Produced water would be gathered by a gathering 

and transport pipeline system as well as tanker trucks, delivered to several central tank batteries for storage 

and additional condensate separation, and then transported to several injection wells for disposal into aquifers

as well as to evaporation ponds.

3.6.1 Water Tank Battery Operation

It was assumed that the tank batteries would use 2,900 bbl tanks for storing produced water, which includes 

some small amount of condensate in non-aqueous phase. As the produced water is drawn from these tanks, 

the remaining condensate would be piped to 1,500 bbl tanks for recovery. Emissions of VOC in both sets of 

tanks would result from both the standing evaporation losses and working losses from emptying or filling these 

tanks. These emissions were estimated using USEPA TANKS 4.09, which implements the procedures in 

AP-42, Chapter 7.1 for Liquid Storage Tanks (USEPA 2006b).

To accurately predict emissions, TANKS 4.09 requires physical characteristic data for the stored material. 

Since VOC emissions from the produced water result from the non-aqueous layer on top of the total fluid, the 

non-aqueous condensate properties were used to estimate emissions from both non-aqueous condensate and 

produced water tanks. The condensate analysis from E&P Tanks Version, as discussed in Section 3.5.1 and 

presented in Appendix B, was used to determine the necessary physical properties, which are shown in 

Table 3-36.

Table 3-36 Physical Properties of Tank Condensate

Parameter Value

Vapor Molecular Weight (lb/lb-mol) 36.24

Liquid Molecular Weight (lb/lb-mol) 110.68

Liquid Density (lb/gal) 5.71

Liquid Reid Vapor Pressure (psia) 7.25

Based on data provided by KMG, produced water would be generated at a rate of 90 bbl/MMscf of gas 

production. As stated in Section 3.5.1, new wells would produce 10 bbls of condensate per day and old wells 

would produce 3 bbls/day. The sum of this production distributed over the tank batteries and tanks determines 

the total throughput to each tank for emissions calculations. Eight water tank batteries are included in the 2018 

Projected Baseline as approved actions, and KMG proposes to install 2 more as part of Proposed Action or 

5 more as part of the Optimal Recovery Alternative. A summary of throughput calculation data and 

assumptions is provided in Table 3-37. The output from TANKS 4.09 for each alternative is provided in 

Appendix B. 

Additionally, KMG has committed to installing controls capable of 95 percent reduction on sources exceeding 

20 tpy of uncontrolled VOC emissions. Therefore, a control efficiency of 95 percent was applied since the 

aggregate emissions from every battery exceed this threshold. Total VOC emissions from each water tank 

battery are summarized in Table 3-38. Table 3-38 also summarizes the emissions of selected HAP from water 

tank batteries. 

HAP emissions were calculated based on the mass fraction of the selected HAP of the condensate as TOC. 

This mass fraction was taken from the condensate analytical information provided in Table 3-28. Since 

TANKS calculates emissions as VOC, the TANKS data were converted to TOC by multiplying by 1.13, which 

is the ratio of TOC to VOC based on the data in Table 3-28. 
3-32 March 2012

Table 3-37 Produced Water and Condensate Throughput for Water Tank Batteries

Parameter Unit Proposed Action Optimal Recovery Alternative

Produced Water

Peak Field Production Bscf/yr 318.9 616.7

Water Production bbl/MMscf 90 90

MMbbl/yr 28.7 55.5

Number of Tank Batteries 10 13

Number of Tanks per Battery 4 4

Tank Capacity bbl/tank 2,900 2,900

Tank Turnovers turnovers/yr 247.4 368.1

Condensate

New Wells wells 336 672

Old Wells wells 3,339 12,774

New Well Production bbl/well-day 10 10

Old Well bbl/well-day 3 3

Condensate Production MMbbl/yr 4.88 16.44

Number of Tanks per Battery 2 4

Tank Capacity bbl/tank 1,500 1,500

Tank Turnovers turnovers/yr 162.8 210.8

Table 3-38 VOC and HAP Emissions from Water Tank Batteries

VOC Emissions

Parameter Unit Proposed Action Optimal Recovery Alternative

Produced Water

Working Losses lb/tank-yr 28,460.10 36,497.38

Breathing Losses lb/tank-yr 10,485.43 10,485.43

VOC Emissions (per tank) ton/tank-yr 19.5 23.5

Tanks per Battery tanks/battery 4 4

VOC Emissions (per battery) ton/battery-yr 77.9 94.0

Condensate (per tank)

Working Losses lb/tank-yr 11,806.90 13,460.14

Breathing Losses lb/tank-yr 6,758.09 6,758.09

VOC Emissions (per tank) ton/tank-yr 9.3 10.1

Tanks per Battery tanks/battery 2 4

VOC Emissions (per battery) ton/battery-yr 18.6 40.4

Uncontrolled VOC Emissions ton/battery-yr 96.5 134.4

Control Efficiency % 95% 95%

Controlled VOC Emissions ton/battery-yr 4.8 6.7

Hazardous Air Pollutant Emissions

Pollutant Unit Proposed Action Optimal Recovery Alternative

TOC ton/battery-yr 5.5 7.6

Benzene %wt 2.15% 2.15%

ton/battery-yr 0.12 0.16

Toluene %wt 2.20% 2.20%

ton/battery-yr 0.12 0.17

Ethylbenzene %wt 0.08% 0.08%

ton/battery-yr 0.0043 0.0060

Xylene %wt 1.19% 1.19%

ton/battery-yr 0.065 0.090

n-Hexane %wt 4.72% 4.72%

ton/battery-yr 0.26 0.36
3-33 March 2012

3.6.2 Water Injection Facility Operation

Each water injection facility would be equipped with a gas-fired engine to drive the injection pumps. For 

purposes of this analysis, these engines were estimated at 650 hp each and assumed to operate continuously. 

Emissions factors for NOX, CO, and VOC were taken from the New Source Performance Standard, Subpart 

JJJJ for non-emergency gas-fired engines greater than 500 hp (Table 1, 40 CFR 60.4231) manufactured after 

July 1, 2010. Emission factors for SO2 were derived from fuel sulfur content as shown in Equation 3-6. PM10

emission factors were taken from AP-42, Table 3.2-2 (USEPA 2000). Additionally, emissions of CO and VOC 

would be controlled by an oxidation catalyst reducing emissions by 93 and 50 percent, respectively. Emissions 

of criteria pollutants (excluding PM10) were the product of the emission factor, engine size, and operating time. 

Emissions for PM10 were the product of the emission factor, fuel use, and operating time. Criteria pollutant 

emissions from individual water injection engines are shown in Table 3-39. HAP emission factors were taken 

from AP-42, Table 3.2-2 (USEPA 2000).

Equation 3-6 SO2 Emissions Factor from Combustion of Fuel Gas in Engines

Table 3-39 Criteria Pollutant Emissions from Water Injection Engines

Annual Operating Hours = 8,760

Heat Content = 950 Btu/scf

Fuel Sulfur Content = 0.012 gr/scf

Rated Engine Size = 650 bhp

Fuel Consumption = 4.55 MMBtu/hr

Pollutant Emission Factor

Control Efficiency Emission Rate

(%) (lb/hr) (tpy)

NOX 1.00 g/hp-hr -- 1.43 6.28

CO 2.00 g/hp-hr 93 0.20 0.88

SO2 0.000025 lb/hp-hr -- 0.02 0.07

PM10 0.01 lb/MMBtu -- 0.05 0.20

VOC 0.70 g/hp-hr 50 0.37 1.64

Benzene 0.0004 lb/MMBtu 50 0.001 0.004

Toluene 0.0004 lb/MMBtu 50 0.0009 0.004

Ethylbenzene 0.00004 lb/MMBtu 50 0.00009 0.0004

Xylene 0.0002 lb/MMBtu 50 0.0004 0.002

Formaldehyde 0.05 lb/MMBtu 50 0.12 0.53

n-Hexane 0.001 lb/MMBtu 50 0.003 0.01

3.6.3 Gas-fired Compression Engines

The Proposed Action and Optimal Recovery Alternative both would include the installation of additional 

gas-fired compression to transport the increase in field production. For this analysis, the additional 

compression will be provided by gas-fired engines of three sizes (1,265 hp, 1,340 hp, and 2,370 hp). 

Emissions factors for NOX, CO, and VOC were taken from manufacturer specifications as provided in 

Appendix B. Emission factors for SO2 were derived from fuel sulfur content as shown in Equation 3-6. 

Emission factors for PM10 were taken from AP-42, Table 3.2-2 (USEPA 2000). Emissions of criteria pollutant 

per engine are shown in Tables 3-40, 3-41, and 3-42. A listing of additional compression engines at each site 

for both the Proposed Action and Optimal Recovery Alternative, as well as the total emissions for each facility 

by alternative are summarized in Tables 3-43 and 3-44. HAP emissions factors were taken from AP-42, 

Table 3.2-2 for four-stroke lean burn engines. Emissions of HAP were calculated as the product of these 

x lb hp hr

mwS

mwSO

x

gr

lb

x

hp hr

Btu

x

Btu

scf fuel x

scf fuel

gr S EFSO = − − = − 2.52 10 /

7,000

7,000

950

0.012 5 2

2
3-34 March 2012

emission factors and the total proposed hp of gas-fired compression. Table 3-45 and Table 3-46 summarize 

total HAP emissions from gas-fired compression for each alternative.

Table 3-40 Criteria Pollutant Emissions from Gas-fired Compression Engines (1,265 hp)

Annual Operating Hours = 8,760

Heat Content = 950 Btu/scf

Fuel Sulfur Content = 0.012 gr/scf

Rated Engine Size = 1,265 bhp

Fuel Consumption = 8.9 MMBtu/hr

Pollutant Emission Factor1

Control Efficiency Emission Rate

(%) (lb/hr) (tpy)

NOX 1.50 g/hp-hr -- 4.2 18.3

CO 2.42 g/hp-hr 93 0.5 2.1

SO2 0.000023 lb/hp-hr -- 0.03 0.1

PM10 0.01 lb/MMBtu -- 0.09 0.4

VOC 0.56 g/hp-hr 50 0.8 3.4

1 Emissions factors for NOX, CO, and VOC for CAT Model G3516 LE, see Appendix B.

Table 3-41 Criteria Pollutant Emissions from Gas-fired Compression Engines (1,340 hp)

Annual Operating Hours = 8,760

Heat Content = 950 Btu/scf

Fuel Sulfur Content = 0.012 gr/scf

Rated Engine Size = 1,340 bhp

Fuel Consumption = 9.4 MMBtu/hr

Pollutant Emission Factor1

Control Efficiency Emission Rate

(%) (lb/hr) (tpy)

NOX 1.50 g/hp-hr -- 4.4 19.4

CO 2.42 g/hp-hr 93 0.5 2.2

SO2 0.000023 lb/hp-hr -- 0.031 0.1

PM10 0.01 lb/MMBtu -- 0.09 0.4

VOC 0.56 g/hp-hr 50 0.8 3.6

1 Emissions factors for NOX, CO, and VOC for CAT Model G3516 LE, see Appendix B.

Table 3-42 Criteria Pollutant Emissions from Gas-fired Compression Engines (2,370 hp)

Annual Operating Hours = 8,760

Heat Content = 950 Btu/scf

Fuel Sulfur Content = 0.012 gr/scf

Rated Engine Size = 2,370 bhp

Fuel Consumption = 16.59 MMBtu/hr

Pollutant Emission Factor1

Control Efficiency Emission Rate

(%) (lb/hr) (tpy)

NOX 0.7 g/hp-hr -- 3.66 16.02

CO 2.5 g/hp-hr 93 0.89 3.88

SO2 0.000023 lb/hp-hr -- 0.06 0.24

PM100.01 9.99E-3 lb/MMBtu -- 0.17 0.73

VOC 0.83 g/hp-hr 50 1.46 6.41

1 Emissions factors for NOX, CO, and VOC for CAT Model G3608 LE, see Appendix B.
3-35 March 2012

Table 3-43 Summary of Criteria Pollutant Emissions from Gas-fired Compression for the Proposed Action 

Station

Additional Engines Proposed Criteria Pollutant Emissions (tpy)

1,265 hp 1,340 hp 2,370 hp NOX CO SO2 PM10 VOC

Antelope Flats -- 3 -- 58.2 6.6 0.4 1.2 10.9

Archie Bench -- 4 -- 77.6 8.8 0.5 1.6 14.5

Bitter Creek -- 1 -- 19.4 2.2 0.1 0.4 3.6

Blue Feather -- 2 -- 38.8 4.4 0.3 0.8 7.2

Bonanza East -- 2 -- 38.8 4.4 0.3 0.5 7.2

Bonanza West -- 3 -- 58.2 6.6 0.4 1.2 10.9

Bridge -- 2 -- 38.8 4.4 0.3 0.8 7.2

Cottonwood/West 3 -- 1 1 35.4 6.1 0.4 1.1 10.0

Diablo -- -- 4 64.1 16.0 1.0 2.9 38.0

East -- 1 -- 19.4 2.2 0.1 0.4 3.6

Love -- 2 -- 38.8 4.4 0.3 0.8 7.2

North Ouray -- 2 -- 38.8 4.4 0.3 0.8 7.2

Ouray -- 3 1 74.2 10.5 0.7 2.0 17.3

Rimer Canyon -- 6 -- 116.5 13.2 0.8 2.5 21.7

Sage Grouse -- 2 -- 38.8 4.4 0.3 0.8 7.2

Sand Wash -- 1 -- 19.4 2.2 0.1 0.4 3.6

South 1 -- -- 18.3 2.1 0.1 0.4 3.4

White River -- 3 2 90.3 14.3 0.9 2.7 23.7

Willow Creek -- 3 1 74.2 10.5 0.7 2.0 17.3

Total 1 45 5 958.3 127.3 8.0 23.7 222.0
3-36 March 2012

Table 3-44 Summary of Criteria Pollutant Emissions from Gas-fired Compression for the Optimal Recovery Alternative

Station

Additional Engines Proposed Criteria Pollutant Emissions (tpy)

1,265 hp 1,340 hp 2,370 hp NOX CO SO2 PM10 VOC

Antelope Flats -- 5 -- 97.0 11.0 0.7 2.1 18.1

Archie Bench -- 5 -- 97.0 11.0 0.7 2.1 18.1

Bitter Creek -- 5 -- 97.0 11.0 0.7 2.1 18.1

Blue Feather -- 5 -- 97.0 11.0 0.7 2.1 18.1

Bonanza East -- 5 -- 97.0 11.0 0.7 2.1 18.1

Bonanza West -- 5 -- 97.0 11.0 0.7 2.1 18.1

Bridge -- 5 -- 97.0 11.0 0.7 2.1 18.1

Cottonwood/West 3 -- 2 5 118.9 23.8 1.5 4.4 39.3

Diablo -- -- 8 128.2 32.0 1.9 5.8 76.0

East -- 5 -- 97.0 11.0 0.7 2.1 18.1

Love -- 5 -- 97.0 11.0 0.7 2.1 18.1

North Ouray -- 5 -- 97.0 11.0 0.7 2.1 18.1

Ouray -- 4 5 157.7 28.2 1.8 5.3 46.5

Rimer Canyon -- 6 -- 116.5 13.2 0.8 2.5 21.7

Sage Grouse -- 5 -- 97.0 11.0 0.7 2.1 18.1

Sand Wash -- 5 -- 97.0 11.0 0.7 2.1 18.1

South 2 -- -- 36.6 4.1 0.3 0.8 6.8

White River -- 3 6 154.3 29.8 1.9 5.6 49.3

Willow Creek -- 3 5 138.3 26.0 1.6 4.9 42.9

Total 2 86 21 2,015.1 288.6 18.0 53.8 500.0
3-37 March 2012

Table 3-45 Summary of HAPs from Gas-Fired Compression for the Proposed Action 

Annual Operating Hours = 8,760

Total Proposed Compression = 73,415 bhp

Fuel Consumption = 513.9 MMBtu/hr

Pollutant Emission Factor1

Control Emission Rate

Efficiency (lb/hr) (tpy)

Benzene 0.0004 lb/MMBtu 50% 0.11 0.50

Toluene 0.0004 lb/MMBtu 50% 0.10 0.46

Ethylbenzene 0.00004 lb/MMBtu 50% 0.01 0.04

Xylene 0.0002 lb/MMBtu 50% 0.05 0.21

Formaldehyde 0.05 lb/MMBtu 50% 13.57 59.42

n-Hexane 0.001 lb/MMBtu 50% 0.29 1.25

1 USEPA 2000.

Table 3-46 Summary of HAPs from Gas-Fired Compression for the Optimal Recovery Alternative

Annual Operating Hours = 8,760

Total Proposed Compression = 167,540 bhp

Fuel Consumption = 1172.8 MMBtu/hr

Pollutant Emission Factor1

Control Emission Rate

Efficiency (lb/hr) (tpy)

Benzene 0.0004 lb/MMBtu 50% 0.26 1.13

Toluene 0.0004 lb/MMBtu 50% 0.24 1.05

Ethylbenzene 0.00004 lb/MMBtu 50% 0.02 0.10

Xylene 0.0002 lb/MMBtu 50% 0.11 0.47

Formaldehyde 0.05 lb/MMBtu 50% 30.96 135.61

n-Hexane 0.001 lb/MMBtu 50% 0.65 2.85

1 USEPA 2000.

3.7 Modeling Inventory Development for Project Alternatives

Sections 3.3 through 3.6 describe the annual emissions for each alternative per activity. However, the 

additional emissions from each project alternative must be calculated for the peak production year activity and 

spatially distributed throughout the GNBPA for modeling. The peak production year for the Proposed Action 

would be 2017, and for the Optimal Recovery Alternative it would be 2026. For the project alternatives, it was 

assumed that all wells proposed are operating at normal capacity excluding the final year of wells drilled. The 

wells drilled were assumed to be operating for part of the year and producing condensate at a higher rate. This 

reflects the last ongoing year of drilling emissions and the maximum operational emissions.

Under the Proposed Action, it was assumed that a fleet of 15 rigs would be operating, drilling an average of 

two producing wells per month, while the Optimal Recovery drilling would require 28 rigs drilling at the same 

rate. It was assumed that 3 percent of these wells would be dry, resulting in additional drilling emissions. 

As described earlier, total emissions for production and drilling activity were the product of the proposed 

activity level and the emissions per activity. Finally, these emissions were spatially distributed for each 

alternative to specific township, range, and section based on the predicted activity in each section. The 

emissions per section for each alternative are summarized in Appendix C. These emissions are in addition to 

the compression emissions shown in Tables 3-43 and 3-44. Location of compression emissions are 

summarized in Chapter 4.0. Tables 3-47 through 3-50 summarize the total project emissions (criteria pollutant 

and HAP) for each alternative, based on the summary of emissions provided in Tables 3-26, 3-35, 3-37, 3-39, 

3-44, and 3-45.
3-38 March 2012

For the analysis conducted for the Draft EIS, it was assumed that a fleet of 14 rigs would operate under 

the Proposed Action. For the Supplement to the Draft EIS, the number of operating rigs was increased

to 15 for the Proposed Action. This adjustment was due to a small change to the drilling schedule for 

this alternative. Consequently, the increase in the number of operating rigs resulted in a decrease in 

the number of producing wells in the inventory as well as a material increase in NOX and CO. The NOX

increased 142.1 tpy (6.8 percent), while CO increased 144.4 tpy (12.5 percent). The change in other 

criteria pollutants and HAPs were inconsequential.
3-39 March 2012

Table 3-47 Summary of Criteria Pollutant Emissions for the Proposed Action 

Activity

Scenario Description 2017 Annual Emissions (tpy)

Project 2017 2018 NOX CO SO2 PM10 PM2.5 VOC

Drilling Activities

Wellbores Drilled (Producing) 3,675 360 0 755.5 782.0 2.0 589.9 94.4 53.3

Wellbores Drilled (Non-producing) 91 11 0 23.1 23.9 0.1 10.1 1.7 1.7

Total Drilling Emissions1 778.6 805.9 2.0 600.0 96.1 54.9

Production and Operation Activities

Producing Wells (above baseline) 3,675 3,315 3,675 394.2 354.9 14.2 384.2 83.2 6,309.4

Compression Engines 958.3 127.3 8.0 23.7 23.7 222.0

Water Tank Batteries Operating 2 2 2 0.0 0.0 0.0 0.0 0.0 9.6

Water Injection Facilities Operating 15 13 15 81.6 11.4 0.9 2.6 2.6 21.3

Total Production and Operating Emissions1 1,434.1 493.7 23.0 410.6 109.5 6,562.3

Total Project Emissions1 2,212.7 1,299.6 25.0 1,010.6 205.7 6,617.3 1 Totals may vary slightly due to rounding.

Table 3-48 Summary of Criteria Pollutant Emissions for Optimal Recovery Alternative

Activity

Scenario Description 2026 Annual Emissions (tpy)

Project 2026 2027 NOX CO SO2 PM10 PM2.5 VOC

Drilling Activities

Wellbores Drilled (Producing) 13,446 672 0 1,230.2 1,279.6 3.4 1,100.0 175.3 89.8

Wellbores Drilled (Non-producing) 384 20 0 36.6 38.1 0.1 18.4 3.0 2.7

Total Drilling Emissions 1,266.8 1,317.7 3.5 1,118.5 178.3 92.5

Production and Operation Activities

Producing Wells (above baseline) 13,446 12,774 13,446 1,519.1 1,367.7 54.8 1,480.6 320.6 24,312.6

Compression Engines 2,015.1 288.6 18.0 53.5 53.5 500.0

Water Tank Batteries Operating 5 5 5 0.0 0.0 0.0 0.0 0.0 33.6

Water Injection Facilities Operating 25 23 25 144.4 20.2 1.5 3.7 3.7 37.7

Total Production and Operating Emissions 3,678.6 1,676.6 74.3 1,691.3 531.3 24,883.9

Total Project Emissions 4,945.9 2,994.4 77.8 2,656.6 556.4 24,976.3
3-40 March 2012

Table 3-49 Summary of Hazardous Air Pollutant Emissions for the Proposed Action 

Activity

Scenario Description 2017 Annual Emissions (tpy)

Project 2017 2018 Benzene Toluene Ethyl Benzene Xylene Formaldehyde n-Hexane

Drilling Activities

Wellbores Drilled (Producing) 3,675 360 0 0.8 0.6 0.1 0.4 4.6 0.06

Wellbores Drilled (Non-producing) 91 11 0 0.02 0.02 0.004 0.01 0.1 0.002

Total Drilling Emissions1 0.8 0.6 0.1 0.4 4.8 0.06

Production and Operation Activities

Producing Wells (above baseline) 3,675 3,315 3,675 65.3 171.0 12.5 184.9 0.3 192.9

Compression Engines 0.5 0.5 0.04 0.2 59.4 1.2

Water Tank Batteries Operating 2 2 2 0.2 0.2 0.009 0.1 0.0 0.5

Water Injection Facilities Operating 15 13 15 0.06 0.05 0.005 0.02 6.8 0.1

Total Production and Operating Emissions1 66.1 171.8 12.5 185.3 66.5 194.8

Total Project Emissions1 67.0 172.4 12.7 185.7 71.3 194.9 1 Totals may vary slightly due to rounding.

Table 3-50 Summary of Hazardous Air Pollutant Emissions for Optimal Recovery Alternative

Activity

Scenario Description 2026 Annual Emissions (tpy)

Project 2026 2027 Benzene Toluene Ethyl Benzene Xylene Formaldehyde n-Hexane

Drilling Activities

Wellbores Drilled (Producing) 13,446 672 0 1.3 1.1 0.2 0.7 7.5 0.1

Wellbores Drilled (Non-producing) 384 20 0 0.04 0.04 0.006 0.02 0.2 0.003

Total Drilling Emissions 1.3 1.2 0.2 0.7 8.7 0.1

Production and Operation Activities

Producing Wells (above baseline) 13,446 12,774 13,446 251.8 658.9 48.1 712.5 1.1 743.5

Compression Engines (bhp) 167,540 1.1 1.0 0.1 0.5 135.6 2.9

Water Tank Batteries Operating 5 5 5 0.8 0.8 0.003 0.5 - 1.8

Water Injection Facilities Operating 25 23 25 0.1 0.09 0.009 0.04 12.1 0.3

Total Production and Operating Emissions 253.9 660.9 48.3 713.5 148.8 748.4

Total Project Emissions 255.2 662.1 48.5 714.1 156.5 748.5
4-1 March 2012

4.0 Modeling Procedures

Meteorological data for regional atmospheric modeling were developed for 2 meteorological years, 2005 and

2006. This period was utilized due to the availability of concurrent and representative emissions data and 

meteorological databases. The modeling analysis used three atmospheric dispersion models to evaluate 

impacts and changes in impacts to air quality and other related AQRVs (i.e., regional haze, acidic deposition, 

and acid neutralizing capacity) resulting from increased development in the Uinta Basin. The modeling 

consisted of the following analyses/models:

• CALPUFF – to assess project development and cumulative impacts on air concentrations and other 

AQRVs at Class I and sensitive Class II areas within the modeling domain using 2006 meteorological 

data only;

• CMAQ – to assess cumulative impacts on ozone concentrations in the surrounding areas using 2005 

and 2006 meteorological data; and

• AERMOD – to assess near-field project development impacts on local air concentrations within 2 km 

of the development, using 5 years of meteorological data (2002 through 2006).

4.1 CALPUFF Modeling

The CALPUFF modeling system (Scire et al. 2000a,b) was promulgated on April 15, 2003, and is USEPA’s 

preferred/recommended model for long-range transport beyond 50 km. When appropriate, the modeling 

procedure followed recommendations in the Interagency Workgroup on Air Quality Modeling (IWAQM) and 

FLAG documents for the assessment of impacts (USEPA 1998a; FLAG 2000). Consideration also was given 

to the modeling procedures described in the draft FLAG 2008 guidance specifically pertaining to the regional 

haze analysis techniques. This analysis used the current USEPA-approved version of the CALPUFF modeling 

suite (Version 5.8) to address air quality impacts and AQRVs.

The CALPUFF modeling consisted of three different model simulations: Run 1 (Baseline 2018) was the 

baseline modeled year (2018 project WRAP III/WRAP II inventory) without the project-specific emissions from 

the proposed project; Run 2 (Proposed Action) was a combination of Run 1 along with the future Proposed 

Action project emissions for the year 2017; and Run 3 (Optimal Recovery Alternative) was similar to Run 2 

with a different project emission scenario that maximizes the recovery of oil and natural gas. Under the 

Proposed Action, the year 2017 is projected to have combined maximum production emissions in addition to 

construction emissions for the GNBPA.

4.1.1 Model Options and Computational Domain

Since CALPUFF is a Lagrangian puff model with the capability to simulate regional-scale, long-range 

dispersion as well as local-scale, short-range dispersion (Scire et al. 2000a), the CALPUFF modeling system 

was used for assessing impacts from the proposed development within the GNBPA at the identified Class I 

and sensitive Class II areas.

The CALPUFF modeling system has three main components:

• CALMET Version 5.8, Level 070623 (a diagnostic three-dimensional meteorological model, which 

develops the meteorological data for modeling input);

• CALPUFF Version 5.8, Level 070623 (the transport and dispersion model that carries out calculations 

of dispersion); and 

• CALPOST Version 5.6394, Level 070622 (a post-processing package that is used to depict overall 

concentrations and impacts).
4-2 March 2012

The CALPUFF modeling system has several unique features that, given the objectives of the study, make it 

suited to carry out the required atmospheric dispersion modeling for this study. Those features include:

• Time-varying point, volume, and area source emissions; 

• Model domains at distances from tens of meters to hundreds of kilometers from the sources;

• Averaging times from 1 hour to 1 year;

• Impact prediction for inert pollutants that are not chemically reactive in the atmosphere;

• Impact prediction for pollutants that may be subject to removal (i.e., wet scavenging and gravitational 

settling) and chemical conversion mechanisms; and

• Applications in rough and flat terrain situations. 

The modeling domain for this study was designed to closely resemble the CMAQ 12-km domain. This domain 

incorporated the GNBPA along with Class I and sensitive Class II area locations within approximately 200 to 

250 km of sources within the GNBPA. The domain included a majority of Utah and western Colorado along 

with portions of Wyoming, Arizona, and New Mexico (Figure 4-1). The spatial extent of the domain was 

672 km (east-west) x 552 km (north-south). The design allowed for 168 x 138 grid cells and a 4-km grid 

element size. That size domain required the use of a Lambert Conformal Projection (LCP) grid system as 

follows: 

• Central reference LCP point longitude, latitude = (-97.0° W, 40.0° N); 

• Standard latitude parallels at 33° N and 45° N; and 

• Grid origin (southwest corner) offset from central reference point = (-1392 km, -312 km).

The IWAQM recommended default settings were used when they were consistent with the current version of 

CALPUFF. Thus, the default dry and wet deposition algorithms were used. In addition, the following CALPUFF 

options also were selected:

• Pasquill-Gifford (P-G) dispersion coefficients;

• Transitional plume rise;

• Stack tip downwash;

• Transition of horizontal dispersion to time-dependent (Heffter) growth rates;

• Chemical transformation based on MESOPUFF II scheme; and

• Wet and dry deposition modeling.

4.1.2 Assessment Areas and Receptor Grids

The receptor grids for the Class I areas for this assessment were based on the NPS national database. For 

those sensitive areas that were not contained in the NPS database of receptors, receptor sets were developed 

within the sensitive area’s boundary from the existing grid of receptors. The elevations of these receptors were 

derived using Digital Elevation Model (DEM) data for the 1:250,000 quads with 90-m horizontal resolution 

(U.S. Geological Survey [USGS] 2000). Table 2-5 lists each of the Class I areas and sensitive Class II areas 

of concern within the modeling domain and included in the analysis. Figure 4-1 also shows the location of 

each area in relation to the GNBPA.
4-3 March 2012

Figure 4-1 Modeling Domain and Location of Class I and Class II Receptors
4-4 March 2012

4.1.3 CALPUFF Emission Inputs

The project emission inputs to CALPUFF are provided in Appendix D. The background source inventory used 

as inputs to CALPUFF were developed based on the output of SMOKE (also used as input to CMAQ). The 

development of these emissions is discussed in Chapter 3.0. Two source types modeled from the SMOKE 

output were area sources and point sources.

The area source emissions were based on the total emissions within each CMAQ 12-km grid box. Before input 

to CALPUFF, some of these grid boxes were merged based upon their location in proximity to a Class I or 

Class II area of concern to reduce the number of sources. Figure 4-2 shows the point and area sources used 

as input to CALPUFF throughout the modeling domain for the 2018 Projected Baseline. 

The SMOKE point source emissions must be consolidated due to the large number of point sources in the 

WRAP Phase II/Phase III Inventory. Sources were consolidated based on the following methodology:

• For point sources with total facility NOX, SO2, and PM10 emissions greater than 100 tpy, a weighted 

average point source for each facility was derived. The weighting was done based on the sum of NO2, 

SO2, and PM10 emissions for each point relative to the sum of the SO2, NO2, and PM10 emissions for 

the entire facility. The resulting weighted average point source for each facility included the total sum 

of all the facility emissions released through a weighted average location along with weighted average 

release parameters. Thus, the modeled source had the location and release parameters consistent 

with the facility source that had the greatest total emissions of NOX, SO2, and PM10.

• For point sources with total facility NOX, SO2, and PM10 emissions less than 100 tpy, a weighted 

average point source for each facility also was derived using the same procedure described above for 

the facilities with greater than 100 tpy emissions. However, additional consolidating was applied for 

the sources with facility total emissions less than 100 tpy of combined NOX, SO2, and PM10. These 

sources were further consolidated based on location on the modeling domain. For sources that fell 

within the same 12-km grid box, these sources were consolidated using the same procedures 

discussed above. Figure 4-2 shows the consolidated points sources used as input to CALPUFF. 

Appendix D provides the emissions source inventory used as input to CALPUFF along with some of 

the steps in the consolidation process.

This source consolidation procedure conserved the total emissions throughout the analysis. As a result, even 

though the number of sources was lower in the CALPUFF inputs as compared to the SMOKE output (the 

CMAQ input), the total emissions being modeled for NOX, SO2, and PM10 were the same. Since the CALPUFF 

modeling does not consider CO or VOC, point sources emitting these pollutant(s) were excluded from the 

analysis. 

4.1.4 CALMET Processing and Meteorological Data Development

CALMET, one of the three main components of the CALPUFF modeling system, includes a diagnostic wind 

model that combines surface and upper-air meteorological data with diagnostic effects of terrain and other 

factors to generate three-dimensional wind fields (Scire et al. 2000b). It also includes other interpolation 

algorithms that generate three-dimensional temperature, pressure, and other meteorological variables and 

two-dimensional precipitation fields. For areas with complex terrain and sparse wind observations, a diagnostic 

wind model cannot accurately depict the complex flow fields by using surface observation data alone. In those 

situations, CALMET defines the synoptic-scale flow features by using the output from a coarse grid (12- or 

36-km) resolution simulation of a prognostic meteorological model (e.g., MM5) to better characterize the local 

wind variations at a finer scale (e.g., 4 km) by using its diagnostic wind algorithms and local surface 

observations. For this analysis, CALMET was used to derive hourly three dimensional meteorological data 

fields for 1 year (2006). The meteorological database was developed using a 4- by 4-km grid resolution.
4-5 March 2012

Figure 4-2 2018 CALPUFF Modeled Point and Area Sources
4-6 March 2012

The meteorological data were developed in a series of steps. The Step 1 wind field was developed by using 

2006 MM5 data available at 12-km resolution combined with 4-km terrain and land use defined throughout the 

modeling domain. The terrain and land use data were developed from USGS 1:250,000 DEM and 1:250,000 

Composite Theme Grid files. Additional surface (from both primary and secondary observation stations –

including CASTNET meteorology) and upper-air meteorological data were used in the production of the Step 2 

wind field. Precipitation data and other meteorological variables (i.e., temperature, relative humidity, etc.) were 

then incorporated into the final output of CALMET that was used to drive the CALPUFF model. Figure 4-3

depicts the location of the meteorological data sources used as input data to the CALMET model. Table 4-1

presents the user-defined parameters that define the CALMET domain and the weighting values used in 

developing the CALMET fields.

Table 4-1 Preliminary CALMET User-defined Fields Not Specified in IWAQM Appendix A

Variable Description Value 

NX Number of east-west grid cells 159

NY Number of north-south grid cells 141

DGRIDKM Meteorology grid spacing (km) 4

NZ Number of vertical layers of input meteorology 12

ZFACE Vertical cell face heights (meters [m]) 0,20,40,80,120,180,260,400,600,800,1200,

2000,3500

IEXTRP Extrapolation of surface winds to upper layers -4 

RMAX1 Maximum surface over-land extrapolation radius (km) 20

RMAX2 Maximum aloft over-land extrapolation radius (km) 50

RMAX3 Maximum over-water extrapolation radius (km) 500

TERRAD Radius of influence of terrain features (km) 10

R1 Relative weight at surface of Step 1 field and 

observations 

10

R2 Relative weight aloft of Step 1 field and observations 25

IPROG Gridded initial prognostic wind field – MM5 data 14

RMIN Minimum radius of influence for wind field interpolation 0.1

IKINE Kinematic effects OFF

4.1.5 CALPUFF Background Air Quality Data

The CALPUFF chemistry algorithms require hourly estimates of background ammonia and ozone 

concentrations for the conversion of NO/NO2 and SO2 to nitrates and sulfates, respectively. As discussed in 

Section 2.3, background ozone monitoring data available for the proposed model year from rural located 

stations from within and just outside the modeling domain were included in the CALPUFF analysis. Hourly 

ozone data from representative rural USEPA AIRS and CASTNET monitoring sites were used to create a time 

and spatially varying ozone database used as input into CALPUFF. In areas without hourly data, a regional 

representative background ozone concentration value based upon the monthly average of all the available

regional hourly data was used. The background monthly average ozone values ranged from 26.1 ppb in 

December to 46.6 ppb in July.2

 

2 Actual monthly values for January through December are respectively 28.3, 32.0, 37.6, 42.9, 41.9, 45.3, 46.6, 40.5, 34.0, 

28.0, 27.7, 26.1.
4-7 March 2012

Figure 4-3 Meteorological Stations Selected for Input to CALMET
4-8 March 2012

4.2 CMAQ Ozone Modeling

For more than a decade, USEPA has been developing the Models-3 CMAQ modeling system with the 

overarching aim of producing a ‘One-Atmosphere’ air quality modeling system capable of addressing ozone, 

PM, visibility, and acid deposition within a common platform (Byun and Schere 2006; USEPA 1999). The 

original justification for the Models-3 development emerged from the challenges posed by the 1990 CAA 

Amendments and the USEPA’s desire to develop an advanced modeling framework for ‘holistic’ environmental 

modeling utilizing state-of-science representations of atmospheric processes in a high performance computing 

environment. USEPA completed the initial stage of development with Models-3 and released CMAQ in 

mid-1999 as the initial operating science model under the Models-3 framework. The most recent rendition is 

CMAQ Version 4.6, publicly released in October 2006.

CMAQ consists of a core CTM and several pre-processors including the MCIP, ICON and BCON, and a 

JPROC. The USEPA continues to improve and develop new modules for the CMAQ model and typically 

provides a new release each year. In the past, the USEPA also has provided patches for CMAQ as errors are 

discovered and corrected. More recently, the USEPA has funded the CMAS center to support the 

coordination, update, and distribution of the Models-3 system. Byun and Schere (2006) describe the newest 

features implemented in the previously released CMAQ Version 4.5. 

4.2.1 CMAQ Modeling Setup

The CMAQ modeling system was used for assessing the potential ozone impacts of the proposed project on 

the surrounding area. This analysis used the CMAQ meteorological and chemistry databases developed for 

the UBAQS (ENVIRON 2009). The CMAQ modeling consisted of five different model simulations for each of 

the CMAQ base years of 2005 and 2006:

• Simulation 1 was the 2005 and 2006 actual years using actual emissions from the UBAQS data base 

and also is used in the model performance evaluation. 

• Simulation 2 was run with 2006 typical emissions for both the 2005 and 2006 meteorological data and 

was used for comparison with the future case design values and calculations. 

• Simulation 3 was a future baseline year, which is 2018 – the year the proposed project would be

complete.

• Simulation 4 included the 2018 future baseline year and the anticipated emissions for 2017 from the 

Proposed Action.

• Simulation 5 included the 2018 future baseline year and the anticipated emissions for 2026 from the 

Optimal Recovery Alternative.

The impacts from the Proposed Action were estimated by determining the difference between Simulations 4 

and 3, and impacts from the Optimal Recovery Alternative were estimated by determining the difference 

between Simulations 5 and 3. 

The years 2005 and 2006 were used for the baseline CMAQ ozone modeling for this study. This selection was 

appropriate primarily because of data availability for these years from UBAQS.

4.2.2 Modeling Domains

This section summarizes the model domain definitions for the GNB ozone modeling, including the domain 

coverage, resolution, map projection, and nesting schemes for the high resolution sub-domain.

4.2.2.1 Horizontal Modeling Domain

Figure 4-4 displays the 36- and 12-km modeling domains that were used in the CMAQ/SMOKE air 

quality/emissions modeling. The 36-km continental U.S. horizontal domain for CMAQ air quality and SMOKE 

emissions modeling were identical to that used by several Regional Planning Organizations (RPOs) for their 
4-9 March 2012

regional haze modeling (e.g., WRAP, Central States Regional Air Partnership [CENRAP], and VISTAS). This 

36-km modeling domain covered the continental U.S. as well as large portions of Mexico and Canada. The 

CMAQ 12-km modeling domain is shown in Figure 4-5 and covers eastern Utah, western Colorado, and 

portions of Wyoming, Arizona, and New Mexico.

Note: The 12-km domain is highlighted in red and is expanded in Figure 4-7. 

Figure 4-4 36- and 12-km Domains for the GNB Study
4-10 March 2012

Figure 4-5 12-km CMAQ Domain for the GNB Study

The CMAQ air quality and SMOKE emissions modeling 36- and 12-km domains were aligned within the MM5 

domains. The larger MM5 modeling domains provided a buffer around the CMAQ/emissions modeling 

domains by at least 6 grid cells in each direction. These grids were based on a LCP using the same projection 

as adopted by the RPOs. The LCP parameters are listed in Table 4-2. 

Table 4-2 Lambert Conformal Projection Definition for the GNB Modeling Grid

Parameter Value

Projection Lambert-Conformal

1st True Latitude 33 degrees N

2nd True Latitude 45 degrees N

Central Longitude -97 degrees W

Central Latitude 40 degrees N

There was a possibility of boundary “noise” effects resulting from boundary conditions coming into dynamic 

balance with the MM5 algorithms. The 12-km MM5 domain, with the 12-km CMAQ domain in red, is presented 

in Figure 4-6. The larger MM5 domain was designed to sequester such errors from the air quality simulation. 

The buffer region used in the current study exceeded the USEPA suggestion of at least 5 grid cell buffers at 

each boundary. 
4-11 March 2012

Figure 4-6 12-km WRAP MM5 with 12-km CMAQ Domain in the GNB Study

Table 4-3 lists the number of rows and columns (i.e., the number of grid cells in the east-west and north-south 

directions, respectively) and the definition of the X and Y origin (i.e., the southwest corner) for the 36-/12-km 

domains used in the CMAQ and the SMOKE models for the current study. 

Table 4-3 Grid Definitions for SMOKE and CMAQ

Grid Resolution

East-west Grid 

Cells

North-south Grid 

Cells

X-origin

(km)

Y-origin

(km)

36 km grid 148 112 -2736.0 -2088.0

12 km grid 53 47 -1368.0 -288.0

4.2.2.2 Vertical Modeling Structure

The CMAQ vertical structure was primarily defined by the vertical grid used in the MM5 modeling. The MM5 

model employs a terrain-following coordinate system defined by pressure, using multiple layers that extend 

from the surface to 100 millibars (mb), which is approximately 15 km above ground level. A layer-averaging 

scheme was adopted for CMAQ simulations to reduce the air quality computational time. The effects of layer 

averaging were evaluated by WRAP and VISTAS and found to have a relatively minor effect on the model 

performance metrics when both 34-layer and 19-layer CMAQ model simulations were compared to ambient 

monitoring data (Morris et al. 2004). For the GNB ozone modeling, 19 vertical layers were used. Table 4-4 lists 
4-12 March 2012

the mapping from the MM5 vertical layer structure to the CMAQ vertical layers. This MM5 structure was taken 

from the WRAP, VISTAS, and CENRAP RPO configuration, and the same CMAQ structure also was being 

used in modeling by the RPOs. Note that the MM5 and CMAQ models both used a terrain following “sigma” 

coordinate system so that the model heights will be compressed over elevated terrain.

Table 4-4 Vertical Layer Definition for MM5 Simulations and Approach for Reducing CMAQ Layers by 

Collapsing Multiple MM5 Layers

MM5 CMAQ

Layer Sigma Pressure (mb) Height (m) Depth (m) Layer Pressure (mb) Height (m) Depth (m)

34 (top) 0.000 100 18123 2856 19 100 18123 9160

33 0.050 145 15267 2097

32 0.100 190 13170 1659

31 0.150 235 11510 1374

30 0.200 280 10136 1173

39 0.250 325 8963 1024 18 325 8963 3492

28 0.300 370 7938 909

27 0.350 415 7030 817

26 0.400 460 6213 742

25 0.450 505 5471 680 17 505 5471 1890

24 0.500 550 4791 627

23 0.550 595 4163 582

22 0.600 640 3581 543 16 640 3581 1053

21 0.650 685 3038 509

20 0.700 730 2528 386 15 730 2528 664

19 0.740 766 2142 278

18 0.770 793 1864 269 14 793 1864 443

17 0.800 820 1596 174

16 0.820 838 1421 171 13 838 1421 338

15 0.840 856 1251 167

14 0.860 874 1083 164 12 874 1083 163

13 0.880 892 920 161 11 892 920 161

12 0.900 910 759 79 10 910 759 158

11 0.910 919 680 78

10 0.920 928 601 78 9 928 601 155

9 0.930 937 524 77

8 0.940 946 447 76 8 946 447 76

7 0.950 955 371 75 7 955 371 76

6 0.960 964 295 75 6 964 295 75

5 0.970 973 220 74 5 973 220 74

4 0.980 982 146 37 4 982 146 37

3 0.985 987 109 37 3 987 109 37

2 0.990 991 73 36 2 991 73 36

1 0.995 996 36 36 1 996 36 36

0 (ground) 1.000 1000 0 0 0 0 0 0

4.2.3 Model Input Preparation Procedures

This and the following subsections describe the procedures used in developing the meteorological, emissions, 

and air quality inputs to the CMAQ model for the ozone modeling study on the 36- and 12-km grids. The 
4-13 March 2012

development of the CMAQ meteorological and emissions inputs are discussed together with the science 

options recommended for the CMAQ model. The procedures for developing the initial and boundary conditions 

and photolysis rates also are discussed along with the model application procedures.

The procedures set forth here are consistent with USEPA guidance (USEPA 2007, 2005b, 1991), other recent 

8-hour ozone modeling studies conducted for various state and local agencies using these or other state-ofscience modeling tools (e.g., Morris et al. 2004; Tesche et al. 2005, 2003), as well as the methods used by 

USEPA in support of the recent Clean Air Interstate Rule (USEPA 2005c) and the Clean Air Mercury Rule 

(USEPA 2005d).

4.2.3.1 Meteorological Inputs

Annual 36-/12-km MM5 simulations for 2005 (McNally and Schewe 2006) and 2006 (McNally and 

Schewe 2008) were used to provide meteorological inputs to the CMAQ and SMOKE models. The MM5 

configurations were based on the WRAP 2002 simulation (Kemball-Cook et al. 2004), which was based on an 

extensive review of available MM5 physical and dynamical options and has been the basis of many 

subsequent MM5 applications in the region. The WRAP did a fairly extensive study to determine the optimal 

configuration for the MM5 modeling system. One of the choices they made was to use the Betts-Miller 

Cumulus Parameterization. Betts-Miller was developed to parameterize tropical convection, which improved 

the precipitation skill of the model.

4.2.3.2 Emission Inputs

In order to simulate atmospheric ozone levels, it was necessary to develop emissions estimates for all other 

emission sources (i.e., industrial, electric generation, motor vehicle, biogenic) in addition to the emissions from 

the proposed project. The foundation datasets for the emissions development were based on the emissions

data developed by WRAP. Details on the emissions input preparation are presented in Chapter 3.0. The 

emissions were processed into CMAQ-ready files using SMOKE 2.2 for both the 36- and 12-km grids. 

SMOKE 2.2 was used because several of the WRAP-developed emissions files are not directly compatible 

with the newest version of SMOKE (i.e., Version 2.4). 

4.2.4 CMAQ Science and Input Configurations

This section describes the model configuration and science options that were used in this ozone modeling 

effort. Table 4-5 summarizes the CMAQ configuration that was used in the study. The latest version of CMAQ 

(Version 4.6) was used for ozone modeling. 

As indicated in the CMAQ model setup defined in Table 4-5, two grids were employed. CMAQ was initially run 

for the 2005 and 2006 Baseline on the 36-km continental U.S. grid for calendar year 2005 and 2006 and was 

then run on the 12-km grid utilizing the initial and boundary conditions from the 36-km CMAQ simulation.

CMAQ inputs were as follows:

• Meteorological Inputs: The MM5-derived meteorological fields were prepared for CMAQ using 

MCIP 3.3. 

• Initial/Boundary Conditions (IC/BCs): The IC/BCs for the 36-km continental U.S. simulation were 

based on the latest available information. Currently, the RPOs use IC/BC’s for the same domain 

based on a 2002 GEOS-CHEM global chemistry model simulation. Boundary and initial conditions for 

the 12-km nest were generated from the 36-km CMAQ nest using the CMAQ ICON and BCON 

processors.
4-14 March 2012

Table 4-5 CMAQ Model Configuration

Science Options Configuration Details/Comments

Model Code CMAQ (version 4.6) USEPA 1999

Horizontal Grid Mesh 36/12 km 36 km covering continental U.S; 12 km covering 

Eastern Utah and Western Colorado

 36 km grid 148 x 112 cells RPO National Grid

 12 km grid 53 x 47 cells

Vertical Grid Mesh 19 Layers First 8 layers synchronized with MM5

Grid Interaction One-way nesting

Initial Conditions 15 days full spin-up Separately run 4 quarters of 2006

Boundary Conditions GEOS-CHEM annual run 2002 GEOS-CHEM run

Emissions

Baseline Emissions Processing See SMOKE (Version 2.2) model 

configuration

MM5 Meteorology input to SMOKE, CMAQ 

Dust Transport Fraction Applied in emissions before SMOKE

NH3 Inventory Adjustment Applied in emissions before SMOKE

Sub-grid-scale Plumes No Plume-in-Grid 

Chemistry

Gas Phase Chemistry CB-05 with Isoprene updates

Aerosol Chemistry AE3/ISORROPIA

Secondary Organic Aerosols Secondary Organic Aerosol Model Schell et al. (2001)

Aerosol Mass Conservation Patch Yes

Cloud Chemistry RADM-type aqueous chemistry Includes subgrid cloud processes

N2O5 Reaction Probability 0.01 – 0.001

Horizontal Transport

Eddy Diffusivity Scheme K-theory with Kh grid size dependence Multiscale Smagorinsky (1963) approach

Vertical Transport

Eddy Diffusivity Scheme K-theory

Diffusivity Lower Limit Kzmin = 0.1

Planetary Boundary Layer No Patch1

Deposition Scheme Aero_dep Directly linked to Pleim-Xiu Land Surface Model 

parameters

Numerics

Gas Phase Chemistry Solver Euler Backward Iterative solver Hertel et al. (1993) EPI solver ~ 2x faster than 

MEBI

Horizontal Advection Scheme Piecewise Parabolic Method scheme

Other

Meteorological Processor MCIP version 3-3

Simulation Periods Annual 2006

Integration Time Step Internally Computed 15 minute coupling time step

Time zone GMT

Platform Dual Processor/Dual Core AMD Opteron

Run-Time (expected) 7-10 days Platform Dependent

1 Patch means applying a mosaic scheme based on land-use, which is not normally done for CMAQ. The terminology is not the same as used for a 

software fix.
4-15 March 2012

• Photolysis Rates: The modeling used the photolysis inputs as well as the albedo/haze/ozone/snow 

inputs for CMAQ based on Total Ozone Mapping Spectrometer data using the CMAQ JPROC 

processor. 

• Spin-Up Initialization: The model was run in quarters using a nominal 15-day spin-up from the 

previous quarter for the 36-km grid and a nominal 4-day spin-up from the previous quarter for the 

12-km grid.

4.3 AERMOD Near-field Modeling

The near-field ambient air quality impacts on NO2, CO, SO2, PM10, and PM2.5 were assessed in the vicinity of 

the proposed project using USEPA's guideline model of assessing near-field impacts, AERMOD 

(Version 09292; updated 1-hour NO2 modeling was conducted with Version 11103). AERMOD was 

executed using the USEPA-default recommended settings. Emissions sources that were associated with the 

project development and included in the near-field AERMOD analysis consisted of activities associated with 

drill rigs, compressor stations, single pad construction, and the actual producing well. These operations require 

the use of diesel engines with the capability of producing air emissions, which potentially could have an impact 

on surrounding air quality. The air quality assessment addresses impacts associated with emissions 

from both Tier 2 and Tier 4 engines.

AERMOD (USEPA 2004) was adopted by USEPA in a final rule (FR November 9, 2005) that replaced the ISC 

model with AERMOD, effective on December 9, 2005. The AERMOD model was developed by the AERMIC 

work group (the American Meteorological Society/USEPA Regulatory Model Improvement Committee) and 

was intended to incorporate improved understanding of PBL meteorology into air dispersion calculations. 

AERMOD (Versions 09292 and 11103) includes the PRIME (Plume Rise Model Enhancement) building 

downwash algorithms. The AERMOD modeling system consists of two preprocessors and the dispersion 

model. AERMET is the meteorological preprocessor component and AERMAP is the terrain pre-processor 

component that characterizes the terrain and generates receptor elevations along with critical hill heights for 

those receptors. The AERMOD model runs reported in this section used the 5-year meteorological database.

4.3.1 Criteria Pollutant Analysis

The near-field impacts were assessed to quantify air quality impacts related to the density of well pad 

development and drill rig operations within a hypothetical designated area (e.g., a section/township/range). 

Near-field impacts were addressed for NOX, CO, SO2, PM10, and PM2.5 within the immediate vicinity of these 

development areas. The AERMOD modeling analysis consisted of three phases: 1) single source impact 

analysis, 2) well pad production analysis, and 3) well drilling analysis.

For the newly promulgated 1-hour SO2 and 1-hour NO2 NAAQS modeling, special modeling techniques 

were needed beyond what was required for the other pollutants. USEPA’s Guideline on Air Quality 

Models (USEPA 2005e) provides a tiered approach for modeling NO2 that provides for increased levels 

of refinement for the treatment of the in-plume conversion of nitric oxide (NO) to NO2. For this 

analysis, a Tier 3 approach was followed, as discussed in the June 2010 USEPA Clarification Memo 

regarding the application of AERMOD for 1-hour NO2 modeling (USEPA 2010a). The Tier 3 approach 

involves using the Plume Volume Molar Ratio Method (PVMRM), which computes the available moles 

of ozone to combine with the moles of NO. The moles of ozone available to combine with the in-plume 

moles of NO are restricted to the plume cross-sectional area at each downwind distance considered. 

The PVMRM option appears to provide a more realistic treatment of the conversion of NO to NO2 as a 

function of distance downwind from the source than the Ozone Limiting Method (OLM) or the other 

NO2 screening options. Because PVMRM better simulates the NO to NO2 conversion chemistry during 

plume expansion, it is particularly well suited for near-field receptors and, therefore, simulating the 

project sources where the maximum modeled NOX concentrations would occur near the stacks. In 

addition, unlike OLM, PVMRM is designed to work with either single or multiple plumes as is the case 

for the project.
4-16 March 2012

The application of AERMOD with PVMRM requires specification of the equilibrium ratio and the 

in-stack NO2/NOX ratio. The default equilibrium ratio for the NO2/NOX ratio in AERMOD of 0.90 was used 

and the in-stack NO2/NOX ratio of 0.1 was used. The use of the 0.1 in-stack ratio is supported by 

stack-test data as provided in Appendix B.

PVMRM requires the use of hourly ozone data with concurrent meteorological data to approximate the 

rate of conversion of NO to NO2. The current meteorological inputs to AERMOD are based on the years 

2002 through 2006. Since the ozone monitoring near the GNBPA did not begin until July 2009, 

concurrent hourly ozone monitoring data are not available from either the Ouray or Redwash 

monitors. Therefore, diurnal profiles of hourly ozone background concentrations were developed 

using data from July 2009 through June 2011 for the Ouray and Redwash monitors for each season 

defined as follows:

• Winter – December, January, February, and March;

• Spring – April and May;

• Summer – June, July, August; and

• Fall – September, October, and November.

For each of these seasons at each monitor, the highest monitored concentration for each hour of the 

day was selected to represent all of the hours for the entire season. The ozone data indicates that the 

Ouray winter peak value is slightly higher than other seasons, but the other seasons are comparable 

in trend and magnitude. The diurnal values developed for the Ouray monitor were used to develop a 

full year of hourly ozone values for each season because it is closest to the GNBPA. Figure 4-7 shows 

the diurnal profile of hourly ozone used in this study.

Figure 4-7 Ouray Diurnal Ozone Profile of Maximum Hourly Values by Season
4-17 March 2012

For 1-hour SO2, the 5-year average of the 99th percentile highest daily 1-hour maximum modeled SO2

concentrations was computed and added to the representative 1-hour SO2 background concentration 

to determine compliance with the NAAQS. 

For 1-hour NO2, compliance with the NAAQS was assessed by combining the 5-year average of the 

98th percentile highest daily 1-hour maximum modeled NO2 concentrations and the representative 1-

hour NO2 background concentration. This approach follows USEPA guidance released on March 1, 

2011 (USEPA 2011), in the form of a clarification memo that addresses different options on how to 

combine model and monitored concentrations to assess compliance with the 1-hour NO2 NAAQS. In 

addition to the March 2011 USEPA guidance, a new AERMOD model version (11103) has been released 

with the capability of calculating the correct form of the model design concentration for 1-hour NO2

and SO2. This new AERMOD model version was used to update the 1-hour NO2 modeling methodology 

to be consistent with the March 2011 USEPA Guidance. As such, the 1-hour NO2 background 

concentrations used to assess compliance with the NAAQS are now based on seasonal diurnal 

profiles as opposed to a single design concentration that is added to the design model concentration. 

The seasonal diurnal profiles were developed using guidance in the USEPA March 2011 clarification 

memo and implemented in AERMOD using the model feature SEASHR. 

The seasonal diurnal profiles were based on the 98th percentile concentration of available hourly 

monitored concentrations for each specific season/hour of day combination. Seasonal diurnal profiles 

were developed for each year (2009/2010 and 2010/2011) and each monitor (Ouray and Redwash). A 

2-year average 98th percentile concentration was calculated for each year’s seasonal diurnal profiles. 

The seasonal diurnal profiles input into AERMOD represent an array of 96 values (4 seasons x 

24 hours per day) based on a composite maximum between the Ouray and Redwash 2-year average 

98th percentile seasonal diurnal profiles. Figure 4-8 shows the seasonal diurnal profiles used as input 

to AERMOD. Regional background concentrations are discussed in Section 2.3.

4.3.1.1 Single Source Group Impact Analysis 

The single source impact analysis was designed to assess the near-field impacts from each type of project 

source individually. AERMOD was run for each of the following types of project sources: 1) a compressor 

station; 2) a drill rig consisting of 2 drill rig engines and a rig boiler (assuming a completion rig would 

not operate simultaneously on the same pad as the drill rig); and 3) a production well. A uniform polar grid 

of receptors was placed in a radial fashion around the modeled source every 100 m starting at 100 m 

downwind out to 2,000 m with radials every 10°. Figure 4-9 shows the source/receptor setup used for the 

single source impact analysis, and Table 4-6 lists the emission and modeling parameters for each source 

assessed for Tier 2 and Tier 4 engines. 

Emissions for a compressor station were calculated based on the assumption of 3 separate compressor 

engines with 1,340 bhp engine capacity, equivalent to 9.38 MMBtu/hour each. Compressor stations were 

assumed to operate 8,760 hours per year, and used emission factors that were provided in Tables 3-40

through 3-42. 

Short-term emissions for drilling operations were based on the emissions from one well including a drill rig

(two rig engines) and a rig boiler. Tables 3-20 and 3-21 provide a summary of short-term and annual 

emissions from these sources. Fugitive emissions from well drilling and completion road traffic were not 

included because of the dispersed and temporary nature of the source. For addressing impacts, the wells were 

aggregated as discussed above. 

Emissions from production wells included the separator heater for short-term emissions (Table 3-28) and 

included both that unit and the fugitive emissions from production traffic for annual emissions (Tables 3-28

and 3-31). For modeling impacts, the wells were aggregated over a square mile, as discussed above.
4-18 March 2012

Data in ppb.

Figure 4-8 Ouray Diurnal NO2 Profile of 98th Percentile Maximum Hourly Values by Season

For the single source near-field analysis, building downwash and receptor terrain elevations were ignored 

largely due to the uncertainty in location and orientation of each source relative to terrain and buildings. These 

assumptions should not have a measurable impact on the overall modeling results because the terrain within 

the immediate vicinity of these sources likely would be relatively flat and there are few buildings or structures 

associated with these project sources.

Modeling results for the AERMOD single source impact analysis were tabulated for NO2, CO, SO2, PM10, and 

PM2.5. No distinction was made between the short-term and annual modeling scenarios because it was 

assumed that these sources could operate 8,760 hours per year. The results of this analysis are reported in 

Chapter 5.0.

4.3.1.2 Well Pad Production Analysis

The well pad production analysis was designed to assess air quality impacts related to the density of well pad 

production within a hypothetical square mile section/township/range for three production density levels. Well 

pad density was assessed at 10-acre spacing, 20-acre spacing, and 40-acre spacing. For example, the 

10-acre spacing well pad production scenario contained producing well pads that were spaced uniformly at 

10-acre intervals throughout the hypothetical square mile section. For each well pad scenario, a compressor 

station was placed in the middle of each producing field of well pads.
4-19 March 2012

Figure 4-9 Single Source Impact Analysis Model Setup and Receptor Location
4-20 March 2012

Table 4-6 Project Source Modeling Parameters and Emission Rates

Tier 2 Engines

Point Source Parameters

ID Activity

Operating 

Hours

(hr/day)

Emission Rate per activity (g/s) Stack Parameters1

NOX CO SO2 PM10 PM2.5 Stack 

Orientation

H

(m)

V

(m/s)

T

(K)

D

1-hr Annual 1-hr 8-hr 1-hr 3-hr 24-hr Annual 24-hr 24-hr Annual (m)

CS Compressor Station 24 1.68 1.68 0.19 0.19 0.012 0.012 0.012 0.012 0.14 0.14 0.14 Vertical 10.0 51.1 755 0.30

DR Drill Rig 24 1.97 0.10 1.07 1.07 0.002 0.002 0.001 0.0001 0.04 0.04 0.003 Vertical 6.1 71.7 672 0.25

CR Completion Rig 12 0.63 0.002 0.34 0.34 0.0006 0.0006 0.0002 0.000002 0.006 0.006 0.00005 Vertical 3.0 101.5 770 0.13

RB Rig Boiler 24 0.04 0.02 0.01 0.01 0.0005 0.0005 0.0005 0.0003 0.005 0.005 0.002 Vertical 4.0 5.3 450 0.39

Volume Source Parameters

ID Activity

Operating 

Hours

(hr/day)

Emission Rate per activity (g/s) Source Dimensions1 Release Parameters1

NOX CO SO2 PM10 PM2.5 W

(m)

Area

(m2)

H

(m)

σy-init

(m)

σz-init

(m)

Hr

1-hr Annual 1-hr 8-hr 1-hr 3-hr 24-hr Annual 24-hr 24-hr Annual (m)

PW Production Well 24 0.0066 0.0033 0.0056 0.0056 0.00022 0.00022 0.00022 0.00011 0.00050 0.00050 0.00056 71.1 5,058.5 5 16.54 2.33 2.50

Tier 4 Engines

Point Source Parameters

ID Activity

Operating 

Hours

(hr/day)

Emission Rate per activity (g/s) Stack Parameters1

NOX CO SO2 PM10 PM2.5 Stack 

Orientation

H

(m)

V

(m/s)

T

(K)

D

1-hr Annual 1-hr 8-hr 1-hr 3-hr 24-hr Annual 24-hr 24-hr Annual (m)

CS Compressor Station 24 1.68 1.68 0.19 0.19 0.012 0.012 0.012 0.012 0.14 0.14 0.14 Vertical 10.0 51.1 755 0.30

DR Drill Rig 24 1.07 0.06 1.07 1.07 0.002 0.002 0.001 0.0001 0.004 0.004 0.0003 Vertical 6.1 71.7 672 0.25

CR Completion Rig 12 0.34 0.0009 0.34 0.34 0.0006 0.0006 0.0002 0.000002 0.0006 0.0006 0.000005 Vertical 3.0 101.5 770 0.13

RB Rig Boiler 24 0.04 0.02 0.01 0.01 0.0005 0.0005 0.0005 0.0003 0.005 0.005 0.002 Vertical 4.0 5.3 450 0.39

Volume Source Parameters

ID Activity

Operating 

Hours

(hr/day)

Emission Rate per activity (g/s) Source Dimensions1 Release Parameters1

NOX CO SO2 PM10 PM2.5 W

(m)

Area

(m2)

H

(m)

σy-init

(m)

σz-init

(m)

Hr

1-hr Annual 1-hr 8-hr 1-hr 3-hr 24-hr Annual 24-hr 24-hr Annual (m)

PW Production Well 24 0.0066 0.0033 0.0056 0.0056 0.00022 0.00022 0.00022 0.00011 0.00050 0.00050 0.00056 71.1 5,058.5 5 16.54 2.33 2.50

1 Units for dimensions and parameters

H = height

V = vertical exhaust speed

T = temperature

D = diameter

W = width

Hr = height of release
4-21 March 2012

This design allowed for the allocation of the following number of producing wells per scenario:

• 10-acre spacing  64 production wells, 1 compressor station; 

• 20-acre spacing  32 production wells, 1 compressor station; and 

• 40-acre spacing  16 production wells, 1 compressor station.

The production wells were evenly spaced throughout the hypothetical square mile section centered on the 

compressor station. Uniformly spaced Cartesian receptors were placed throughout the hypothetical square 

mile section at 100-m intervals. Each source had a 100-m buffer to the nearest receptor point to minimize the 

impact of extremely localized high model predictions. Figures 4-10 through 4-12 depict the source/receptor 

model setup for each of the three well pad production scenarios. The compressor station and production well 

emissions and modeling parameters used to develop each well pad production scenario are provided in

Table 4-6.

As in the single source near-field analysis, building downwash and receptor terrain elevations were ignored 

largely due to the uncertainty in location and orientation of each source relative to terrain and buildings. These 

assumptions should not have an impact on the overall modeling results because the terrain within the 

immediate vicinity of these sources likely would be relatively flat and there are few buildings or structures 

associated with these project sources.

Modeling results for the AERMOD well pad production analysis were tabulated for NO2, CO, SO2, PM10, and 

PM2.5. No distinction was made between the short-term and annual modeling scenarios because it was 

assumed that these sources could operate 8,760 hours per year. The results of this analysis were reported in 

Chapter 5.0.

4.3.1.3 Well Drilling Analysis

The well drilling analysis was designed to assess air quality impacts related to the drilling operations at the well 

pad site. Modeling was conducted over the short term to address the new 1-hour standards and over a 

1-year time frame to address other criteria pollutant standards, as described below.

Short-term modeling was conducted using four well pad sites, all with simultaneous drilling 

operations. Specifically, the modeling scenario consisted of one drill rig with two drill rig engines and 

a rig boiler, which were all assumed to be operating continuously at the same time at each well pad 

site. A second operating scenario consisted of a completion rig assumed to be operating continuously 

at each well pad site. Modeling indicated that the completion rig scenario would have a lower air 

quality impact, so results are presented only for the scenario consisting of one drill rig with two drill 

rig engines and a rig boiler operating on four well pad sites. The four well pads were centered in a 2 x 

2 array in the center of the section at a 400-m interval. The 400-m interval represents the maximum 

density for a 40-acre surface spacing resulting in the greatest potential for source impact overlap. For 

this analysis, it also was assumed that the four well pads would actively drill simultaneously within a 

given day, which is conservative and would capture the peak impacts that could occur at any 

downwind receptor.

For annual impacts, emissions from the drill rig (two drill rig engines), completion rig, and rig boiler 

were modeled over a 1-year time frame. For the project alternatives, it was assumed that the maximum 

downhole spacing was 10 acres (64 wells per section); however, the surface spacing of the wells 

varies by alternative. A 40-acre surface spacing (16 pads per section) represents a worst-case 

scenario for this analysis because of the denser concentration of emission sources. Therefore, the 

annual modeling was based on the emissions from 64 wells drilled in a section, with 4 wells drilled at 

each of the 16 well pads.
4-22 March 2012

Figure 4-10 10-Acre Well Pad Production Analysis Model Setup and Receptor Location
4-23 March 2012

Figure 4-11 20-Acre Well Pad Production Analysis Model Setup and Receptor Location
4-24 March 2012

Figure 4-12 40-Acre Well Pad Production Analysis Model Setup and Receptor Location
4-25 March 2012

Uniformly spaced Cartesian receptors were placed throughout the hypothetical section at 100-m intervals. 

Each source had a 100-m buffer to the nearest receptor point to minimize the impact of extremely localized

high model predictions. Figures 4-13 shows an example of the source/receptor model setup for the short-term 

well pad construction analysis, and Figure 4-14 shows an example of the setup for the annual analysis. 

Table 4-6 provides modeling parameters and emission rates for drilling, which includes emissions from the drill 

rig, single pad construction, and drilling/completion mobile equipment emissions.

As in the previous analyses, building downwash and receptor terrain elevations were ignored largely due to the 

uncertainty in location and orientation of each source relative to terrain and buildings. These assumptions 

should not have an impact on the overall modeling results because the terrain within the immediate vicinity of 

these sources likely would be relatively flat and there are few buildings or structures associated with these 

project sources.

Modeling results for the AERMOD well pad construction analysis were tabulated for NOX, CO, SO2, PM10, and 

PM2.5. The results of this analysis are reported in Chapter 5.0.

4.3.2 Meteorological Data Development

Meteorological data required for AERMOD included hourly values of wind speed, wind direction, and ambient 

temperature. Since the AERMOD dispersion algorithms were based on atmospheric boundary layer dispersion 

theory, additional boundary layer variables were derived by parameterization formulas, which were computed 

by the AERMOD meteorological preprocessor, AERMET. These parameters included sensible heat flux, 

surface friction velocity, convective velocity scale, vertical potential temperature gradient, convective and 

mechanical mixing heights, Monin-Obukhov length, surface roughness length, Bowen ratio, and albedo.

The AERMET meteorological pre-processor (Version 06341) was used to process 5 years of meteorological 

data into a format required by AERMOD. Boundary layer parameters used by AERMOD, which also were 

required as input to the AERMET processor, include albedo, Bowen ratio, and surface roughness. The land 

classifications and associated boundary layer parameters were determined following the guidelines provided 

by the USEPA AERMOD Implementation Guide, updated as of January 9, 2008. In accordance with this 

guide, the input boundary layer parameters to AERMET were determined using the AERSURFACE 

meteorological processor, as applied to the meteorological measurement site (Vernal Municipal Airport).

AERMET was used to combine 5 years (2003 to 2007) of surface observations from data from Vernal 

Municipal Airport, Utah, with twice daily sounding data from Salt Lake City, Utah. The overall annual wind rose 

for 10-m for the Vernal site is provided in Figure 2-1.

4.3.3 HAPs Analysis

The ambient air concentration of selected HAPs was evaluated by modeling the emission rates for 

HAPs listed in Table 4-7. The HAP modeling analysis employed the same key elements of the modeling 

analysis as for modeling the criteria pollutants, such as:

• AERMOD (Version 09292);

• 5 years of hourly meteorological data, 2002 through 2006 consisting of surface observations 

from Vernal, Utah, and upper air data from Salt Lake City, Utah;

• Assumed flat terrain; and

• No building downwash.
4-26 March 2012

Figure 4-13 Short-term Drill Rig Analysis Model Setup and Receptor Location (400-m spacing)
4-27 March 2012

Figure 4-14 Annual Drill Rig Analysis Model Setup and Receptor Location
4-28 March 2012

Table 4-7 HAP Emission Rates

Activity

Operating 

Hours

(hr/day)

Emission Rate per activity (g/s)

Benzene Toluene Ethyl Benzene Xylene Formaldehyde n-Hexane

24-hr Annual 24-hr Annual 24-hr Annual 24-hr Annual 24-hr Annual 24-hr Annual

Compressor Station 24 1.56E-03 1.56E-03 1.45E-03 1.45E-03 1.41E-04 1.41E-04 6.52E-04 6.52E-04 1.87E-01 1.87E-01 3.94E-03 3.94E-03

Drill Rig 24 7.59E-04 6.24E-05 5.58E-04 4.59E-05 1.16E-04 9.51E-06 3.95E-04 3.25E-05 4.41E-03 3.62E-04 5.94E-05 4.88E-06

Completion Rig 12 1.22E-04 1.00E-06 8.99E-05 7.39E-07 1.86E-05 1.53E-07 6.35E-05 5.22E-07 7.09E-04 5.83E-06 9.55E-06 7.85E-08

Rig Boiler 24 4.49E-08 1.12E-08 1.56E-05 3.25E-07 1.56E-05 3.34E-09 1.60E-07 5.72E-09 2.75E-07 1.73E-06 0 0

Production Well 24 1.29E-03 1.26E-03 2.99E-03 2.95E-03 7.96E-05 1.37E-04 2.23E-03 2.18E-03 5.55E-04 5.53E-04 3.65E-03 3.63E-03
4-29 March 2012

AERMOD was run for all scenarios outlined in Section 4.3.1 using the 5 years of meteorological data 

to estimate air concentrations of formaldehyde, benzene, toluene, ethyl benzene, xylene(s), and 

n-hexane. The maximum modeled concentrations over the 5-year period for each applicable 

HAP/averaging period (i.e., annual and 24-hour) was compared to the Toxic Screening Level (TSLs) 

and Reference Concentrations for Chronic Inhalation (RfCs). See Chapter 5.0 for this comparison.
5-1 March 2012

5.0 Assessment and Reporting of Air Quality Impacts

The overall objective of this air quality impact analysis is to evaluate impacts to air quality and AQRVs for 

the Projected Baseline, Proposed Action, and Optimal Recovery Alternative. The analysis compares the 

predicted impacts to established significance thresholds, air quality standards and other environmental 

parameters. Projected Baseline emissions are included in both the Proposed Action and Optimal Recovery 

Alternative modeling efforts. 

To evaluate the significance of proposed air quality impacts, the results of air quality modeling and 

post-processing were compared with applicable standards and criteria and reported as described in the 

following subsections. Modeled results are provided to further identify impacts in support of the NEPA 

analysis for the proposed project.

5.1 CALPUFF Impact Assessment for Class I and Sensitive Class II Areas

The CALPUFF model used data from the meteorological year 2006 to produce hourly values of pollutant 

concentrations at each receptor location for each of the following model scenarios:

• 2018 Projected Baseline – 2018 projected future emissions;

• 2017 Proposed Action – 2018 Projected Baseline emissions with project emissions from the 

proposed development alternative in 2017; and

• 2026 Optimal Recovery Alternative – 2018 Projected Baseline emissions with project emissions 

from the maximum recovery alternative action in 2026.

The hourly CALPUFF concentrations were processed using POSTUTIL and CALPOST to compute 3-hour, 

24-hour, and annual average concentration levels for the applicable pollutants and averaging periods. 

Regional haze estimates were produced for daily intervals, while total sulfur and nitrogen deposition fluxes 

were computed based on an average from the entire annual model simulation. Concentrations of NO2, SO2, 

PM10, PM2.5, sulfur and nitrogen deposition, as well as regional haze (aerosol light extinction) were predicted 

at selected receptor locations as described in Section 4.1.2.

5.1.1 Ambient Air Quality Impact Assessment – Criteria Pollutants

The CALPUFF modeled air concentrations of NOX, SO2, PM10, and PM2.5 predicted at the Class I and 

sensitive Class II areas were calculated for each of the three emissions scenarios: the 2018 Projected 

Baseline, the 2017 Proposed Action, and the 2026 Optimal Recovery Alternative scenarios. 

The CALPUFF modeled concentrations were calculated and compared with the allowable PSD increments 

for informational purposes only. This comparison to the PSD Class I and II increments was done because 

these increments represent a convenient means to evaluate the amount of air quality change due to the 

proposed project. This comparison does not represent a regulatory PSD increment consumption analysis 

since it involves other non-increment-affecting sources. 

In addition to comparing the CALPUFF modeled concentration to the PSD increments, a comparison also 

was made to the applicable health- and welfare-related NAAQS and SAAQS. The ambient ratio method, 

which assumes a conversion rate of 75 percent of NOX to NO2, was used according to USEPA guidance 

(40 CFR 51, Appendix W).

The modeling results for criteria pollutant impacts from CALPUFF are presented in Tables 5-1 and 5-2 for 

the projected action alternative scenarios at each identified Class I or sensitive Class II National Park (NP), 

Wilderness Area (WA), National Wildlife Refuge (NWR), and National Monument (NM). Results are 

presented for the total modeled impact from all sources along with the breakdown of project and non-project 
5-2 March 2012

sources. The impacts from non-project sources represent the 2018 Projected Baseline modeled scenario as 

if the project would not be built. The modeled concentrations presented in these tables for the separate 

source groups are not additive in each row for “all sources.” The maximum concentration that was modeled 

for any one source group can occur at a different time and in a different location than for all sources. The 

results for “all sources” represent only the combined impact of the whole group, not the sum of the separate 

maximum impacts. Each table presents the highest modeled criteria pollutant concentration (NOX, SO2, 

PM10, and PM2.5) for all receptors in each of the designated areas. 

Table 5-1 2017 Proposed Action CALPUFF Modeled Concentrations – Criteria Pollutants

Maximum Modeled Concentrations

All Sources PSD Class I / 

(Project + Project Non-Project Class II 

Averaging Non-Project) Sources Sources Increment NAAQS 

Area Pollutant Period (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3)

Class I Areas

Arches NP NOX Annual 1.861 0.001 1.860 2.5 100

SO2 3-hr 4.873 0.005 4.873 25 1300

24-hr 1.663 0.001 1.663 5 365

Annual 0.341 0.0001 0.341 2 80

PM10 24-hr 7.555 0.101 7.552 8 150

Annual 2.312 0.008 2.305 4 50

PM2.5 24-hr 2.479 0.055 2.479 2 35

Annual 0.497 0.004 0.493 1 15

Black Canyon of the NOX Annual 2.220 0.0005 2.219 2.5 100

Gunnison NP SO2 3-hr 3.181 0.002 3.181 25 1300

24-hr 1.533 0.001 1.533 5 365

Annual 0.468 0.00003 0.468 2 80

PM10 24-hr 25.487 0.069 25.486 8 150

Annual 9.323 0.004 9.319 4 50

PM2.5 24-hr 1.333 0.044 1.320 2 35

Annual 0.354 0.002 0.352 1 15

Canyonlands NP NOX Annual 0.781 0.001 0.781 2.5 100

SO2 3-hr 5.658 0.004 5.658 25 1300

24-hr 2.138 0.001 2.138 5 365

Annual 0.499 0.0001 0.499 2 80

PM10 24-hr 5.509 0.092 5.509 8 150

Annual 1.520 0.005 1.515 4 50

PM2.5 24-hr 2.608 0.046 2.607 2 35

Annual 0.387 0.003 0.385 1 15

Capitol Reef NP NOX Annual 0.481 0.0003 0.481 2.5 100

SO2 3-hr 9.287 0.002 9.287 25 1300

24-hr 2.564 0.001 2.564 5 365

Annual 0.503 0.00002 0.503 2 80

PM10 24-hr 4.320 0.074 4.319 8 150

Annual 1.307 0.002 1.305 4 50

PM2.5 24-hr 2.723 0.042 2.722 2 35

Annual 0.345 0.001 0.344 1 15

Mesa Verde NP NOX Annual 17.825 0.00003 17.825 2.5 100

SO2 3-hr 60.331 0.001 60.331 25 1300

24-hr 13.674 0.0003 13.674 5 365

Annual 0.723 0.00001 0.723 2 80

PM10 24-hr 28.205 0.042 28.205 8 150

Annual 8.099 0.001 8.097 4 50

PM2.5 24-hr 5.048 0.025 5.048 2 35

Annual 0.667 0.001 0.666 1 15

Eagles Nest WA NOX Annual 2.167 0.0003 2.166 2.5 100

SO2 3-hr 5.643 0.001 5.643 25 1300

24-hr 1.078 0.001 1.078 5 365

Annual 0.353 0.00003 0.353 2 80

PM10 24-hr 24.576 0.053 24.576 8 150

Annual 6.825 0.004 6.822 4 50

PM2.5 24-hr 1.376 0.031 1.349 2 35

Annual 0.307 0.002 0.305 1 15

 
5-3 March 2012

Table 5-1 2017 Proposed Action CALPUFF Modeled Concentrations – Criteria Pollutants

Maximum Modeled Concentrations

All Sources PSD Class I / 

(Project + Project Non-Project Class II 

Averaging Non-Project) Sources Sources Increment NAAQS 

Area Pollutant Period (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3)

Flat Tops WA NOX Annual 0.899 0.001 0.898 2.5 100

SO2 3-hr 7.188 0.003 7.188 25 1300

24-hr 1.184 0.001 1.184 5 365

Annual 0.211 0.0001 0.211 2 80

PM10 24-hr 8.093 0.084 8.088 8 150

Annual 2.436 0.009 2.431 4 50

PM2.5 24-hr 1.486 0.049 1.437 2 35

Annual 0.261 0.004 0.258 1 15

La Garita WA NOX Annual 1.010 0.0001 1.010 2.5 100

SO2 3-hr 3.882 0.001 3.882 25 1300

24-hr 0.919 0.0003 0.919 5 365

Annual 0.070 0.00001 0.070 2 80

PM10 24-hr 2.697 0.022 2.685 8 150

Annual 0.956 0.001 0.955 4 50

PM2.5 24-hr 1.067 0.011 1.059 2 35

Annual 0.393 0.001 0.393 1 15

Maroon Bells-Snowmass NOX Annual 1.190 0.0005 1.190 2.5 100

WA SO2 3-hr 2.640 0.001 2.640 25 1300

24-hr 0.783 0.0004 0.783 5 365

Annual 0.198 0.00004 0.198 2 80

PM10 24-hr 9.863 0.059 9.863 8 150

Annual 3.272 0.004 3.269 4 50

PM2.5 24-hr 1.278 0.036 1.264 2 35

Annual 0.301 0.002 0.298 1 15

Mount Zirkel WA NOX Annual 2.613 0.001 2.612 2.5 100

SO2 3-hr 8.309 0.002 8.309 25 1300

24-hr 2.613 0.001 2.613 5 365

Annual 0.582 0.0001 0.582 2 80

PM10 24-hr 21.251 0.090 21.239 8 150

Annual 8.102 0.006 8.096 4 50

PM2.5 24-hr 1.701 0.042 1.695 2 35

Annual 0.412 0.003 0.409 1 15

Weminuche WA NOX Annual 2.167 0.00004 2.167 2.5 100

SO2 3-hr 10.430 0.001 10.430 25 1300

24-hr 2.749 0.0003 2.749 5 365

Annual 0.239 0.00001 0.239 2 80

PM10 24-hr 12.917 0.022 12.917 8 150

Annual 4.871 0.001 4.870 4 50

PM2.5 24-hr 1.824 0.011 1.824 2 35

Annual 0.675 0.001 0.674 1 15

West Elk WA NOX Annual 1.388 0.0003 1.388 2.5 100

SO2 3-hr 2.143 0.001 2.143 25 1300

24-hr 0.778 0.0004 0.778 5 365

Annual 0.222 0.00003 0.222 2 80

PM10 24-hr 12.271 0.061 12.271 8 150

Annual 5.372 0.003 5.369 4 50

PM2.5 24-hr 1.310 0.038 1.296 2 35

Annual 0.248 0.002 0.247 1 15

Class II Areas

Colorado NM NOX Annual 1.707 0.002 1.706 25 100

(Class I for SO2) SO2 3-hr 7.494 0.003 7.494 25 1300

24-hr 1.640 0.001 1.640 5 365

Annual 0.501 0.0001 0.501 2 80

PM10 24-hr 35.109 0.113 35.100 30 150

Annual 9.995 0.009 9.988 17 50

PM2.5 24-hr 2.576 0.069 2.554 9 35

Annual 0.496 0.004 0.492 4 15

 

 
5-4 March 2012

Table 5-1 2017 Proposed Action CALPUFF Modeled Concentrations – Criteria Pollutants

Maximum Modeled Concentrations

All Sources PSD Class I / 

(Project + Project Non-Project Class II 

Averaging Non-Project) Sources Sources Increment NAAQS 

Area Pollutant Period (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3)

Dinosaur NM NOX Annual 4.900 0.142 4.758 25 100

(Class I for SO2) SO2 3-hr 5.633 0.058 5.633 25 1300

24-hr 1.703 0.018 1.701 5 365

Annual 0.338 0.003 0.336 2 80

PM10 24-hr 16.522 1.473 15.577 30 150

Annual 4.856 0.213 4.643 17 50

PM2.5 24-hr 7.104 0.693 6.706 9 35

Annual 1.178 0.099 1.079 4 15

Flaming Gorge National NOX Annual 9.064 0.495 8.568 25 100

Recreation Area (NRA) SO2 3-hr 52.061 0.190 52.061 512 1300

24-hr 12.477 0.047 12.477 91 365

Annual 2.362 0.008 2.362 20 80

PM10 24-hr 50.463 3.225 50.460 30 150

Annual 17.694 0.582 17.690 17 50

PM2.5 24-hr 7.559 1.197 6.883 9 35

Annual 2.464 0.245 2.219 4 15

High Uintah WA NOX Annual 1.163 0.001 1.162 25 100

SO2 3-hr 7.371 0.004 7.371 512 1300

24-hr 1.976 0.002 1.976 91 365

Annual 0.158 0.0001 0.158 20 80

PM10 24-hr 23.809 0.255 23.778 30 150

Annual 4.673 0.013 4.662 17 50

PM2.5 24-hr 2.667 0.148 2.664 9 35

Annual 0.351 0.007 0.343 4 15

Holy Cross WA NOX Annual 8.487 0.0003 8.487 25 100

SO2 3-hr 5.711 0.001 5.711 512 1300

24-hr 2.191 0.0005 2.191 91 365

Annual 1.033 0.00003 1.033 20 80

PM10 24-hr 64.425 0.037 64.425 30 150

Annual 27.202 0.004 27.199 17 50

PM2.5 24-hr 1.728 0.022 1.727 9 35

Annual 0.621 0.002 0.619 4 15

Hunter Frying Pan WA NOX Annual 3.476 0.0002 3.476 25 100

SO2 3-hr 3.263 0.001 3.263 512 1300

24-hr 1.285 0.0003 1.285 91 365

Annual 0.572 0.00003 0.572 20 80

PM10 24-hr 10.795 0.035 10.790 30 150

Annual 4.950 0.003 4.948 17 50

PM2.5 24-hr 1.303 0.022 1.288 9 35

Annual 0.393 0.002 0.392 4 15

Raggeds WA NOX Annual 1.879 0.0003 1.879 25 100

SO2 3-hr 2.039 0.001 2.039 512 1300

24-hr 0.665 0.0004 0.665 91 365

Annual 0.161 0.00003 0.161 20 80

PM10 24-hr 11.613 0.059 11.608 30 150

Annual 4.499 0.004 4.496 17 50

PM2.5 24-hr 1.200 0.036 1.185 9 35

Annual 0.245 0.002 0.244 4 15

Browns Park NWR NOX Annual 0.672 0.011 0.663 25 100

SO2 3-hr 3.151 0.009 3.151 512 1300

24-hr 0.720 0.002 0.720 91 365

Annual 0.174 0.0003 0.173 20 80

PM10 24-hr 3.302 0.248 3.123 30 150

Annual 1.095 0.033 1.067 17 50

PM2.5 24-hr 1.494 0.136 1.456 9 35

Annual 0.325 0.017 0.308 4 15

 

 
5-5 March 2012

Table 5-2 2026 Optimal Recovery Alternative CALPUFF Modeled Concentrations – Criteria Pollutants

Maximum Modeled Concentrations

Area Pollutant

Averaging 

Period

All Sources 

(Project + NonProject) 

(μg/m3)

Project 

Sources 

(μg/m3)

Non-Project 

Sources 

(μg/m3)

PSD 

Class I / Class II 

Increment 

(μg/m3)

NAAQS 

(μg/m3)

Class I Areas

Arches NP NOX Annual 1.862 0.003 1.860 2.5 100

SO2 3-hr 4.873 0.013 4.873 25 1300

24-hr 1.663 0.003 1.663 5 365

Annual 0.341 0.0002 0.341 2 80

PM10 24-hr 7.559 0.237 7.552 8 150

Annual 2.322 0.019 2.305 4 50

PM2.5 24-hr 2.479 0.107 2.479 2 35

Annual 0.501 0.008 0.493 1 15

Black Canyon of the 

Gunnison NP

NOX Annual 2.220 0.001 2.219 2.5 100

SO2 3-hr 3.181 0.006 3.181 25 1300

24-hr 1.533 0.002 1.533 5 365

Annual 0.468 0.0001 0.468 2 80

PM10 24-hr 25.488 0.151 25.486 8 150

Annual 9.328 0.009 9.319 4 50

PM2.5 24-hr 1.344 0.083 1.320 2 35

Annual 0.356 0.004 0.352 1 15

Canyonlands NP NOX Annual 0.782 0.001 0.781 2.5 100

SO2 3-hr 5.658 0.012 5.658 25 1300

24-hr 2.138 0.003 2.138 5 365

Annual 0.500 0.0001 0.499 2 80

PM10 24-hr 5.509 0.212 5.509 8 150

Annual 1.527 0.013 1.515 4 50

PM2.5 24-hr 2.608 0.091 2.607 2 35

Annual 0.390 0.005 0.385 1 15

Capitol Reef NP NOX Annual 0.481 0.001 0.481 2.5 100

SO2 3-hr 9.287 0.005 9.287 25 1300

24-hr 2.564 0.002 2.564 5 365

Annual 0.503 0.0001 0.503 2 80

PM10 24-hr 4.321 0.169 4.319 8 150

Annual 1.309 0.006 1.305 4 50

PM2.5 24-hr 2.723 0.083 2.722 2 35

Annual 0.346 0.002 0.344 1 15

Mesa Verde NP NOX Annual 17.825 0.0001 17.825 2.5 100

SO2 3-hr 60.331 0.002 60.331 25 1300

24-hr 13.674 0.001 13.674 5 365

Annual 0.723 0.00003 0.723 2 80

PM10 24-hr 28.205 0.095 28.205 8 150

Annual 8.100 0.003 8.097 4 50

PM2.5 24-hr 5.048 0.049 5.048 2 35

Annual 0.667 0.001 0.666 1 15

Eagles Nest WA NOX Annual 2.167 0.0005 2.166 2.5 100

SO2 3-hr 5.643 0.004 5.643 25 1300

24-hr 1.078 0.001 1.078 5 365

Annual 0.353 0.0001 0.353 2 80

PM10 24-hr 24.576 0.115 24.576 8 150

Annual 6.830 0.009 6.822 4 50

PM2.5 24-hr 1.401 0.059 1.349 2 35

Annual 0.309 0.004 0.305 1 15
5-6 March 2012

Table 5-2 2026 Optimal Recovery Alternative CALPUFF Modeled Concentrations – Criteria Pollutants

Maximum Modeled Concentrations

All Sources PSD 

(Project + Non- Project Non-Project Class I / Class II 

Averaging Project) Sources Sources Increment NAAQS 

Area Pollutant Period (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3)

Flat Tops WA NOX Annual 0.899 0.002 0.898 2.5 100

SO2 3-hr 7.189 0.007 7.188 25 1300

24-hr 1.184 0.002 1.184 5 365

Annual 0.211 0.0002 0.211 2 80

PM10 24-hr 8.099 0.190 8.088 8 150

Annual 2.444 0.020 2.431 4 50

PM2.5 24-hr 1.532 0.095 1.437 2 35

Annual 0.263 0.009 0.258 1 15

La Garita WA NOX Annual 1.011 0.0001 1.010 2.5 100

SO2 3-hr 3.882 0.002 3.882 25 1300

24-hr 0.919 0.001 0.919 5 365

Annual 0.094 0.00003 0.094 2 80

PM10 24-hr 2.711 0.056 2.685 8 150

Annual 0.958 0.003 0.955 4 50

PM2.5 24-hr 1.075 0.022 1.059 2 35

Annual 0.394 0.001 0.393 1 15

Maroon Bells- NOX Annual 1.191 0.001 1.190 2.5 100

Snowmass WA SO2 3-hr 2.640 0.004 2.640 25 1300

24-hr 0.783 0.001 0.783 5 365

Annual 0.198 0.0001 0.198 2 80

PM10 24-hr 9.863 0.130 9.863 8 150

Annual 3.275 0.010 3.269 4 50

PM2.5 24-hr 1.293 0.070 1.264 2 35

Annual 0.303 0.005 0.298 1 15

Mountt Zirkel WA NOX Annual 2.613 0.001 2.612 2.5 100

SO2 3-hr 8.309 0.004 8.309 25 1300

24-hr 2.613 0.002 2.613 5 365

Annual 0.582 0.0001 0.582 2 80

PM10 24-hr 21.266 0.210 21.239 8 150

Annual 8.110 0.014 8.096 4 50

PM2.5 24-hr 1.706 0.083 1.695 2 35

Annual 0.415 0.006 0.409 1 15

Weminuche WA NOX Annual 2.167 0.0001 2.167 2.5 100

SO2 3-hr 10.430 0.002 10.430 25 1300

24-hr 2.749 0.001 2.749 5 365

Annual 0.239 0.00003 0.239 2 80

PM10 24-hr 12.917 0.055 12.917 8 150

Annual 4.873 0.003 4.870 4 50

PM2.5 24-hr 1.824 0.022 1.824 2 35

Annual 0.675 0.001 0.674 1 15

West Elk WA NOX Annual 1.388 0.001 1.388 2.5 100

SO2 3-hr 2.143 0.003 2.143 25 1300

24-hr 0.778 0.001 0.778 5 365

Annual 0.222 0.0001 0.222 2 80

PM10 24-hr 12.271 0.134 12.271 8 150

Annual 5.375 0.008 5.369 4 50

PM2.5 24-hr 1.325 0.072 1.296 2 35

Annual 0.249 0.003 0.247 1 15

 
Table 5-2 2026 Optimal Recovery Alternative CALPUFF Modeled Concentrations – Criteria Pollutants

Maximum Modeled Concentrations

All Sources PSD 

(Project + Non- Project Non-Project Class I / Class

Averaging Project) Sources Sources Increment 

Area Pollutant Period (μg/m3) (μg/m3) (μg/m3) (μg/m3)

Class II Areas

Colorado NM NOX Annual 1.708 0.003 1.706 25

(Class I for SO2) SO2 3-hr 7.494 0.009 7.494 25

24-hr 1.640 0.002 1.640 5

Annual 0.501 0.0002 0.501 2

PM10 24-hr 35.123 0.245 35.100 30

Annual 10.005 0.021 9.988 17

PM2.5 24-hr 2.579 0.130 2.554 9

Annual 0.499 0.009 0.492 4

Dinosaur NM NOX Annual 5.021 0.263 4.758 25

(Class I for SO2) SO2 3-hr 5.634 0.149 5.633 25

24-hr 1.707 0.046 1.701 5

Annual 0.341 0.007 0.336 2

PM10 24-hr 17.773 3.291 15.577 30

Annual 5.151 0.507 4.643 17

PM2.5 24-hr 7.503 1.330 6.706 9

Annual 1.276 0.197 1.079 4

Flaming Gorge NRA NOX Annual 9.503 0.935 8.568 25

SO2 3-hr 52.061 0.489 52.061 512

24-hr 12.477 0.119 12.477 91

Annual 2.362 0.022 2.362 20

PM10 24-hr 50.468 7.358 50.460 30

Annual 17.698 1.382 17.690 17

PM2.5 24-hr 8.593 2.265 6.883 9

Annual 2.716 0.497 2.219 4

High Uintah WA NOX Annual 1.164 0.003 1.162 25

SO2 3-hr 7.371 0.010 7.371 512

24-hr 1.976 0.004 1.976 91

Annual 0.158 0.0002 0.158 20

PM10 24-hr 23.849 0.571 23.778 30

Annual 4.687 0.030 4.662 17

PM2.5 24-hr 2.671 0.290 2.664 9

Annual 0.358 0.015 0.343 4

Holy Cross WA NOX Annual 8.487 0.001 8.487 25

SO2 3-hr 5.711 0.003 5.711 512

24-hr 2.191 0.001 2.191 91

Annual 1.033 0.0001 1.033 20

PM10 24-hr 64.425 0.087 64.425 30

Annual 27.206 0.009 27.199 17

PM2.5 24-hr 1.729 0.043 1.727 9

Annual 0.623 0.004 0.619 4

Hunter Frying Pan NOX Annual 3.476 0.0004 3.476 25

WA SO2 3-hr 3.263 0.003 3.263 512

24-hr 1.285 0.001 1.285 91

Annual 0.572 0.0001 0.572 20

PM10 24-hr 10.804 0.079 10.790 30

Annual 4.953 0.007 4.948 17

PM2.5 24-hr 1.317 0.042 1.288 9

Annual 0.395 0.003 0.392 4

II 

NAAQS 

(μg/m3)

100

1300

365

80

150

50

35

15

100

1300

365

80

150

50

35

15

100

1300

365

80

150

50

35

15

100

1300

365

80

150

50

35

15

100

1300

365

80

150

50

35

15

100

1300

365

80

150

50

35

15

5-7 March 2012

 
5-8 March 2012

Table 5-2 2026 Optimal Recovery Alternative CALPUFF Modeled Concentrations – Criteria Pollutants

Maximum Modeled Concentrations

All Sources PSD 

(Project + Non- Project Non-Project Class I / Class II 

Averaging Project) Sources Sources Increment NAAQS 

Area Pollutant Period (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3)

Raggeds WA NOX Annual 1.879 0.001 1.879 25 100

SO2 3-hr 2.039 0.004 2.039 512 1300

24-hr 0.665 0.001 0.665 91 365

Annual 0.161 0.0001 0.161 20 80

PM10 24-hr 11.620 0.128 11.608 30 150

Annual 4.503 0.009 4.496 17 50

PM2.5 24-hr 1.214 0.069 1.185 9 35

Annual 0.247 0.004 0.244 4 15

Browns Park NWR NOX Annual 0.679 0.020 0.663 25 100

SO2 3-hr 3.151 0.024 3.151 512 1300

24-hr 0.722 0.006 0.720 91 365

Annual 0.174 0.001 0.173 20 80

PM10 24-hr 3.529 0.564 3.123 30 150

Annual 1.133 0.078 1.067 17 50

PM2.5 24-hr 1.549 0.265 1.456 9 35

Annual 0.341 0.033 0.308 4 15

 

As shown in Tables 5-1 and 5-2, project-related impacts on air quality in the Class I areas were very small. 

The maximum modeled impacts to Class I areas from the Proposed Action and Optimal Recovery 

Alternative occur at Arches National Park. The projected 24-hour PM10 maximum impact was 0.1 μg/m3 for 

the Proposed Action and 0.237 μg/m3 for the Optimal Recovery Alternative. Projected impacts for all other 

pollutants at the Class I areas for both scenarios were estimated at 0.2 μg/m3 or less.

For the listed Class II areas, the maximum modeled impacts from the Proposed Action and the Optimal 

Recovery Alternative occurred at the Flaming Gorge National Recreation Area and at Dinosaur National 

Monument. The maximum 24-hour PM10 impacts from the Proposed Action at the two areas were 3.2 and 

1.5 μg/m3

, respectively. For the Optimal Recovery Alternative, the project-related impacts at these two areas 

were 7.4 and 3.3 μg/m3

, respectively. Project-related impacts for all other pollutants at all the other Class II 

areas listed were less than 1 μg/m3

. 

When added to the background concentrations, all cumulative impacts at all Class I and Class II areas were 

below the established NAAQS.

5.1.2 Impact Assessment Air Quality Related Values – Regional Haze

For each modeled scenario, the model results provided estimated maximum visibility degradation (regional 

haze) at the listed Class I areas and specified Class II areas. The results identify contributions from model 

sources using a measure of visibility impairment in terms of percent change in extinction, or dv, relative to 

natural background conditions. The predicted regional haze results were compared with the threshold of 

10 percent of the reference background visibility, or 1.0 dv, for the impairment attributable to cumulative 

impacts from multiple sources. 

Two separate post-processing visibility analyses were used to assess regional haze impacts at the Class I 

areas and specified Class II areas of concern. The primary method (Method 6) is most widely implemented 

for visibility analyses under USEPA’s BART guideline and is consistent with the same approach that is 

applied to visibility analyses under the final regional haze rule. The secondary method provided for 

comparison is the standard “FLAG method” (Method 2), as proposed by FLAG (2000). 

The post-processing algorithm, CALPOST Method 6, was used with annual average background air quality 

data from Appendix B of USEPA’s “Guidance for Estimating Natural Visibility Conditions Under the 
5-9 March 2012

Regional Haze Program” (USEPA 2003b) for each Class I area. This method used site-specific monthly 

function of relative humidity (f[RH]) values to calculate the scattering efficiency of the hygroscopic 

component (i.e., ammonium sulfate and/or nitrate) of the annual average background concentrations, and 

thus, generated monthly background extinction values for each Class I area. The same procedure was used 

to calculate the hourly modeled extinction values that correspond to the hourly modeled CALPUFF 

concentrations and the same monthly f(RH) values. This method then calculated each day’s 24-hour 

average maximum percent change in extinction, expressed in dv, over all the receptors for each Class I 

area. 

The applicable site-specific monthly relative humidity adjustment factors were taken from Table A-3 in 

Appendix A in the “Guidance for Tracking Progress Under the Regional Haze Rule” (USEPA 2003a). This 

method was consistent with USEPA’s methodology in modeling of BART-eligible sources. The 98th 

percentile predicted visibility extinction impact was used as the indicator of impact on visibility in a given 

Class I area.

Results also were provided for an alternate method for visibility analysis (Method 2). Under this method, the 

FLAG-recommended speciated annual average hygroscopic and non-hygroscopic concentrations were 

used to describe the background air quality for each Class I area. However, unlike Method 6, Method 2 uses 

hourly relative humidity from the CALMET files to determine the daily average f(RH) value. These f(RH) 

values were used in a similar manner within CALPOST to calculate each day’s 24-hour average maximum 

percent change in extinction, expressed in dv, over all the receptors for each Class I area. 

Tables 5-3 and 5-4 provide the results from both Method 6 (primary) and Method 2 (secondary) for each of 

the modeled scenarios for each listed area. Method 6 results are presented in terms of number of days 

when modeled change from the specified background in dv is greater than both 0.5 and 1.0 dv, along with 

the maximum modeled and eighth highest change in dv for each Class I and Class II area of concern. 

Method 2 results are presented in terms of number of days when modeled percent change in extinction is 

greater than both 5 and 10 percent of the specified background, along with the maximum modeled change 

in extinction for each Class I and Class II area of concern. 

Results are presented for the total modeled impact from all sources along with the breakdown of project and 

non-project sources. The impacts from non-project sources represent the 2018 Projected Baseline modeled 

scenario as if the project would not be built.

Results of the regional haze analysis show that for the Method 6 analysis of impacts from project sources at 

Class I areas, there were no days with an incremental increase above 0.5 dv for either scenario. For the

Proposed Action, the maximum eighth highest value was 0.13 dv (1.3 percent increase in extinction) at 

Arches National Park. For the Optimal Recovery Alternative, the maximum eighth highest value was 

0.25 dv, also at Arches National Park. These projected impacts were less than 1.0 dv for regional haze 

impacts at Class I areas. Results of the Method 2 analysis for the Proposed Action showed no impacts 

above 0.5 dv at any Class I areas; and for the Optimal Recovery analysis, results showed only 2 days with 

impacts above 0.5 dv at Class I areas.

The results of the simulations under the Proposed Action scenario show that there were no days with a 

contribution to visibility impacts greater than 5 percent in extinction (0.5 dv) at listed Class I areas for either 

the Method 2 or Method 6 analysis. The conclusion is that the Proposed Action would not contribute to an 

impact on visibility at these sites. The modeling results at the listed sensitive Class II areas show the highest 

impacts at Flaming Gorge National Recreation Area and Dinosaur National Monument. However, the FLAG 

guidance provides no guidance or visibility thresholds for Class II areas. Results from Method 6 show that 

up to 102 days would be impacted with greater than 10 percent increase in extinction at Flaming Gorge. The 

same analysis shows the eighth highest increase in extinction for the Proposed Action at 32.6 percent. At 

Dinosaur National Monument, the model predicted 32 days per year with an impact above 10 percent and 

an eighth highest increase in light extinction of 16.6 percent. Except at Flaming Gorge National Recreation 
5-10 March 2012

Table 5-3 2017 Proposed Action CALPUFF Modeled Results – Regional Haze

All Sources (Project + Non-Project) Project Sources Non-Project Sources

Area

Days > than MAX% ∆

Bext

8th Highest 

% ∆ Bext

Days > than MAX% ∆

Bext

8th Highest 

% ∆ Bext

Days > than MAX% ∆

Bext

8th Highest 

5% ∆ Bext 10% ∆ Bext 5% ∆ Bext 10% ∆ Bext 5% ∆ Bext 10% ∆ Bext % ∆ Bext

Method 6, Annual Average Natural Conditions Background

Class I Areas

Arches NP 359 311 118.47 82.29 0 0 2.56 1.30 359 311 118.47 81.84

Black Canyon of the Gunnison NP 365 364 133.96 105.94 0 0 1.76 0.49 365 364 133.94 105.92

Canyonlands NP 328 236 106.52 68.85 0 0 1.98 1.12 328 236 106.50 68.85

Capitol Reef NP 327 223 110.77 74.75 0 0 1.79 0.80 327 223 110.75 74.75

Mesa Verde NP 365 365 155.14 122.13 0 0 0.80 0.16 365 365 155.13 122.10

Eagles Nest WA 365 359 107.04 83.71 0 0 1.17 0.53 365 359 107.04 83.71

Flat Tops WA 365 348 55.02 45.70 0 0 1.86 1.01 365 348 54.72 45.58

La Garita WA 365 354 49.43 33.36 0 0 0.42 0.21 365 354 49.14 33.35

Maroon Bells-Snowmass W 365 360 67.48 54.52 0 0 1.32 0.56 365 360 67.35 53.26

Mount Zirkel WA 365 365 125.44 100.78 0 0 1.65 0.74 365 365 125.21 100.73

Weminuche WA 365 365 104.32 84.87 0 0 0.34 0.16 365 365 104.32 84.87

West Elk WA 365 365 74.35 57.74 0 0 1.48 0.47 365 365 74.35 56.75

Class II Areas

Colorado NM 364 361 158.52 138.59 0 0 2.67 1.00 364 361 158.41 138.00

Dinosaur NM 365 364 166.24 131.74 73 32 30.54 16.60 365 363 147.81 123.53

Flaming Gorge NRA 365 365 280.99 240.99 150 102 41.89 32.57 365 365 256.70 221.14

High Uintah WA 365 363 121.35 73.02 2 0 5.70 3.53 365 363 120.67 72.78

Holy Cross WA 365 365 318.99 243.94 0 0 0.79 0.44 365 365 318.99 243.78

Hunter Frying Pan WA 365 365 77.30 60.17 0 0 0.79 0.41 365 365 76.76 60.08

Raggeds WA 365 362 64.91 44.85 0 0 1.34 0.51 365 362 64.41 44.84

Browns Park NWR 313 206 62.58 46.90 1 0 5.12 3.24 313 201 61.13 45.03
5-11 March 2012

Table 5-3 2017 Proposed Action CALPUFF Modeled Results – Regional Haze

All Sources (Project + Non-Project) Project Sources Non-Project Sources

8th 8th 8th Days > than MAX% ∆ Highest Days > than MAX% ∆ Highest Days > than MAX% ∆ Highest 

Area 5% ∆ Bext 10% ∆ Bext Bext % ∆ Bext 5% ∆ Bext 10% ∆ Bext Bext % ∆ Bext 5% ∆ Bext 10% ∆ Bext Bext % ∆ Bext

Method 2, Background

Class I Areas

Arches NP 359 305 186.94 NA 0 0 2.29 NA 359 305 186.94 NA

Black Canyon of the Gunnison NP 365 364 140.95 NA 0 0 2.92 NA 365 364 138.03 NA

Canyonlands NP 319 215 83.92 NA 0 0 1.57 NA 319 214 83.85 NA

Capitol Reef NP 326 232 127.25 NA 0 0 2.21 NA 326 232 127.23 NA

Mesa Verde NP 365 365 175.00 NA 0 0 1.14 NA 365 365 174.99 NA

Eagles Nest WA 365 359 117.69 NA 0 0 1.56 NA 365 359 117.56 NA

Flat Tops WA 365 348 79.58 NA 0 0 2.68 NA 365 348 79.11 NA

La Garita WA 365 354 48.05 NA 0 0 0.63 NA 365 354 48.05 NA

Maroon Bells-Snowmass WA 365 362 95.64 NA 0 0 2.22 NA 365 362 95.64 NA

Mt Zirkel WA 365 365 154.57 NA 0 0 2.31 NA 365 365 154.23 NA

Weminuche WA 365 365 104.76 NA 0 0 0.54 NA 365 365 104.76 NA

West Elk WA 365 365 100.34 NA 0 0 2.57 NA 365 365 100.34 NA

Class II Areas

Colorado NM 364 359 177.98 NA 0 0 3.78 NA 364 359 177.97 NA

Dinosaur NM 365 363 245.5 NA 82 40 43.42 NA 365 362 232.1 NA

Flaming Gorge NRA 365 365 435.87 NA 153 104 78.88 NA 365 365 356.99 NA

High Uintah WA 365 365 180.77 NA 6 0 7.03 NA 365 365 180.17 NA

Holy Cross WA 365 365 313.06 NA 0 0 1.37 NA 365 365 313.06 NA

Hunter Frying Pan WA 365 365 88.10 NA 0 0 1.43 NA 365 365 87.44 NA

Raggeds WA 365 362 74.07 NA 0 0 1.78 NA 365 362 73.53 NA

Browns Park NWR 310 197 99.44 NA 2 0 7.76 NA 309 191 94.69 NA
5-12 March 2012

Table 5-4 2026 Optimal Recovery Alternative CALPUFF Modeled Results – Regional Haze

All Sources (Project + Non-Project) Project Sources Non-Project Sources

Days > than MAX% ∆

Bext

8th Highest 

% ∆ Bext

Days > than MAX% ∆

Bext

8th Highest 

% ∆ Bext

Days > than MAX% ∆

Bext

8th Highest 

Area 5% ∆ Bext 10% ∆ Bext 5% ∆ Bext 10% ∆ Bext 5% ∆ Bext 10% ∆ Bext % ∆ Bext

Method 6, Annual Average Natural Conditions Background

Class I Areas

Arches NP 359 311 118.47 82.72 0 0 4.99 2.51 359 311 118.47 81.84

Black Canyon of the Gunnison NP 365 364 133.98 105.97 0 0 3.31 0.99 365 364 133.94 105.92

Canyonlands NP 328 236 106.54 68.85 0 0 3.89 2.20 328 236 106.50 68.85

Capitol Reef NP 327 223 110.78 74.75 0 0 3.49 1.60 327 223 110.75 74.75

Mesa Verde NP 365 365 155.14 122.17 0 0 1.56 0.32 365 365 155.13 122.10

Eagles Nest WA 365 359 107.04 83.71 0 0 2.18 1.03 365 359 107.04 83.71

Flat Tops WA 365 349 55.34 45.81 0 0 3.59 1.97 365 348 54.72 45.58

La Garita WA 365 355 49.72 33.37 0 0 0.80 0.46 365 354 49.14 33.35

Maroon Bells-Snowmass WA 365 360 67.60 54.75 0 0 2.55 1.11 365 360 67.35 53.26

Mt Zirkel WA 365 365 125.65 100.83 0 0 3.28 1.45 365 365 125.21 100.73

Weminuche WA 365 365 104.32 84.87 0 0 0.65 0.32 365 365 104.32 84.87

West Elk WA 365 365 74.35 57.75 0 0 2.80 0.92 365 365 74.35 56.75

Class II Areas

Colorado NM 364 361 158.64 139.15 1 0 5.03 1.99 364 361 158.41 138.00

Dinosaur NM 365 364 187.10 146.42 129 71 56.77 32.72 365 363 147.81 123.53

Flaming Gorge NRA 365 365 306.23 256.94 198 156 83.70 62.37 365 365 256.70 221.14

High Uintah WA 365 363 122.05 73.21 11 1 11.11 6.86 365 363 120.67 72.78

Holy Cross WA 365 365 318.99 244.11 0 0 1.52 0.85 365 365 318.99 243.78

Hunter Frying Pan WA 365 365 77.82 60.26 0 0 1.54 0.81 365 365 76.76 60.08

Raggeds WA 365 362 65.42 45.07 0 0 2.55 1.02 365 362 64.41 44.84

Browns Park NWR 313 207 65.31 49.06 20 0 9.92 6.19 313 201 61.13 45.03
5-13 March 2012

Table 5-4 2026 Optimal Recovery Alternative CALPUFF Modeled Results – Regional Haze

All Sources (Project + Non-Project) Project Sources Non-Project Sources

8th 8th 8th Days > than MAX% ∆ Highest Days > than MAX% ∆ Highest Days > than MAX% ∆ Highest 

Area 5% ∆ Bext 10% ∆ Bext Bext % ∆ Bext 5% ∆ Bext 10% ∆ Bext Bext % ∆ Bext 5% ∆ Bext 10% ∆ Bext Bext % ∆ Bext

Method 2, Background

Class I Areas

Arches NP 359 305 186.94 NA 0 0 4.48 NA 359 305 186.94 NA

Black Canyon of the Gunnison NP 365 364 143.44 NA 1 0 5.41 NA 365 364 138.03 NA

Canyonlands NP 319 215 83.99 NA 0 0 3.09 NA 319 214 83.85 NA

Capitol Reef NP 326 232 127.27 NA 0 0 4.26 NA 326 232 127.23 NA

Mesa Verde NP 365 365 175.00 NA 0 0 2.19 NA 365 365 174.99 NA

Eagles Nest WA 365 359 117.82 NA 0 0 2.86 NA 365 359 117.56 NA

Flat Tops WA 365 349 80.00 NA 1 0 5.10 NA 365 348 79.11 NA

La Garita WA 365 354 48.06 NA 0 0 1.19 NA 365 354 48.05 NA

Maroon Bells-Snowmass WA 365 362 95.64 NA 0 0 4.23 NA 365 362 95.64 NA

Mt Zirkel WA 365 365 154.90 NA 0 0 4.51 NA 365 365 154.23 NA

Weminuche WA 365 365 104.77 NA 0 0 1.02 NA 365 365 104.76 NA

West Elk WA 365 365 100.34 NA 0 0 4.79 NA 365 365 100.34 NA

Class II Areas

Colorado NM 364 359 177.99 NA 1 0 7.03 NA 364 359 177.97 NA

Dinosaur NM 365 363 280.79 NA 135 81 80.32 NA 365 362 232.10 NA

Flaming Gorge NRA 365 365 483.51 NA 199 156 126.52 NA 365 365 356.99 NA

High Uintah WA 365 365 181.37 NA 11 6 13.68 NA 365 365 180.17 NA

Holy Cross WA 365 365 313.06 NA 0 0 2.63 NA 365 365 313.06 NA

Hunter Frying Pan WA 365 365 88.73 NA 0 0 2.74 NA 365 365 87.44 NA

Raggeds WA 365 362 74.62 NA 0 0 3.34 NA 365 362 73.53 NA

Browns Park NWR 312 202 104.36 NA 20 1 14.75 NA 309 191 94.69 NA
5-14 March 2012

Area and Dinosaur National Monument, modeled results for all other Class II areas under Method 6 show all 

of the eighth highest impacts at less than a 10 percent increase in extinction (1.0 dv).

For the Optimal Recovery Alternative, all project impacts were below 10 percent light extinction at all Class I 

areas. At Class II areas under the Optimal Recovery Alternative, the eighth highest impacts using Method 6 

were above 10 percent at Flaming Gorge National Recreation Area and Dinosaur National Monument. The 

eighth highest increase in light extinction for project-related sources was 62.4 percent at Flaming Gorge 

National Recreation Area, with 156 days predicted to be greater than 10 percent. At Dinosaur National 

Monument, the eighth highest increase in light extinction was 32.7 percent, with 71 days predicted to be 

greater than 10 percent.

5.1.3 Acid Deposition and Lake Chemistry

For each modeled scenario, CALPUFF was used to estimate annual wet, dry, and total (wet plus dry) 

deposition fluxes of total nitrogen and sulfur compounds due to the contributions from the modeled sources 

at the Class I and Class II areas of concern.

The acid deposition modeling results also were used to provide an additional analysis in terms of the ANC 

for selected sensitive water bodies. An estimation of potential changes in ANC at several specified sensitive 

lake receptors was made by following the procedure developed by the USFS Rocky Mountain Region 

(USFS 2000). Figure 5-1 shows the location of the sensitive lakes included in the ANC analysis. The 

guideline post-processing utility program, POSTUTIL, was used to sum all wet and dry fluxes of NO3, HNO3, 

NOX, SO2, and SO4. The total nitrogen and sulfur deposition were then computed from the summed fluxes. 

Predicted changes in ANC were then compared with the threshold (10 percent change in ANC for lakes with 

background ANC values greater than 25 micro equivalents per liter [μeq/l], and no more than a 1 μeq/l

change in ANC for lakes with background ANC values equal to or less than 25 μeq/l). 

The modeling results for the acid deposition impacts from CALPUFF are presented in Tables 5-5 and 5-6

for the 2017 Proposed Action and 2026 Optimal Recovery Alternative scenarios, respectively. Each table 

presents both the annual average total nitrogen and sulfur deposition results for each modeled scenario. 

Results are presented for the total modeled impact from all sources along with the breakdown of project and 

non-project sources. The impacts from non-project sources represent the 2018 Projected Baseline modeled 

scenario as if the project would not be built. 

The maximum acid deposition at Class I areas for the Proposed Action is 0.0016 kg/ha-yr at the Flat Tops 

Wilderness Area, and impacts at other Class I areas generally were 0.001 kg/ha-yr or less. For the Optimal 

Recovery Alternative, the maximum deposition rate for nitrogen compounds was 0.003 kg/ha-yr at the Flat 

Tops Wilderness Area, and less for all other Class I areas.

The maximum acid deposition rate at the listed Class II areas was predicted for the Flaming Gorge National 

Recreation Area. The maximum deposition from the Proposed Action was 0.06 kg/ha-yr. For the Optimal 

Recovery Alternative, the maximum deposition rate was 0.12 kg/ha-yr for nitrogen compounds.

The results of the acidic neutralizing capacity analysis for the selected lakes are presented in Table 5-7. 

Impacts from project-related sources for both scenarios were less than the 1 percent threshold for all lakes, 

and the deposition rates were all less than 0.06 μeq/l or less than 0.12 μeq/l at all identified lakes for the 

Proposed Action and Optimal Recovery Alternative, respectively.
5-15 March 2012

Figure 5-1 Sensitive Lakes Analyzed in the Acid Neutralizing Capacity Analysis
5-16 March 2012

Table 5-5 2017 Proposed Action CALPUFF Modeled Results – Acid Deposition

Maximum Modeled Deposition

Area Pollutant

All Sources (Project 

+ Non-Project) 

(kg/ha - yr)

Project Sources 

(kg/ha - yr)

Non-Project 

Sources 

(kg/ha - yr)

Comparative 

Deposition Value 

(kg/ha - yr)

Class I Areas

Arches NP Nitrogen 0.325 0.0010 0.324 3

Sulfur 0.185 0.00004 0.185 5

Black Canyon of the Gunnison NP Nitrogen 0.459 0.0008 0.458 3

Sulfur 0.241 0.00003 0.241 5

Canyonlands NP Nitrogen 0.203 0.0005 0.202 3

Sulfur 0.201 0.00002 0.201 5

Capitol Reef NP Nitrogen 0.114 0.0003 0.113 3

Sulfur 0.143 0.00001 0.143 5

Mesa Verde NP Nitrogen 4.956 0.0002 4.955 3

Sulfur 0.646 0.00001 0.646 5

Eagles Nest WA Nitrogen 0.809 0.0011 0.808 3

Sulfur 0.238 0.00004 0.238 5

Flat Tops WA Nitrogen 0.267 0.0016 0.266 3

Sulfur 0.146 0.0001 0.146 5

La Garita WA Nitrogen 0.380 0.0003 0.379 3

Sulfur 0.096 0.00001 0.096 5

Maroon Bells-Snowmass WA Nitrogen 0.408 0.0010 0.407 3

Sulfur 0.163 0.00003 0.163 5

Mt Zirkel WA Nitrogen 0.645 0.0012 0.643 3

Sulfur 0.304 0.00004 0.304 5

Weminuche WA Nitrogen 0.586 0.0003 0.586 3

Sulfur 0.213 0.00001 0.213 5

West Elk WA Nitrogen 0.273 0.0007 0.272 3

Sulfur 0.163 0.00002 0.163 5

Class II Areas

Colorado NM Nitrogen 0.440 0.0017 0.439 3

Sulfur 0.274 0.00007 0.273 5

Dinosaur NM Nitrogen 0.695 0.0296 0.665 3

Sulfur 0.204 0.0009 0.203 5

Flaming Gorge NRA Nitrogen 1.429 0.0619 1.429 3

Sulfur 0.852 0.0017 0.852 5

High Uintah WA Nitrogen 0.443 0.0015 0.442 3

Sulfur 0.157 0.00005 0.157 5

Holy Cross WA Nitrogen 2.603 0.0010 2.602 3

Sulfur 0.590 0.00003 0.590 5

Hunter Frying Pan WA Nitrogen 1.131 0.0007 1.130 3

Sulfur 0.337 0.00002 0.337 5

Raggeds WA Nitrogen 0.465 0.0008 0.464 3

Sulfur 0.130 0.00003 0.130 5

Browns Park NWR Nitrogen 0.237 0.0053 0.232 3

Sulfur 0.117 0.0002 0.117 5
5-17 March 2012

Table 5-6 2026 Optimal Recovery Alternative CALPUFF Modeled Results – Acid Deposition

Maximum Modeled Deposition

Area Pollutant

All Sources (Project 

+ Non-Project) 

(kg/ha - yr)

Project 

Sources 

(kg/ha - yr)

Non-Project 

Sources 

(kg/ha - yr)

Comparative 

Deposition Value 

(kg/ha - yr)

Class I Areas

Arches NP Nitrogen 0.326 0.002 0.324 3

Sulfur 0.185 0.0001 0.185 5

Black Canyon of the Gunnison NP Nitrogen 0.460 0.001 0.458 3

Sulfur 0.241 0.0001 0.241 5

Canyonlands NP Nitrogen 0.203 0.001 0.202 3

Sulfur 0.201 0.0001 0.201 5

Capitol Reef NP Nitrogen 0.114 0.001 0.113 3

Sulfur 0.143 0.00002 0.143 5

Mesa Verde NP Nitrogen 4.956 0.0004 4.955 3

Sulfur 0.647 0.00003 0.646 5

Eagles Nest WA Nitrogen 0.810 0.002 0.808 3

Sulfur 0.238 0.0001 0.238 5

Flat Tops WA Nitrogen 0.269 0.003 0.266 3

Sulfur 0.146 0.0002 0.146 5

La Garita WA Nitrogen 0.380 0.001 0.379 3

Sulfur 0.096 0.00004 0.096 5

Maroon Bells-Snowmass WA Nitrogen 0.409 0.002 0.407 3

Sulfur 0.163 0.0001 0.163 5

Mount Zirkel WA Nitrogen 0.646 0.002 0.643 3

Sulfur 0.304 0.0001 0.304 5

Weminuche WA Nitrogen 0.587 0.001 0.586 3

Sulfur 0.213 0.00003 0.213 5

West Elk WA Nitrogen 0.274 0.001 0.272 3

Sulfur 0.163 0.0001 0.163 5

Class II Areas

Colorado NM Nitrogen 0.441 0.003 0.439 3

Sulfur 0.274 0.0002 0.273 5

Dinosaur NM Nitrogen 0.721 0.055 0.665 3

Sulfur 0.205 0.002 0.203 5

Flaming Gorge NRA Nitrogen 1.429 0.116 1.429 3

Sulfur 0.852 0.005 0.852 5

High Uintah WA Nitrogen 0.444 0.003 0.442 3

Sulfur 0.157 0.0001 0.157 5

Holy Cross WA Nitrogen 2.604 0.002 2.602 3

Sulfur 0.590 0.0001 0.590 5

Hunter Frying Pan WA Nitrogen 1.131 0.001 1.130 3

Sulfur 0.337 0.0001 0.337 5

Raggeds WA Nitrogen 0.466 0.002 0.464 3

Sulfur 0.130 0.0001 0.130 5

Browns Park NWR Nitrogen 0.241 0.010 0.232 3

Sulfur 0.118 0.001 0.117 5
5-18 March 2012

Table 5-7 Modeled Impacts on Acid Sensitive Lakes

Annual 2017 Proposed Action 2026 Optimal Recovery

Wilderness Area/Lake

Background 

ANC

(ueq/l)

Number 

of

Samples

Watershed 

Area

(ha)

Averaged 

Precipitation 

(m)

ANC(o) 

(eq)

Project Only Sources All Sources Project Sources Only All Sources

%ANC 

Change

Hdep 

(ueq/l)

%ANC 

Change

Hdep 

(ueq/l)

%ANC 

Change

Hdep 

(ueq/l)

%ANC 

Change

Hdep

(ueq/l)

Eagles Nest Wilderness

Booth Lake 86.4 42 54.0 0.29 9,190.2 0.04 0.03 11.3 9.8 0.07 0.06 11.4 9.8

Upper Willow Lake 133.2 43 124.0 0.29 32,549.4 0.02 0.03 5.3 7.0 0.04 0.05 5.3 7.0

Flat Tops Wilderness

Ned Wilson Lake 39.4 193 49.2 0.26 3,312.0 0.15 0.06 34.8 13.7 0.29 0.12 34.9 13.7

Trappers Lake1 659.4 59 -- 0.26 -- -- -- -- -- -- -- -- --

Upper Ned Wilson Lake 12.9 144 3.1 0.26 68.7 0.45 0.06 105.2 13.6 0.86 0.11 105.6 13.6

La Garita Wilderness

Small Lake Above U-Shaped Lake 63.3 19 26.0 0.36 4,013.3 0.04 0.02 13.7 8.7 0.07 0.05 13.7 8.7

U-Shaped Lake 79.3 18 66.0 0.36 12,749.8 0.03 0.02 10.8 8.5 0.06 0.05 10.8 8.5

Maroon Bells-Snowmass Wilderness

Avalanche Lake 171.0 51 358.0 0.24 96,575.6 0.02 0.04 11.8 20.2 0.04 0.07 11.9 20.3

Capitol Lake 186.6 51 139.0 0.24 40,918.0 0.03 0.05 10.3 19.2 0.05 0.10 10.3 19.2

Moon Lake (Upper) 54.3 49 117.0 0.24 10,018.8 0.10 0.05 33.6 18.2 0.19 0.10 33.6 18.3

Mount Zirkel Wilderness

Lake Elbert 53.8 68 101.0 0.42 15,476.4 0.01 0.01 27.1 14.6 0.03 0.01 27.1 14.6

Summit Lake 48.0 110 7.8 0.42 1,061.9 0.02 0.01 41.8 20.0 0.03 0.01 41.8 20.1

Weminuche Wilderness

Big Eldorado Lake 20.4 54 115.0 0.47 7,430.2 0.03 0.01 24.8 5.1 0.06 0.01 24.8 5.1

Little Eldorado Lake -3.3 53 48.7 0.47 -509.3 -0.21 0.01 -153.1 5.1 -0.40 0.01 -153.3 5.1

Lower Sunlight Lake 85.0 52 96.6 0.47 26,030.9 0.01 0.01 11.2 9.5 0.03 0.02 11.2 9.5

Upper Grizzly Lake 29.9 45 30.0 0.47 2,840.5 0.07 0.02 37.2 11.1 0.13 0.04 37.2 11.1

Upper Sunlight Lake 28.0 51 76.9 0.47 6,823.0 0.06 0.02 35.1 9.8 0.12 0.03 35.1 9.8

White Dome Lake 2.1 52 38.8 0.47 253.3 0.83 0.02 295.1 6.1 1.58 0.03 295.4 6.1

West Elk Wilderness

South Golden Lake 112.6 23 73.0 0.29 15,946.8 0.03 0.03 9.1 10.3 0.05 0.06 9.2 10.3

High Uintas Wilderness

Dean Lake 51.4 7 117.0 0.41 16,569.3 0.01 0.01 17.3 8.9 0.02 0.01 17.4 8.9

Fish Lake1 104.5 6 -- 0.41 -- -- -- -- -- -- -- -- --

Raggeds Wilderness

Deep Creek Lake 40.0 26 525.0 0.28 39,811.9 0.03 0.01 40.2 16.1 0.05 0.02 40.3 16.1

Island Lake2 -- -- -- 0.28 -- -- -- -- -- -- -- -- --

1 For Trappers and Fish lakes, ANC calculations could not be made because the watershed area was not provided in the database from the USFS.

2 For Island Lake, ANC calculations could not be made because there was no data in the USFS database for this lake.
5-19 March 2012

5.2 CMAQ Ozone Impact Assessment

5.2.1 CMAQ 2005/2006 Base Case Modeling Results

A group of representatives from the oil and gas industry, along with federal and state air quality agencies, 

participated in a coordinated analysis of air quality impacts within the Uinta Basin. Under their direction and 

coordination by the Independent Petroleum Association of the Mountain States, the UBAQS analyzed the 

impact of projected development on the ambient levels of ozone and other air quality constituents in the 

region (ENVIRON 2009). The CMAQ modeling that is provided here used emissions and meteorological 

input data consistent with the UBAQS. While the UBAQS estimated impacts for 2012, this analysis 

estimated impacts projected for 2017 and 2026 using cumulative development projections through 2018.

Table 5-8 compares the UBAQS CMAQ 2005 and 2006 base case simulation ozone model performance 

across AIRS and CASTNet monitoring sites in the 12-km domain with USEPA hourly ozone model 

performance goals for bias (≤±15 percent) and error (≤35 percent) (USEPA 1991). Presented in Table 5-8

are the fractional, normalized mean, and mean normalized ozone performance metrics for both bias and 

error for 2005 and 2006. These were calculated using hourly predicted and observed ozone pairs for which 

the observed value was above a 60 ppb threshold (USEPA 1991). Bias and error performance statistics in 

Table 5-8 are only presented for quarters when there is a minimum of at least 100 predicted and observed 

hourly ozone pairs available. For the second quarter of 2005 and the first and second quarters of 2006, the 

UBAQS CMAQ base case ozone performance always achieved the USEPA ozone performance goal. 

During the third quarters of both 2005 and 2006, the CMAQ ozone bias performance metrics were very near 

the -15 percent ozone performance goal, with some of the bias metrics achieving the goal and others just 

outside of the goal. However, the CMAQ error ozone performance metrics for these quarters achieved the 

≤35 percent ozone performance goal by more than a factor of two.

Table 5-8 Ozone Model Performance Bias and Error Statistics

Year/Quarter

Bias (Percent) Error (Percent)

Fractional

Normalized 

Mean

Mean 

Normalized Fractional

Normalized 

Mean Gross

Mean Normalized 

Gross Number1

2005 Quarter 2 -5.80 -5.16 -4.82 11.16 10.65 10.51 2,015

2005 Quarter 3 -16.75 -15.04 -14.89 17.52 15.82 15.70 1,388

2006 Quarter 1 -5.00 -4.52 -4.43 8.56 8.18 8.14 278

2006 Quarter 2 -4.06 -3.66 -3.40 9.14 8.87 8.77 3,174

2006 Quarter 3 -16.48 -14.83 -14.71 16.86 15.21 15.11 1,179

1 Number of predicted and observed ozone pairs available. Data shown only for quarters where greater than 100 pairs available for analysis.

The UBAQS CMAQ base case simulations also satisfied the USEPA daily maximum 8-hour ozone 

concentration performance goal that requires predicted daily maximum 8-hour ozone concentration “near 

the monitor” to be within ±20 percent of the observed value most of the time (USEPA 1999). Even using the 

most stringent definition of “near the monitor,” which is based on the predicted 8-hour ozone concentration 

at the monitor, the CMAQ base case predicted daily maximum 8-hour ozone concentration is within 

±20 percent of the observed value 90 and 83 percent of the time for the 2005 and 2006 modeling years, 

respectively. 

The 8-hour ozone NAAQS was expressed as the 3-year average of the fourth highest daily maximum 

8-hour ozone concentrations. Thus, an important ozone performance issue when analyzing the future year 

CMAQ absolute modeling results was the fourth highest daily maximum 8-hour ozone concentration in each 

modeled year. Figure 5-2 depicts the CMAQ estimated (modeled) fourth highest daily maximum 8-hour 

ozone concentration and the observed values for 2005 and 2006. Modeled data are shown as the shaded 
5-20 March 2012

2005

2006

Figure 5-2 Depiction of Predicted and Observed Fourth highest Daily Maximum 8-hour Ozone 

Concentrations for 2005 and 2006
5-21 March 2012

patterns, and observations are shown as whole numbers at their applicable station location. The modeled 

fourth highest daily maximum 8-hour ozone concentrations were comparable to the observed values; 

however, at the locations of the ozone monitors, the predicted values were usually higher than the observed 

values, resulting in an overprediction bias. This bias was greater in 2006 than in 2005 and needs to be 

accounted for when interpreting the future year absolute model ozone predictions.

5.2.2 CMAQ Ozone Impact Assessment of Alternatives

The following subsections present the ozone impacts of the 2018 Projected Baseline, 2017 Proposed 

Action, and 2026 Optimal Recovery Alternative scenarios using both the USEPA guidance relative impact

approach (USEPA 2007) and an absolute impact approach. Considerable caution must be taken in 

interpreting the modeled project impacts. In traditional CMAQ ozone modeling applications, the model is 

applied in regions with sufficient ozone and precursor observations to judge the adequacy of the model for 

use in ozone analysis. In this application, the closest rural monitor with a long enough data record to be 

used for attainment designation was the Canyonlands site approximately 150 km from the project area. 

Ozone observations closer to the project (Vernal and Dinosaur National Park) were operated for shorter 

time periods that did not correspond to the 2005/2006 period being modeled and were not able to be used 

for the performance evaluation. Without sufficient local monitored ozone data, the base and future year 

model estimated ozone levels were suspect; however, the comparative modeled ozone levels among the 

alternatives were considered a reliable evaluation. 

5.2.2.1 Results Using USEPA Guidance Ozone Projection Approach

The USEPA metrics for determining attainment of the ozone standard are based on the modeled ozone 

concentrations at a monitor location. Both the relative and absolute values of ozone modeling were used in 

this analysis, as discussed below. 

5.2.2.2 USEPA Guidance 8-Hour Ozone Projection Procedures

USEPA guidance for projecting future 8-hour ozone concentrations recommends using the photochemical 

grid model in a relative sense to scale current observed 8-hour design values (USEPA 2007). A design 

value is defined as a consecutive 3-year average of the fourth highest daily maximum 8-hour ozone 

concentrations at a monitor. Model scaling factors, referred to as relative response factors (RRFs), were

used to scale the observed design values to predict future year design values. RRFs are the ratio of the 

future year (or the control case) to the current-year modeled 8-hour ozone concentrations near a monitor 

site. USEPA has defined “near the monitor” to be approximately 15 km from the monitor location. The 

future-year design value (DVf) is obtained from the current-year design value (DVc) using the relation:

 DVf = DVc x RRF

The RRFs are calculated for all days in which the current-year modeled 8-hour ozone value is above a 

threshold. This is done so that the model response to future changes in emissions is considered only on 

high ozone days of comparable conditions to the days used to produce the DVc. USEPA recommends a 

threshold between 70 and 85 ppb.

To perform the 8-hour projections, USEPA has developed the Modeled Attainment Test Software (MATS) 

tool that uses modeling results, 8-hour ozone design values, and follows USEPA guidance (USEPA 2007) 

to project 8-hour ozone concentrations that reflect the change in emissions from the base case to an 

alternative emissions scenario. 

USEPA modeling guidance procedures (USEPA 2007) recommend using a DVc based on an average of 

3-year 8-hour ozone design values that span 5 consecutive years centered on the modeling year (i.e., a 

weighted average of 5 years of fourth highest daily maximum 8-hour ozone concentrations). For example, 

for the 2006 base case modeling year used in this analysis, this would mean the DVc at a given monitor 

would be the weighted average of the fourth highest 8-hour daily maximum ozone at that monitor from the 
5-22 March 2012

years 2004, 2005, 2006, 2007, and 2008 using weights of 1, 2, 3, 2, and 1, respectively. To develop RRFs, 

USEPA guidance recommends using current and future modeling results for all days in which the current 

year daily maximum 8-hour ozone concentration near the monitor exceeds an ozone threshold value. For a 

12-km grid, as in the GNB CMAQ modeling, the maximum modeled daily maximum 8-hour ozone 

concentration in a 3 x 3 array of grid cells centered on the monitor is used. USEPA recommends using an 

8-hour ozone threshold concentration of 85 ppb and also recommends that RRFs be based on a minimum 

of 5 days, although a total of at least 10 days is preferred. USEPA allows a reduction of the threshold value 

to 70 ppb to meet the minimum 5- to 10-day requirement. These procedures were developed mainly for 

urban ozone nonattainment areas where there typically are many more days of elevated ozone 

concentrations than are observed in the rural Uinta Basin study area. 

There are several issues with using the MATS tool in its standard configuration for the ozone analysis. The 

most serious is that the monitoring network is relatively dense in the Salt Lake City area but sparse 

throughout the rest of Utah, with no monitors in the Uinta Basin that have a sufficiently long data record to 

allow inclusion in the MATS tool (Figure 5-3). Therefore, use of the MATS tool in its standard configuration

would result in the DVc in Uintah County, Utah, being based on interpolation of DVc from monitors hundreds 

of kilometers away in the Salt Lake City area, San Juan County, Utah (Canyonlands), and the Gothic, 

Colorado, and Centennial, Wyoming, CASTNet sites. This results in the interpolation of high Salt Lake City 

ozone values typical of an urban area across the Wasatch Range into the rural Uinta Basin region. Note that 

the Uinta Basin is not part of the Salt Lake City airshed. In addition, restricting sites used in MATS to those 

with a minimum of 5 days of DVc greater than 70 ppb means that MATS cannot project future ozone in the 

middle of the Uinta Basin and leaves this area blank in plotting future year design values in the unmonitored 

area analysis. To address this issue, the analysis includes monitors that record ozone data according to 

USEPA standard methods but have fewer than 5 years of data available. 

For this analysis, a MATS assessment was performed in which all available data were used. While this may 

not be acceptable to NAAQS attainment designation, this approach leads to a more informative analysis of 

expected changes in ozone levels in an area that is fundamentally in compliance with the standard. The 

5-year data requirement to construct DVc was relaxed so that sites with a minimum of 1 year of data were 

included as DVc in the analysis. DVc for sites with multiple years of record were based on the 3-year 8-hour 

ozone design value that spanned 2004 through 2008. In addition, in the enhanced MATS Unmonitored Area 

Analysis, grid cells were included in the RRF calculation if they had 1 or more days over the 70 ppb 

threshold. Figure 5-3 displays the locations of the ozone monitors used in the enhanced MATS projection 

analysis using the expanded monitoring sites for the DVc. The most important difference in the Uinta Basin 

was the addition of DVc associated with the Vernal, Utah, ozone monitor and the monitor at Dinosaur 

National Monument. The Vernal monitor lies within the Uinta Basin and was active in 2007. The fourth 

highest daily maximum 8-hour ozone concentration was used for the DVc for this monitor. The DVc for the 

Dinosaur National Monument was based on 3 years of monitoring data (2006 though 2008) with the 3-year 

average fourth highest daily maximum 8-hour ozone concentrations. 

5.2.3 Impact Assessment at Monitors

Monitor station 2006 design values (DVc) as well as 2018 DVf and RRFs for the 2018 Projected Baseline, 

2017 Proposed Action, and 2026 Optimal Recovery Alternative for all stations in the domain for the 2005 

and 2006 meteorological years are presented in Tables 5-9 and 5-10, respectively. USEPA guidance 

(USEPA 2007) suggests truncating ozone concentrations to the ppb level (truncating tenths of ppb) when 

performing attainment testing. However, for this analysis the results are presented to 0.1 ppb to better 

resolve the magnitude of potential project impacts. For all three future scenarios, all monitors in the 

modeling domain are predicted to be in attainment with the 75 ppb ozone standard. 
5-23 March 2012

Figure 5-3 Ozone Monitoring Stations
5-24 March 2012

Table 5-9 Annual Monitoring Station 8-hour Ozone Design Values and Future Year Design Values

for 2005 Meteorological Year

Baseline

2018 Projected 

Baseline

2017 Proposed 

Action

2026 Optimal 

Recovery

Monitor ID State Name DVc DVf RRF DVf RRF DVf RRF

80450012 CO Rifle - Health 66.0 60.4 0.9159 60.4 0.9159 60.51 0.9171

80677001 CO LaPlata7001 56.3 50.0 0.8895 50.0 0.8895 50.0 0.8895

80677003 CO LaPlata7003 65.3 56.8 0.8703 56.8 0.8703 56.8 0.8703

80679000 CO Shamrock 71.3 66.4 0.9321 66.4 0.9321 66.4 0.9321

80770020 CO Palisade-Water 70.0 64.3 0.9192 64.3 0.9192 64.41 0.9203

80771001 CO Colorado NM 69.0 62.7 0.9094 62.7 0.9094 62.7 0.9096

80830101 CO Montezuma0101 72.3 64.1 0.8873 64.1 0.8873 64.1 0.8873

350450009 NM SanJuan0009 67.3 61.9 0.9205 61.9 0.9205 61.9 0.9206

350450018 NM Navajo Dam 77.0 70.5 0.9161 70.5 0.9161 70.5 0.9161

350451005 NM SanJuan1005 71.0 66.1 0.9314 66.1 0.9314 66.1 0.9315

490110004 UT Davis0004 80.0 69.2 0.8657 69.2 0.8657 69.2 0.8657

490350003 UT SaltLake0003 80.0 72.6 0.9084 72.6 0.9084 72.6 0.9085

490352004 UT SaltLake2004 80.0 63.0 0.7886 63.0 0.7886 63.0 0.7886

490353006 UT SaltLake3006 77.0 69.2 0.8999 69.2 0.8999 69.2 0.8999

490353007 UT SaltLake3007 78.0 64.5 0.8271 64.5 0.8271 64.5 0.8271

490353008 UT SaltLake3008 78.0 66.5 0.8538 66.5 0.8538 66.5 0.8538

490370101 UT SanJuan0101 71.0 62.2 0.8764 62.2 0.8764 62.2 0.8768

490471002 UT Dinosaur NM 65.0 58.6 0.9020 58.6 0.9020 58.71 0.9034

490490002 UT Utah0002 73.0 65.6 0.8988 65.6 0.8988 65.6 0.8989

490495008 UT Utah5008 75.0 67.5 0.9001 67.5 0.9001 67.5 0.9002

490495010 UT Utah5010 76.0 66.8 0.8793 66.8 0.8793 66.8 0.8793

490570007 UT Weber0007 78.0 66.8 0.8568 66.8 0.8568 66.8 0.8568

490571003 UT Weber1003 79.0 67.6 0.8568 67.6 0.8568 67.6 0.8568

Black_CnNP CO Black_CnNP 74.0 67.2 0.9088 67.2 0.9088 67.2 0.9090

Cent_WY WY Cent_WY 68.0 62.9 0.9264 62.9 0.9264 63.01 0.9265

EnCanaCyn CO EnCanaCyn 68.0 62.5 0.9203 62.5 0.9203 62.61 0.9219

EnCanaMtn CO EnCanaMtn 68.0 63.3 0.9310 63.3 0.9310 63.3 0.9318

Gothic CO Gothic 67.7 63.9 0.9448 63.9 0.9448 64.01 0.9465

USFS-Sunlight CO USFS-Sunlight 70.0 64.1 0.9162 64.1 0.9162 64.21 0.9172

USFS_Ajax CO USFS_Ajax 77.0 71.8 0.9335 71.8 0.9335 71.91 0.9345

USFS_Bell CO USFS_Bell 70.5 63.1 0.8952 63.1 0.8952 63.1 0.8964

USFS_Ripp CO USFS_Ripp 66.0 61.1 0.9258 61.1 0.9258 61.1 0.9260

Vernal UT Vernal 68.9 63.5 0.9222 63.5 0.9222 63.5 0.9225

1 Ozone design value increases by 0.1 ppb compared to the 2018 Projected Baseline scenario.
5-25 March 2012

Table 5-10 Annual Monitoring Station 8-hour Ozone Design Values and Future Year Design Values 

for 2006 Meteorological Year

Baseline

2018 Projected 

Baseline

2017 Proposed 

Action

2026 Optimal 

Recovery

Monitor ID State County DVc DVf RRF DVf RRF DVf RRF

80450012 CO Rifle - Health 66.0 59.8 0.9062 59.8 0.9067 59.8 0.9074

80677001 CO LaPlata7001 56.3 51.8 0.9210 51.8 0.9211 51.8 0.9211

80677003 CO LaPlata7003 65.3 59.9 0.9176 59.9 0.9176 59.9 0.9177

80679000 CO Shamrock 71.3 66.1 0.9282 66.1 0.9282 66.1 0.9283

80770020 CO Palisade-Water 70.0 63.8 0.9123 63.8 0.9125 63.8 0.9128

80771001 CO Colorado NM 69.0 62.6 0.9077 62.6 0.9079 62.6 0.9083

80830101 CO Montezuma0101 72.3 65.5 0.9068 65.5 0.9070 65.5 0.9071

350450009 NM SanJuan0009 67.3 62.7 0.9331 62.81 0.9332 62.81 0.9333

350450018 NM Navajo Dam 77.0 70.9 0.9220 71.01 0.9221 71.01 0.9222

350451005 NM SanJuan1005 71.0 66.3 0.9339 66.3 0.9340 66.3 0.9341

490110004 UT Davis0004 80.0 73.2 0.9161 73.31 0.9163 73.31 0.9167

490350003 UT SaltLake0003 80.0 71.2 0.8908 71.2 0.8909 71.2 0.8911

490352004 UT SaltLake2004 80.0 67.6 0.8461 67.71 0.8463 67.71 0.8466

490353006 UT SaltLake3006 77.0 68.0 0.8841 68.0 0.8843 68.1 0.8845

490353007 UT SaltLake3007 78.0 66.5 0.8536 66.6 0.8539 66.6 0.8544

490353008 UT SaltLake3008 78.0 71.6 0.9187 71.6 0.9188 71.6 0.9190

490370101 UT SanJuan0101 71.0 64.0 0.9026 64.11 0.9033 64.11 0.9042

490471002 UT Dinosaur NM 65.0 59.3 0.9132 59.71 0.9187 60.11 0.9261

490490002 UT Utah0002 73.0 65.1 0.8930 65.1 0.8930 65.1 0.8931

490495008 UT Utah5008 75.0 66.2 0.8837 66.2 0.8837 66.2 0.8837

490495010 UT Utah5010 76.0 67.1 0.8837 67.1 0.8838 67.1 0.8839

490570007 UT Weber0007 78.0 70.7 0.9067 70.7 0.9070 70.7 0.9073

490571003 UT Weber1003 79.0 71.6 0.9067 71.6 0.9070 71.6 0.9073

Black_CnNP CO Black_CnNP 74.0 68.3 0.9239 68.3 0.9240 68.3 0.9241

Cent_WY WY Cent_WY 68.0 64.3 0.9458 64.3 0.9466 64.41 0.9477

EnCanaCyn CO EnCanaCyn 68.0 62.0 0.9131 62.11 0.9136 62.11 0.9142

EnCanaMtn CO EnCanaMtn 68.0 61.8 0.9089 61.8 0.9094 61.8 0.9100

Gothic CO Gothic 67.7 63.1 0.9329 63.1 0.9330 63.1 0.9332

USFS-Sunlight CO USFS-Sunlight 70.0 64.7 0.9244 64.7 0.9247 64.7 0.9250

USFS_Ajax CO USFS_Ajax 77.0 71.8 0.9329 71.8 0.9330 71.8 0.9331

USFS_Bell CO USFS_Bell 70.5 64.1 0.9106 64.21 0.9108 64.21 0.9111

USFS_Ripp CO USFS_Ripp 66.0 62.8 0.9516 62.8 0.9523 62.91 0.9534

Vernal UT Vernal 68.9 63.8 0.9263 64.01 0.9296 64.31 0.9341

1 Ozone design value increases by 0.1 ppb compared to the 2018 Projected Baseline scenario.
5-26 March 2012

For the 2005 meteorological year (Table 5-9), the Proposed Action scenario does not increase ozone 

design values by over 0.1 ppb over the Projected Baseline scenario at any of the monitors; however, the 

Optimal Recovery scenario does increase ozone by 0.1ppb at 8 monitors. For the 2006 meteorological year 

(Table 5-10), the CMAQ model shows more impact from the project using the 2006 meteorology, where the 

Proposed Action scenario increases ozone by 0.1 ppb at 7 monitors, by 0.2 ppb at the Vernal monitor, and 

by 0.4 ppb at the Dinosaur NM monitor. The Optimal Recovery scenario increases ozone by 0.1 ppb at 

9 monitors, 0.5 ppb at the Vernal monitor, and 0.8 ppb at the Dinosaur NM monitor.

5.2.4 Impact Assessment in Areas Removed from Monitors

To assess the project impacts in areas removed from monitor locations, USEPA guidance calls for an 

unmonitored area analysis. For this analysis, the MATS tool is used to prepare spatial fields of the projected 

future year ozone design values throughout the 12-km domain. USEPA does not determine attainment of 

the 8-hour standard based on the unmonitored area analysis; rather, the unmonitored analysis is used as 

more of a weight-of-evidence analysis and to guide potential future ozone monitor placement 

(USEPA 2007).

Figure 5-4 presents the Baseline MATS estimated ozone design values using the 2005 and 2006 

meteorology. For both meteorological years, the highest values are estimated to occur in the Salt Lake City 

area. For the 2005 meteorology in the GNBPA, the estimated design values were below 70 ppb. For the 

2006 meteorology, the majority of the values were below 70 ppb with one grid cell in the range of 70 to 

73 ppb. No grid cells in the vicinity of the GNBPA were estimated to have design values in excess of the 

75 ppb ozone NAAQS. 

Figure 5-5 presents the 2018 Projected Baseline design values. For both years of meteorology, the CMAQ 

model generally is estimating a decrease in the design value across the domain. Figure 5-6 presents the 

future design values that include the 2017 Proposed Action emissions. The results are nearly 

indistinguishable from the 2018 Projected Baseline figures. Analogous 2026 Optimal Recovery results are 

presented in Figure 5-7. Again, the differences are difficult to distinguish from either the Projected Baseline 

or the Proposed Action. The model calculated no ozone concentrations in excess of the 75 ppb standard in 

the GNBPA for any of the scenarios.

To focus on the differences in the future design values, difference plots between the scenarios are shown. 

Figure 5-8 presents the differences in the design values between the Projected Baseline and the Proposed 

Action. The Proposed Action scenario shows more extensive impact using the 2006 meteorology than for 

2005. The maximum increase with the 2005 meteorology was 0.3 ppb occurring well southwest of the 

GNBPA, an ozone decrease of 0.3 ppb in the GNBPA, and only a limited area showed impacts of 0.2 ppb. 

With the 2006 meteorology, the maximum increase in the GNBPA was 2.4 ppb with the Proposed Action 

scenario showing a 0.2 ppb or greater impact over much of Uintah County and into Colorado. 

Figure 5-9 presents the future design value differences between the Optimal Recovery Alternative and the 

Projected Baseline. As with the Proposed Action, the 2006 meteorology showed a larger and more 

extensive impact from the Optimal Recovery Alternative. The maximum impact from the Optimal Recovery 

scenario using the 2005 meteorology was 0.6 ppb occurring southwest of the GNBPA, with an ozone 

decrease of 0.8 ppb in the GNBPA. The 2006 meteorology showed a maximum impact from the Optimal 

Recovery scenario of 4.9 ppb in the vicinity of the GNBPA, with a sizable portion of Uintah County having an 

impact greater than 0.4 ppb. 

Differences between the Optimal Recovery Alternative and Proposed Action future design values are 

presented in Figure 5-10 using the 2005 and 2006 meteorology. With the 2005 meteorology, the maximum 

difference in increase was 0.3 ppb and the maximum difference in decrease was 0.5 ppb. For the 2006 

meteorology, the maximum difference in increase was 2.5 ppb and the maximum difference in decrease 

was 0.1 ppb.
5-27 March 2012

2005

2006

Figure 5-4 Baseline 8-hour Ozone Design Values
5-28 March 2012

2005

2006

Figure 5-5 Annual 8-hour Ozone Future Design Values for 2018 Projected Baseline 
5-29 March 2012

2005

2006

Figure 5-6 Annual 8-hour Ozone Future Design Values for 2017 Proposed Action 
5-30 March 2012

2005

2006

Figure 5-7 Annual 8-hour Ozone Future Design Values for 2026 Optimal Recovery Alternative 
5-31 March 2012

2005

2006

Figure 5-8 Annual 8-hour Ozone Future Design Value Differences for Proposed Action Minus 2018 

Projected Baseline 
5-32 March 2012

2005

2006

Figure 5-9 Annual 8-hour Ozone Future Design Value Differences for Optimal Recovery Minus 2018 

Projected Baseline
5-33 March 2012

2005

2006

Figure 5-10 Annual 8-hour Ozone Future Design Value Differences for Optimal Recovery Minus 

Proposed Action
5-34 March 2012

5.2.5 Ozone Projections Using Absolute Modeling Results

As was stated previously, the USEPA preferred approach for use of photochemical models to assess ozone 

attainment is to use air quality model results in a relative sense. However, another approach is to use the 

model in an absolute sense. Again, the lack of observations in the vicinity of the GNBPA makes it 

impossible to assess whether the CMAQ model is able to replicate the ozone levels in the base year and 

hence reduces the credibility of the model to estimate future ozone concentrations. 

The fourth highest annual daily maximum predicted 8-hour ozone concentrations for the 2018 Projected 

Baseline using the 2005 and 2006 meteorology are presented in Figure 5-11. Using the 2005 meteorology, 

the GNBPA was estimated to have ozone concentrations below 73 ppb and using the 2006 meteorology, 

the GNBPA was estimated to have ozone concentrations at 75 ppb or less. The model was not simulating a 

fourth high ozone concentration of above 75 ppb with either year of meteorology in the Uinta Basin counties.

Fourth high ozone concentrations for the 2017 Proposed Action scenario are presented in Figure 5-12. The 

spatial patterns are very similar to the Projected Baseline, with only a few grid cells near the GNBPA 

showing a difference. The 2026 Optimal Recovery Alternative fourth high ozone concentrations are 

presented in Figure 5-13. The only time the fourth highest ozone concentrations were above 75 ppb is 

under the Optimal Recovery Alternative at 3 grid square receptors using the 2006 meteorology. For all other 

cases, the maxima were 75 ppb or less.

As was performed for the unmonitored area analysis, differences between the alternatives were prepared. 

Figure 5-14 presents the differences in the modeled fourth highest ozone levels between the Proposed 

Action and the Projected Baseline using the 2005 and 2006 meteorological data. For the 2005 meteorology, 

the maximum ozone increase was 0.6 ppb, with the impact area generally being oriented southwest to 

northeast. For the 2006 meteorology, the maximum increase was 1.8 ppb. Analogous plots for the Projected 

Baseline and the Optimal Recovery Alternative are presented in Figure 5-15. For the 2005 meteorology, the 

maximum increase was 1.3 ppb and for the 2006 meteorology, the maximum increase was 3.7 ppb. Finally, 

differences between the Optimal Recovery Alternative and the Proposed Action are presented in 

Figure 5-16. The maximum differences between the two alternatives using 2005 meteorology was 1.2 ppb, 

and the maximum difference using 2006 meteorology was 2.6 ppb.

5.2.6 Ozone Impact Assessment Summary

The project impacts for the 2018 Projected Baseline, 2017 Proposed Action, and 2026 Optimal Recovery 

scenarios were examined using both the USEPA recommended relative approach and an absolute 

approach. Using the relative approach at the monitors, the criteria used by USEPA to show attainment of 

the NAAQS indicated that all monitors were simulated to be below the 75 ppb NAAQS for all scenarios. The 

maximum impact at a monitor was 0.4 ppb for the Proposed Action, and 0.8 ppb for the Optimal Recovery 

Alternative. However, for both cases the maximum impact was at the Dinosaur National Monument monitor, 

which does not have a sufficiently long data record for it to be used in a formal attainment designation. The 

maximum impact at an AIRS monitor that could be used for attainment designation was 0.1 ppb for both the

Proposed Action and the Optimal Recovery Alternative.

Using the USEPA recommended relative non-monitored area analysis, no areas in the vicinity of the 

GNBPA were simulated to exceed the 75 ppb ozone standard using either the 2005 or 2006 meteorologies 

for any of the project alternatives. The maximum fourth highest impact was 2.4 ppb from the Proposed 

Action scenario and 4.9 ppb from the Optimal Recovery Alternative. For both scenarios, the impacts were 

occurring in areas simulated to remain below the 75 ppb ozone standard. 
5-35 March 2012

2005

2006

Figure 5-11 Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone Concentration (ppb) 

for 2018 Projected Baseline
5-36 March 2012

2005

2006

Figure 5-12 Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone Concentration (ppb) 

for 2017 Proposed Action
5-37 March 2012

2005

2006

Figure 5-13 Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone Concentration (ppb) 

for 2026 Optimal Recovery
5-38 March 2012

2005

2006

Figure 5-14 Difference in Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone 

Concentration (ppb) for Proposed Action Minus 2018 Projected Baseline
5-39 March 2012

2005

2006

Figure 5-15 Difference in Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone 

Concentration (ppb) for Optimal Recovery Minus 2018 Projected Baseline
5-40 March 2012

2005

2006

Figure 5-16 Difference in Fourth Highest Annual Daily Maximum Predicted 8-hour Ozone 

Concentration (ppb) for Optimal Recovery Minus Proposed Action
5-41 March 2012

Using the much more uncertain absolute impact approach, the Projected Baseline and Proposed Action 

scenarios did not show any regions in the GNBPA to be in excess of the 75 ppb standard. For the Optimal 

Recovery Alternative using 2006 meteorology, 3 grid cells to the east of the GNBPA were simulated to 

exceed the 75 ppb ozone standard. On an absolute basis, the project emissions were simulated to increase 

ozone by a maximum of 1.8 ppb for the Proposed Action and 3.7 ppb for the Optimal Recovery Alternative.

5.3 AERMOD Impact Assessment for Near-Field Receptors

5.3.1 Criteria Pollutant Analysis

The near-field impacts from the proposed project were assessed using procedures described in Section 4.3 

to quantify air quality impacts related to the density of well pad development and drill rig operations within a 

hypothetical designated square mile area (e.g., a section/township/range). Near-field impacts were 

addressed for NO2, CO, SO2, PM10, and PM2.5 within the immediate vicinity of these development areas 

using the 5 years of meteorological data. The AERMOD modeling approach consisted of three phases: 

1) single source group impact analysis, 2) well pad production analysis, and 3) well drilling analysis.

The AERMOD modeled impacts were compared to the PSD Class II increments because they represent a 

convenient quantitative measure to evaluate the air quality impacts of the proposed project. In addition to 

reporting modeled concentrations alone, total impacts were assessed for compliance with the NAAQS and 

SAAQS by adding the modeled concentrations for the applicable averaging periods to their appropriate 

counterpart of background air quality data. These totals were compared to the applicable NAAQS for NO2, 

CO, SO2, PM10, and PM2.5. As a conservative approach, the NOX adjustment option based on the ambient 

ratio method (40 CFR 51, Appendix W), which assumes a conversion rate of 75 percent, was not used for 

the annual NOX to NO2 conversion rate.

Tables 5-11 through 5-13 contain the AERMOD maximum modeled concentrations over the 

5 meteorological modeled years for NO2, CO, SO2, PM10, and PM2.5 for representative source types. The 

modeled impacts plus the background air quality concentrations were compared to the applicable 

NAAQS/SAAQS. Background air quality data were obtained as described in Chapter 2.0 for this analysis.

Table 5-11 provides a summary of maximum modeled impacts of these criteria air pollutants for three 

separate point source types. Table 5-12 provides similar summaries for well pad production operations at 

various well densities, as described in the table. Table 5-13 provides a summary of annualized and 

short-term impacts for well pad drilling, as discussed in Section 4.3.1.3. The results in Tables 5-11 through 

5-13 show that total concentrations for all source types for all pollutants are below the applicable 

NAAQS/SAAQS.

Near-field modeling showed that simultaneous operation of drill rigs on adjacent pads would not

cause an exceedance of the NAAQS for 1-hour NO2. The extent of 1-hour NO2 impacts are shown in 

the plots in Figures 5-17 and 5-18 for Tier 2 and Tier 4 engines, respectively. The values on these 

plots represent the 5-year average of annual 98th percentile values, including background. These 

figures show that peak impacts occur at receptors adjacent to the drill rigs (within 100 m).

5.3.2 HAP Analysis

AECOM evaluated the ambient air concentration of HAPs by modeling the emission rates for the 

HAPs listed in Table 4-7. AERMOD was run for all scenarios outlined in Section 4.3.1 using 5 years 

of meteorological data to estimate air concentrations of formaldehyde, benzene, toluene, ethyl 

benzene, xylene(s), and n-hexane. The maximum modeled concentrations over the 5-year period for 

each applicable HAP/averaging period (i.e., annual and 24-hour) was compared to the RfCs and 

TSLs.
5-42 March 2012

Table 5-11 AERMOD Near-field Criteria Pollutants Assessment Modeling Result Summary – Single Source Impact Analysis

Pollutant

Average 

Time

Maximum Model Concentration 

by Source1 (μg/m3) Background 

Concentration

(μg/m3)

Total Concentration 

by Source1 (μg/m3)

NAAQS 

(μg/m3)

PSD 

Increments

(μg/m3)

Compressor 

Station Drill Rig2 Production Well

Compressor 

Station Drill Rig Production Well

NO2

1-hour3 42.1 118.1

(100.4)

23.0 N/A4 84.4 136.5

(120.1)

74.9 188 --

Annual5 2.53 0.5

(0.3)

1.58 9.0 11.5 9.5

(9.3)

10.6 100 25

CO

1-hour 13 329 22 6,325 6,338 6,654 6,347 40,000 --

8-hour 7 240 17 3,910 3,917 4,150 3,927 10,000 --

SO2

1-hour6 0.55 0.6 0.87 21.7 22.3 22.3 22.6 196 --

3-hour 0.62 0.6 0.85 16.7 17.3 17.3 17.6 1,300 512

24-hour 0.25 0.2 0.39 5.9 6.1 6.1 6.3 365 91

Annual 0.02 0.001 0.05 1.5 1.5 1.5 1.6 80 20

PM10

24-hour 2.87 4.5

(0.7)

0.89 18 20.9 22.5

(18.7)

18.9 150 30

PM2.5

24-hour 2.87 4.5

(0.7)

0.89 21.6 24.5 26.1

(22.3)

22.5 35 --

Annual 0.21 0.0

(0.0)

0.27 12.3 12.5 12.3

(12.3)

12.6 15 --

1 Modeled results are based on Tier 2 engine emission factors unless otherwise noted.

2 Results in parentheses reflect Tier 4 engine emission factors. 3 Modeled impacts are the 5-year average 98th percentile daily maximum. 4 1-hour NO2 modeling used background concentrations that vary by season and hour of day.

5 For annual averaging period, predicted concentration does not include a reduction from NOX to NO2. All NOX is presumed to be NO2. 6 Modeled impacts are the 5-year average 99th percentile daily maximum.
5-43 March 2012

Table 5-12 AERMOD Near-field Criteria Pollutants Modeling Results – Well Pad Production Analysis

Pollutant

Averaging 

Time

Maximum Modeled 

Concentration1 (μg/m3)

Background 

Concentration (μg/m3)

Total Impact1

(μg/m3)

NAAQS 

(μg/m3)

PSD Increment

(μg/m3)

Distance 

(m)

Direction 

(deg)

10-Acre Spacing Well Production

NO2 1-hour2 63.9 N/A3 111.1 188 -- 943 122

Annual4 5.7 9.0 14.7 100 25 224 63

CO 1-hour 69 6,325 6,394 40,000 -- 806 97

8-hour 34 3,910 3,944 10,000 -- 806 83

SO2 1-hour5 2.6 21.7 24.3 196 -- 854 111

3-hour 1.9 16.7 18.6 1,300 512 854 111

24-hour 0.9 5.9 6.8 365 91 854 69

Annual 0.1 1.5 1.6 80 20 224 63

PM10 24-hour 2.9 18 20.9 150 30 224 207

PM2.5 24-hour 2.9 21.6 24.5 35 -- 854 69

Annual 0.8 12.3 13.1 15 -- 224 63

20-Acre Spacing Well Production

NO2 1-hour2 48.6 N/A3 96.5 188 -- 447 153

Annual4 4.2 9.0 13.2 100 25 224 333

CO 1-hour 51 6,325 6,376 40,000 -- 640 129

8-hour 27 3,910 3,937 10,000 -- 1,714 13

SO2 1-hour5 2.6 21.7 24.3 196 -- 854 111

3-hour 1.4 16.7 18.1 1,300 512 447 27

24-hour 0.7 5.9 6.6 365 91 447 27

Annual 0.1 1.5 1.6 80 20 447 27

PM10 24-hour 2.7 18 20.7 150 30 224 207

PM2.5 24-hour 2.7 21.6 24.3 35 -- 854 69

Annual 0.6 12.3 12.9 15 -- 447 27

40-Acre Spacing Well Production

NO2 1-hour2 45.2 N/A3 86.9 188 -- 728 106

Annual4 3.7 9.0 12.7 100 25 224 333

CO 1-hour 40 6,325 6,365 40,000 -- 728 106

8-hour 20 3,910 3,930 10,000 -- 1,679 7

SO2 1-hour5 1.5 21.7 23.2 196 -- 728 106

3-hour 1.1 16.7 17.8 1,300 512 728 74

24-hour 0.5 5.9 6.4 365 91 922 49

Annual 0.1 1.5 1.6 80 20 224 333

PM10 24-hour 2.7 18 20.7 150 30 224 207

PM2.5 24-hour 2.7 21.6 24.3 35 -- 854 69

Annual 0.4 12.3 12.7 15 -- 224 333

1 Modeled results are based on Tier 2 engine emission factors unless otherwise noted. 2 Modeled impacts are the 5-year average 98th percentile daily maximum. 3 1-hour NO2 modeling used background concentrations that vary by season and hour of day. 4 For annual averaging period, predicted concentration does not include a reduction from NOX to NO2. All NOX is presumed to be NO2. 5 Modeled impacts are the 5-year average 99th percentile daily maximum.
5-44 March 2012

Table 5-13 AERMOD Near-field Criteria Pollutants Modeling Results – Well Drilling Analysis

Pollutant

Averaging 

Time

Maximum Modeled

Concentration1

(μg/m3)

Background 

Concentration 

(μg/m3)

Total Impact1

(μg/m3)

NAAQS 

(μg/m3)

PSD 

Increment 

(μg/m3)

Distance

(m)

Direction 

(deg)

NO2

2 1-hour3 137.1

(106.9)

N/A4 157.2

(125.6)

188 -- 361 146

Annual5 7.7

(2.0)

9.0 16.7

(11.0)

100 25 510 79

CO 1-hour 399 6,325 6724 40,000 -- 361 214

8-hour 251 3,910 4,161 10,000 -- 361 326

SO2 1-hour6 0.7 21.7 22.4 196 8 361 214

3-hour 0.8 16.7 17.5 1,300 512 361 214

24-hour 0.2 5.9 6.1 365 91 424 225

Annual 0.0 1.5 1.5 80 20 728 106

PM10 24-hour 3.6

(0.9)

18 21.6

(18.9)

150 30 424 225

PM2.5 24-hour 3.6

(0.9)

21.6 25.2

(22.5)

35 -- 806 97

Annual 0.1

(0.0)

12.3 12.4

(12.3)

15 -- 728 106

1 Modeled results are based on Tier 2 engine emission factors unless otherwise noted. 2 Results in parentheses reflect Tier 4 engine emission factors.

3 Modeled impacts are the 5-year average 98th percentile daily maximum. 4 1-hour NO2 modeling used background concentrations that vary by season and hour of day.

5 For annual averaging period, predicted concentration does not include a reduction from NOX to NO2. All NOX is presumed to be NO2. 6 Modeled impacts are the 5-year average 99th percentile daily maximum.
5-45 March 2012

Figure 5-17 1-hour NO2 Impacts from Well Drilling with Tier 2 Engines (400-m spacing)
5-46 March 2012

Figure 5-18 1-hour NO2 Impacts from Well Drilling with Tier 4 Engines (400-m spacing)
5-47 March 2012

Table 5-14 provides a summary of maximum modeled impacts of HAPs for three separate point 

source types. Table 5-15 provides similar summaries for well pad production operations at three 

different well densities: 10-, 20-, and 40-acre spacing. Table 5-16 provides a summary of annualized 

and short-term impacts for well drilling. The results in Tables 5-14 through 5-16 show that maximum 

concentrations for all source types for all HAPs are below the applicable RfCs and TSLs.

Table 5-14 AERMOD HAPs Near-field Assessment Modeling Result Summary – Single Source 

Impact Analysis

Pollutant/Averaging 

Period

Concentration by Source Type (μg/m3) Non-Carcinogenic 

RfC1

(μg/m3)

TSL2

(μg/m3)

Compressor 

Station Drill Rigs

Production 

Well

Benzene

24-hour 0.03 0.08 2.26 - 53.3

Annual 0.002 0.0003 0.60 30 -

Ethylbenzene

24-hour 0.003 0.01 0.14 - 14,473

Annual 0.0002 0.00005 0.07 1,000 -

Formaldehyde

24-hour 3.94 0.47 0.95 - 37

Annual 0.28 0.002 0.26 9.8 -

n-Hexane

24-hour 0.08 0.006 6.41 - 5,875

Annual 0.006 0.00002 1.73 700 -

Toluene

24-hour 0.03 0.06 5.26 - 2,512

Annual 0.002 0.0002 1.41 5,000 -

Xylene

24-hour 0.01 0.04 3.91 - 14,473

Annual 0.001 0.0002 1.04 100 -

1 USEPA Air Toxics Database, Table 1 (USEPA 2010b).

2 UDAQ Air Toxic Modeling Guidance for TSLs (UDAQ 2010).
5-48 March 2012

Table 5-15 AERMOD HAPs Near-field Modeling Results – Well Pad Production Analysis

Pollutant/Averaging 

Period

Concentration per Production Well Density 

(μg/m3) Non-Carcinogenic 

RfC1

(μg/m3)

TSL2

(μg/m3)

10-Acre 

Spacing

20-Acre 

Spacing

40-Acre 

Spacing

Benzene

24-hour 5.25 4.14 2.99 - 53.3

Annual 1.55 1.22 0.71 30 -

Ethylbenzene

24-hour 0.32 0.26 0.18 - 14,473

Annual 0.17 0.13 0.08 1,000 -

Formaldehyde

24-hour 3.89 3.76 3.76 - 37

Annual 0.85 0.64 0.50 9.8 -

n-Hexane

24-hour 14.85 11.70 8.45 - 5,875

Annual 4.47 3.52 2.05 700 -

Toluene

24-hour 12.17 9.59 6.93 - 2,512

Annual 3.63 2.86 1.67 5,000 -

Xylene

24-hour 9.08 7.15 5.16 - 14,473

Annual 2.68 2.11 1.23 100 -

1 USEPA Air Toxics Database, Table 1 (USEPA 2010b). 2 UDAQ Air Toxic Modeling Guidance for TSLs (UDAQ 2010).
5-49 March 2012

Table 5-16 AERMOD HAPs Near-field Modeling Results – Well Drilling Analysis

Pollutant / Averaging 

Period

Maximum Modeled 

AERMOD Results

(μg/m3)

Non-Carcinogenic 

RfC1

(μg/m3)

TSL2

(μg/m3)

Benzene

24-hour 0.06 - 53.3

Annual 0.002 30 -

Ethylbenzene

24-hour 0.01 - 14,473

Annual 0.0003 1,000 -

Formaldehyde

24-hour 0.3 - 37

Annual 0.01 9.8 -

n-Hexane

24-hour 0.005 - 5,875

Annual 0.0002 700 -

Toluene

24-hour 0.04 - 2,512

Annual 0.002 5,000 -

Xylene

24-hour 0.03 - 14,473

Annual 0.001 100 -

1 USEPA Air Toxics Database, Table 1 (USEPA 2010b). 2 UDAQ Air Toxic Modeling Guidance for TSLs (UDAQ 2010).
6-1 March 2012

6.0 Greenhouse Gas Emissions

This chapter compares the potential GHG emissions from the project alternatives being analyzed under NEPA. 

The methodology described herein calculated the potential GHG emissions based on the activity levels 

described by KMG; then the projected potential annual GHG emissions increase for the Proposed Action and 

Optimal Recovery Alternative were compared with those of the No Action Alternative. The Resource Protection 

Alternative was not considered since its activity level was less than the Proposed Action and presumed to 

result in less GHG emissions. This analysis does not attempt to predict actual total emissions of GHG from 

each alternative, but only provides a comparison of relative GHG emissions increases from the Proposed 

Action and Optimal Recovery Alternative. As such, no estimate of current actual GHG emissions was required 

or included as part of this analysis. 

6.1 General Quantification Methods

GHG were estimated using the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and 

Gas Industry (API 2004) as implemented using the SANGEATM software tool published by the API. The 

SANGEATM tool is an ExcelTM macro that uses the calculation methodologies described in the Compendium to 

calculate GHG emissions using a series of modules for different source types. These modules determine the 

emissions of CO2, CH4, and N2O as well as the global warming potential (GWP) in CO2e based on the 

comparative GWP of each GHG species. For this analysis, the default GWP coefficients of 21 for CH4 and 310 

for N2O were used. These coefficients were multiplied by the calculated mass emission rate to determine the 

GWP. The SANGEATM tool is available from API on request.

6.2 Well Count

Many of the calculations were dependent on the number of wells drilled per year and the total estimated 

number of wells in production in the maximum production year. Wells in production for each scenario assumed

the total proposed wells for each scenario minus wells drilled per year as shown in Table 6-1.

Table 6-1 Estimated Number of Wells Drilled and Operating in Maximum Production Year

Project Alternative No Action

Proposed 

Action

Optimal 

Recovery

Maximum Production Year 2012 2017 2026

Total Wells Proposed (wells) 1,102 3,675 13,446

Wells Drilled Per Year (wells/year) 192 336 672

Wells Operating in Maximum Production Year (wells) 910 3,339 12,774

6.3 Combustion Sources

Each project alternative included sources of combustion emissions including stationary sources such as 

compression engines and heaters, as well as mobile sources such as drill rig engines, rig boilers, mobile 

equipment, and vehicle fleet. GHG emissions were calculated in SANGEATM for each pollutant based on total 

fuel consumption by activity. Therefore, potential fuel consumption for each alternative was calculated based 

on assumptions of VMT, operating hours, fuel consumption rates, load factors, and fuel characteristics. Where 

appropriate, these data were taken from information provided by KMG and criteria pollutant emission 

calculations as provided in Section 3.3 through 3.9. A description of each source and a summary of the 

throughput calculations are discussed in detail in the following sections.
6-2 March 2012

6.3.1 Fuels

SANGEATM has default characteristics for most standard fuels that are used for gasoline and diesel (distillate 

no. 2) fired sources. Natural gas fired sources would use local fuel gas that can vary significantly from the 

default settings for pipeline grade natural gas in SANGEATM. Local fuel gas would be provided from two 

sources, depending on the equipment to be operated. Uinta fuel gas is gas taken from the wells that has only 

been processed at the well to remove liquids and is used in equipment upstream of the compressors. GNB 

fuel gas is the gas that has been further treated at the compressor station and is used in midstream sources 

such as compressor stations and the processing plant. Local fuel specifications were based on analytical data 

provided by KMG as summarized in Table 6-2.

Table 6-2 Local Fuel Gas Specifications

Parameter Unit

Uinta Fuel Gas

(Upstream)

GNB Fuel Gas

(Midstream)

Composition

Methane Volume Fraction 0.925 0.922

Ethane Volume Fraction 0.037 0.042

Propane Volume Fraction 0.014 0.014

Butane Volume Fraction 0.007 0.006

Pentane+ Volume Fraction 0.008 0.006

Hydrogen Volume Fraction 0.000 0.000

Hydrogen Sulfide Volume Fraction 0.000 0.000

CO2 Volume Fraction 0.008 0.008

CO Volume Fraction 0.000 0.000

Inerts (N2) Volume Fraction 0.001 0.002

Density lb/scf 0.0471 0.0470

Low Heating Value Btu/scf 985 982

High Heating Value Btu/scf 1,094 1,091

CO2 Emission Factor lb/106 Btu (HHV) 118 118

VOC Fraction Volume Fraction 0.0287 0.0263

VOC Molecular Weight lb/lbmol 54.7 54.1

6.3.2 Stationary Combustion Sources

6.3.2.1 Gas-fired Compression Engines

Gas-fired compression engines were assumed to consume GNB fuel gas based on the compression inventory 

provided (see Appendix E). The proposed compression power was converted to fuel basis using a brake 

specific fuel consumption (BSFC) of 7,000 Btu/hp-hr and assuming continuous operation. This conversion is 

summarized in Equation 6-1.

Equation 6-1 Fuel Consumption for Gas-Fired Compression Engines

( ) Btu

MMBtu

x

hp hr

Btu

x

yr

hr Fuel Consumption MMBtu yr Planned Compression hp x 6 10

8760 7000 / ( ) − =

6.3.2.2 Gas Processing Plant Heaters

Since one gas processing plant would be expanded under the action alternatives, the GHG emissions from 

this source were considered for all scenarios. This gas plant currently is approved for construction of three 
6-3 March 2012

trains regardless of alternative. Based on design data, gas processing will consume 62.4 MMBtu/hr of GNB 

fuel gas, with an annual fuel consumption of 546,624 MMBtu/yr assuming 8,760 hours of operation. 

6.3.2.3 Well Separator Heaters

Heaters would be used at each well in the phase separators that burn Uinta fuel gas from the well during cold 

months to maintain optimal separator temperatures. Consumption was based on seasonal operation 

(4,380 hours/year) at 0.5 MMBtu/hr per well or 2,190 MMBtu/yr per well. Maximum fuel consumption was the 

product of the number of operating wells as shown in Table 6-3. 

Table 6-3 Annual Consumption of Uinta Fuel Gas for Separator Heaters per Project Alternative

Project Alternative

Operating Fuel Consumption

Wells (MMBtu/yr)

No Action 910 1,992,900

Proposed Action 3,339 7,312,410

Optimal Recovery 12,774 27,975,060

6.3.2.4 Produced Water Injection Facilities

The Proposed Action and Optimal Recovery alternatives would include 650 gas-fired engines that drive pumps 

to dispose of produced water by deep well injection. For the maximum operating year, it was assumed that two 

wells would be constructed and the balance would be operating. These engines would be operated at 

upstream facilities and were assumed to be driven by Uinta fuel gas. Fuel consumption was calculated per 

Equation 6-2. A summary of total annual fuel consumption is provided in Table 6-4. 

Equation 6-2 Fuel Consumption for Gas-Fired Water Injection Engines

MMBtu facility year

yr

hr

x

Btu

MMBtu

x

hp hr

Btu

x

facility

hp Fuel Consumption = − − = 39,858 / 8760

10

650 7000 6

Table 6-4 Annual Consumption of Uinta Fuel Gas for Produced Water Injection per Project 

Alternative

Project Alternative

Operating Injection Facilities Fuel Consumption

(wells) (MMBtu/yr)

No Action -- --

Proposed Action 13 518,154

Optimal Recovery 23 916,734

6.3.3 Mobile Combustion Sources

The project alternatives would include mobile sources from drilling, construction, and production. Emissions 

from these sources were based on information provided by KMG and an estimate of VMT or mobile equipment 

operating hours used for criteria pollutant emissions.

6.3.3.1 Drill Rigs

Drill rigs consume diesel fuel both in the engine and the rig boiler. Consumption in the engine was based on a 

BSFC of 7,000 Btu/hp-hr and a heating value of 137,000 Btu/gal. Each rig was assumed to have 4,000 hp of 

total power, with a load factor of 42 percent based on 65 percent utilization and a 65 percent average engine 

load (Pfleider 1972). Determination of diesel consumption based on this factor is shown in Equation 6-3. Each 
6-4 March 2012

rig would operate a 2.8 MMBtu/hr rig boiler to provide heat and steam during the winter months. Each boiler 

would operate a maximum of 4,380 hours per year. Diesel fuel consumption for rig boilers was determined as 

shown in Equation 6-4. Table 6-5 summarizes the diesel fuel use for each project alternative.

Equation 6-3 Diesel Fuel Consumption for Drill Rig Engines

x load gal well

Btu

gal x

day

hr

x

wells

days

x

hp hr

Btu

x

drill rig

hp Fuel Consumption 0.42 30,902 /

137,000

4000 7000 15 24 = − =

Equation 6-4 Diesel Fuel Consumption for Rig Boiler

gal rig yr

yr

hr

x

Btu

gal x

MMBtu

Btu

x

hr

MMBtu Fuel Consumption = = 89,518 / − 4380

137,000

2.8 106

Table 6-5 Annual Consumption of Diesel Fuel for Drill Rig Engines and Boilers

Project Alternative

Drill Rig Engines Rig Boilers

Wells Drilled Fuel Consumption Rig Count Fuel Consumption

(wells/year) (gallons/year) (rigs) (gallons/year)

No Action 192 5,933,220 8 716,146

Proposed Action 336 10,383,136 14 1,253,255

Optimal Recovery 672 20,766,272 28 2,506,511

6.3.3.2 Construction and Drilling Equipment

Heavy mobile equipment is used to construct well pads, water injection facilities, and linear facilities such as 

roads and pipelines. Additionally, mobile equipment is used during well drilling. Emissions of GHG result from 

the combustion of diesel fuel in these engines. Diesel fuel use in gallons was estimated from mobile equipment 

operation from an assumed engine operation in hp-hr/day using an estimate of vehicle size and operation 

duration for each activity. These assumptions are identical to those used for criteria pollutant assumptions in 

Chapter 3.0. Engine operation (in hp-hr/day) is the product of the number of each piece of required equipment, 

engine size per piece, and operating hours per day for each type of facility. Each facility total operation also 

includes an operating load factor of 42 percent (Pfleider 1972) to account for periods of non-continuous 

operation and less than peak load. Tables 6-6, 6-7, and 6-8 summarize the load adjusted engine operation (in 

hp-hr/day) for the various types of construction activity considered under each alternative. As shown in 

Equation 6-5, annual diesel fuel use per unit constructed was estimated by converting engine operation (in 

hp-hr/day) to gallons using a BSFC of 7,000 Btu/hp-hr, a fuel heating value of 137,000 Btu/gal, and an 

estimate of construction duration. The diesel fuel consumption factor per activity is summarized in Table 6-9. 

Total annual diesel fuel consumption for each alternative is summarized in Table 6 10.
6-5 March 2012

Table 6-6 Load Adjusted Engine Operation for Well Pad Construction

Equipment

Duration Engine Size Number of Equipment 

Required

Operation

(hours/day) (hp) (hp-hr/day)

Dozer 12 300 2 7,200

Grader 12 300 1 3,600

Water Truck 12 210 1 2,520

Dump Truck 12 330 2 7,920

Total 21,240

Load Factor 0.42

Load Adjusted1 8,921 1 Per single well pad

Table 6-7 Load Adjusted Engine Operation for Construction of Mancamps, Injection Facilities, and 

Linear Facilities

Equipment

Duration Engine Size Number of 

Equipment Required

Operation

(hours/day) (hp) (hp-hr/day)

Loader 8 200 1 1,600

Dozer 11 300 1 3,300

Scraper 11 600 2 13,200

Grader 12 300 1 3,600

Backhoe 8 100 1 800

Roller 10 200 1 2,000

Water Truck 12 210 1 2,520

Dump Truck 6 330 1 1,980

Total 29,000

Load Factor 0.42

Load Adjusted1 12,180 1 Per facility or mile of linear facility

Table 6-8 Load Adjusted Engine Operation for Well Drilling

Equipment

Duration Engine Size Number of 

Equipment Required

Operation

(hours/day) (hp) (hp-hr/day)

Backhoe 4 100 1 400

Cement/CSG Trucks 12 200 6 14,400

Water Truck 12 210 3 7,560

Dump Truck 12 330 2 7,920

Total 30,280

Load Factor 0.42

Load Adjusted1 12,718 1 Per well drilled

Equation 6-5 Diesel Fuel Consumption per Unit Constructed

Btu

gal x hp hr

Btu Fuel Consumption gal facility mile Operation hp hr day x Duration days facility mile x 137,000

7000 ( / [ ]) ( / ) ( / [ ]) − = −
6-6 March 2012

Table 6-9 Diesel Fuel Consumption Factor for Mobile Equipment by Activity

Activity

Load Adjusted Operation Construction Duration Fuel Consumption Factor

(hp-hour/day) (days) (gallons)

Single Well Pad (per pad) 8,921 12.5 5,697.7

Mancamps (per camp) 12,180 25 15,558.4

Injection Wells (per well) 12,180 1 622.3

Linear Facilities (per mile) 12,180 3 1,867.0

Well Drilling (per well) 12,718 15 9,747.4

Table 6-10 Annual Diesel Fuel Consumption for Mobile Equipment by Alternative and Activity

Activity

Annual Activity By Alternative

Annual Fuel Consumption By Alternative 

(gallons/year)

No 

Action

Proposed 

Action

Optimal 

Recovery Unit No Action

Proposed 

Action

Optimal 

Recovery

Single Well Pad 192 336 672 pads 1,093,962 1,914,434 3,828,867

Mancamps 1 1 1 camps 15,558 15,558 15,558

Injection Wells -- 2 2 wells -- 1,245 1,245

Linear Facilities 50.75 199 232.1 miles 94,751 371,534 433,332

Construction Subtotal 1,204,271 2,301,526 4,279,002

Well Drilling 192 336 672 wells 1,871,495 3,275,117 6,550,234

6.3.3.3 Heavy Truck Traffic

GHG emissions from heavy truck traffic include the fuel consumed from hauling equipment and material to and 

from construction sites. Heavy truck traffic was estimated for each activity type (drilling, construction, and 

production) based on the estimate of VMT per well or unit of construction per the criteria pollutant emission 

calculations in Chapter 3.0. Diesel fuel use for each usage type was determined using the API Compendium 

fuel efficiency of 7 miles per gallon (mpg) for heavy diesel powered trucks (Table 4-10, API 2004) to develop a 

normalized fuel consumption factor in gallons per unit of construction. Table 6-11 summarizes the diesel fuel 

consumption for each activity while Table 6-12 summarizes annual fuel use for each alternative by activity.

Table 6-11 Diesel Fuel Consumption Factor by Activity

Activity

Miles Traveled per Activity

(VMT)

Fuel Consumption Factor

(gallons)

Single Well Pad (per well) 102.5 14.6

Mancamps (per camp) 2,640 377.1

Injection Wells (per well) 2,640 377.1

Linear Facilities (per mile) 2,640 377.1

Drilling and Completion (per well) 7,546 1,078

Production (per well) 1,022 146
6-7 March 2012

Table 6-12 Annual Diesel Fuel Consumption for Heavy Truck Traffic by Alternative and Activity

Activity

Annual Activity By Alternative

Annual Fuel Consumption By 

Alternative (gallons/year)

No 

Action

Proposed 

Action

Optimal 

Recovery Unit No Action

Proposed 

Action

Optimal 

Recovery

Single Well Pad 192 336 672 pads 2,811 4,920 9,840

Mancamps 1 1 1 camps 377 377 377

Injection Wells -- 2 2 wells -- 754 754

Linear Facilities 50.75 199 232.1 miles 19,140 75,051 87,535

Construction Subtotal 22,329 81,103 95,506

Drilling and Completion 192 336 672 wells 206,976 362,208 724,416

Production 910 3,339 12,774 wells 132,860 487,494 1,865,004

6.3.3.4 Light Duty Vehicle Traffic

Light duty truck traffic for drilling and construction was based on the estimate of VMT per well or unit of 

construction from criteria pollutant calculations in Chapter 3.0. Data provided by KMG indicated that its light 

duty fleet traveled 4,323,405 miles in 2006 while servicing 1,083 wells that year for an average of 

3,992.1 VMT/well. Gasoline consumption for each usage type was determined using the fuel efficiency of 

14 mpg for gasoline powered trucks (Table 4-10, API 2004) to develop a normalized fuel consumption factor in 

gallons per unit of construction. Table 6-13 summarizes the gasoline consumption for each activity while 

Table 6-14 summarizes annual use for each alternative by activity.

Table 6-13 Gasoline Consumption Factor by Activity

Activity

Miles Traveled per Activity

(VMT)

Fuel Consumption Factor

(gallons)

Single Well Pad (per well) 410 29.3

Mancamps (per camp) 1,760 125.7

Injection Wells (per well) 1,760 125.7

Linear Facilities (per mile) 11 0.8

Drilling and Completion (per well) 10,890 777.9

Production (per well) 3,992.1 285.1

Table 6-14 Annual Gasoline Consumption for Light Duty Vehicle Traffic by Alternative and Activity

Activity

Annual Activity By Alternative

Annual Fuel Consumption By 

Alternative (gallons/year)

No 

Action

Proposed 

Action

Optimal 

Recovery Unit No Action

Proposed 

Action

Optimal 

Recovery

Single Well Pad 192 336 672 pads 5,623 9,840 19,680

Mancamps 1 1 1 camps 126 126 126

Injection Wells -- 2 2 wells -- 251 251

Linear Facilities 50.75 199 232.1 miles 40 156 182

Construction Subtotal 5,788 10,373 20,240

Drilling and Completion 192 336 672 wells 149,349 261,360 522,720

Production 910 3,339 12,774 Wells 259,484 952,107 4,383,109
6-8 March 2012

6.4 Flaring

Data provided by KMG indicated flaring of 620,000 scf (620 Mscf) at the Bridge compressor station for a 

3-month period during 2006. In 2006, the GNBPA produced 74,606 MMscf of gas. The volume of gas flared 

was assumed to be linearly proportional to the gas produced, with additional flares installed as necessary to 

accommodate requirements. Equation 6-5 derives a flaring rate based on annual field production. Table 6-15

summarizes the quantity of gas flared by project alternative during peak production.

Equation 6-5 Estimation of Gas Flared

Mscf flared MMscf produced

year

months

x

MMscf produced

year x

months

Mscf flared Flaring 0.033 / 12

3 74,606

620 = =

Table 6-15 Gas Flaring by Alternative

Alternative

Peak Field Production Gas Flared

(MMscf/year) (Mscf/year)

No Action 101,300 3,367

Proposed Action 318,900 10,601

Optimal Recovery 616.700 20,500

6.5 Flashing Emissions

Each project alternative would include the handling of condensate and produced water under pressures 

greater than atmospheric. When these material streams are allowed to return to atmospheric pressure, CH4, 

held in liquid form by high pressure, returns to gas and is emitted to the atmosphere. The emissions from this 

process, known as flashing, were based on the physical properties of liquid. The SANGEATM flashing module 

implements the Vasquez-Beggs equation for flashing emissions, which uses temperature, pressure, CH4

content, specific gravity, and API gravity to estimate CH4 emissions. In the absence of physical data on the 

liquid stream, emissions factors from the Compendium were used (API 2004).

6.5.1 Condensate Flashing

Since the physical data was available for condensate, the SANGEATM flashing module was used to calculate 

CH4 emissions from condensate flashing. A summary of condensate physical data as provided by KMG is 

provided in Table 6-16. Similar to VOC flashing emissions, new wells were assumed to produce 10 bbl/day of 

condensate, while old wells (1 year or older) produce an average of 3 bbl/day. This analysis assumed 1 year of 

drilling new wells and the balance of total wells to be old wells. Table 6-17 provides a summary of maximum 

condensate throughput for each alternative.

Table 6-16 Summary of Condensate Physical Characteristics

Parameter Value

Specific Gravity of Flash Gas at 60°F 1.22

API Gravity of Oil at 60°F 61.28

Oil Temperature (°F) 78

Oil Pressure (psig) 90

Fraction of CH4 in Flash Gas (Volume Fraction) 0.496

Source: see Appendix B.
6-9 March 2012

Table 6-17 Maximum Condensate Production by Alternative

Alternative Number of Operating Wells

Condensate Production

(bbl/year)

No Action

New 192 700,800

Old 910 996,450

Total 1,102 1,697,250

Proposed Action

New 336 1,226,400

Old 3,339 3,656,205

Total 3,675 4,882,605

Optimal Recovery

New 672 2,452,800

Old 12,774 13,987,530

Total 13,446 16,440,330

6.5.2 Water Flashing

The Compendium provides emission factors for produced water tank flashing emissions for various separator 

pressures and produced water salt contents (Table 5-8, API 2004). This factor was used in lieu of the flashing 

module since the necessary physical properties of the produced water were unknown. The emission factor 

using an average salt content and a separator pressure of 250 psi is 0.0142 tonnes CH4/1,000 bbl of produced 

water (kg/bbl), and this value was used as a conservative estimate. This factor will tend to overestimate CH4

emissions since it is based on higher separator pressure than measured in the separator. Base on data 

provided by KMG, total produced water was assumed to be 90 bbl/MMscf of gas produced. Table 6-18

summarizes the estimates of produced water for water flashing emissions.

Table 6-18 Produced Water by Alternative

Alternative

Peak Gas Production Maximum Produced Water

(MMscf/year) (bbl/year)

No Action 101,300 9,117,000

Proposed Action 318,900 28,701,000

Optimal Recovery 616,700 55,503,000

6.6 Fugitive Emissions

Fugitive emissions include losses of CH4 from production, processing, and transmission, which were based on 

either facility counts or production throughput. The fugitive emissions module in SANGEATM uses emission 

factors from the API Compendium based on default CH4 content of each process stream. For gas processing, 

the Chapita plant was designed to handle 750 MMscf/day using 3 trains for each action alternative, which is 

equivalent to a maximum throughput of 273,750 MMscf/year. However, this analysis assumes that the gas 

processing plant will only process the field maximum production as part of the No Action Alternative since this 

is less than the maximum throughput. The total field production for the remaining alternatives exceeds the 

maximum capacity of the gas plant, so the plant capacity was used. Additional CH4 emissions from gathering 

lines and compression were based on amount of new lines and the number of new stations over existing 

conditions. Table 6-19 summarizes the emission factors and inputs for all alternatives. 
6-10 March 2012

Table 6-19 Emissions Factors and Operating Parameters for Estimating Fugitive CH4 Emissions

Source CH4 Emission Factor

Operating 

Parameter

Alternative

No Action

Proposed 

Action

Optimal 

Recovery

Onshore Gas Production 0.026 Mg/MMscf MMscf/yr 101,300 318,900 616,700

Gathering Pipeline Leaks 0.03 Mg/mile miles 276 1,036 1,036

Gas Processing Plants 0.02 Mg/MMscf MMscf/yr 101,300 273,750 273,750

Compressor Stations 5.12 Mg/station new station 6 8 8

6.7 Indirect Emissions

Indirect GHG emissions include additional emissions that would occur upstream of the project as a result of 

the increased activity from the proposed alternatives. In this case, additional annual electricity use in all project 

alternatives and the gas plant would increase significantly due to the installation of electric compression 

engines. Compression at the gas plant is the same for all project alternatives. Total annual electricity 

consumption was based on additional electric compression using Equation 6-6. Emission factors for GHG 

from electricity production vary by region since the means of power production and fuel characteristics vary by 

region. GHG emissions for electricity consumption for this analysis were based on the factors provided in 

SANGEATM for Utah-produced electrical power. The emissions factors are provided in Table 6-20, and a 

summary of estimated additional electricity consumption is provided in Table 6-21.

Equation 6-6 Estimation of Annual Electricity Consumption for Added Electric Compression

year

hours

x

kW

GW

x

hp

kW Electricy Consumption GWh yr Added Compression hp x8,760

10

0.7457 ( / ) ( ) 6 =

Table 6-20 GHG Emissions Factors for Imported Utah-based Electric Consumption

Pollutant

Emission Factor

(Mg/GWh)

CO2 877.2

CH4 0.0061

N2O 0.014

Operating Parameters

Line Losses 8%

Efficiency 37.54%

Table 6-21 Summary of Estimated Electricity Consumption for Added Electric Compression

Alternative or Activity

Added Electric Compression Estimated Annual Electricity Consumption

(hp) (GWh/yr)

No Action 67,550 441

Proposed Action 97,550 637

Optimal Recovery 196,300 1,282

Gas Processing Plant 91,550 598
6-11 March 2012

6.8 Venting

6.8.1 Pneumatics

Based on pump inventory data provided by KMG, there are two pneumatic devices per operating well. No 

significant change in the pneumatics at midstream operations is anticipated. All pneumatics were considered 

to be “low-bleed” with a natural gas release rate of 3 scf/day, resulting in a calculated emission factor of 47.7 lb 

CH4/device-year as shown in Equation 6-7. Emissions of CO2 and N2O from gas-driven pneumatics are 

considered negligible. Table 6-22 includes a summary of pneumatic counts by project alternative used for 

GHG estimation.

Equation 6-7 Low Bleed Pneumatic CH4 Emission Factor

lb CH device yr

year

day x

lb gas

lb CH

x

scf

lb gas x

device day

scf EF = − − = 47.7 / 3 0.047 0.925 365

4

4

Table 6-22 Summary of Venting Parameters for GHG Emissions Calculations

Source Operating Parameter

Alternative

No Action Proposed Action Optimal Recovery

Pneumatics devices 1,820 6,678 25,548

Workovers workovers 107 389 1,507

Completions completions 192 336 672

6.8.2 Workovers

GHG emissions in CH4 from workovers were calculated based on the default Compendium factor of 4.6995 x 

10-2 Mg CH4/workover (API 2004). Based on data provided by KMG, there would be 1 workover per 

8.5 operating wells. The number of workovers by project alternative considered for GHG estimation is provided 

in Table 6-22. 

6.8.3 Completions

Additional GHG are emitted during fracturing and completion of a well. Review of KMG completion procedures 

indicated that 1.5 MMscf of gas is released per day of completion, with 95 percent captured or controlled. 

Using a gas analysis of CH4 and CO2 (see Appendix B), an estimate of GHG per completion of 8.2 tons 

CH4/completion and 0.07 tons CO2/completion is derived as shown in Equations 6-8 and 6-9. The number of 

completions is equal to the number of wells drilled as shown in Table 6-22.

Equation 6-8 CH4 Emissions from Well Completions

Control ton CH completion completion

days x lbton x lb gas

lb CH x scf

lb gas x MMscfscf x dayMMscf EF (1 0.95) 8.2 / 5

2000

1.5 10 0.047 0.925 4

4

6

= − =

Equation 6-9 CO2 Emissions from Well Completions

Control ton CO completion completion

days x lb

ton x lb gas

lb CO x scf

lb gas x MMscfscf x dayMMscf EF (1 0.95) 0.07 / 5

2000

1.5 10 0.047 0.008 2

24

6

= − =
6-12 March 2012

6.9 Summary of GHG Emissions

The data as described in previous sections was entered into the SANGEATM tool. The total annual GHG 

emissions (in CO2e) for each alternative are summarized in Table 6-23. Detailed emission rates by source and 

pollutant type for each alternative are provided in Tables 6-24, 6-25, and 6-26. Inputs are summarized in 

Table 6-27. The input and output worksheets are provided in Appendix F. 

Table 6-23 Maximum Projected Annual GHG Emissions Increase by Alternative

No Action Proposed Action Optimal Recovery

Total Emissions (tonne CO2e) 1,761,016 2,754,167 5,484,666

The GHG emissions presented in Table 6-23 were calculated based on implementation of the 

applicant-committed environmental protection measures quantified in the modeling analysis (see 

Table 1-1). Implementation of these measures is intended to reduce criteria air pollutants and HAPs; 

some measures also may reduce GHG emissions (e.g., the use of low-emission dehydrators, low-bleed 

pneumatics, and green completion techniques to control emissions of CH4), while others may increase 

GHG emissions (e.g., the use of electric compression and lean-burn natural gas-fired engines). The net 

effect of the applicant-committed environmental protection measures is a 4 percent increase in GHG 

emissions (as CO2e) for the both the Proposed Action and Optimal Recovery alternatives. This 

primarily is due to the use of electric compression, which uses mostly coal-fired sources of electricity,

and the increased emission of CH4 and N2O from lean-burn natural gas-fired engines. The 

implementation of the applicant-committed environmental protection measures represents a trade-off 

of air quality improvements in the GNBPA for an increase in GHG emissions locally and at distant 

coal-fired power plants.

Table 6-24 Detailed Summary of Annual GHG Emissions by Source for the No Action Alternative

Source CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) CO2e

Stationary Combustion 462,999 9 8.5 186 2,623 465,808

Mobile Combustion 106,744 15 10.5 322 3,261 110,357

Flare 239 0 0.005 5 1 246

Flashing 0 1,463 0 30,730 0 30,730

Fugitive 0 6,056 0 127,182 0 127,182

Indirect Emission 990,719 7 15.6 144 4,891 995,754

Venting 12 1,473 0 30,926 0 30,938

Total (tonne CO2e) 1,560,774 9,024 34.8 189,496 10,777 1,761,016
6-13 March 2012

Table 6-25 Detailed Summary of Annual GHG Emissions by Source for the Proposed Action 

Source CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) CO2e

Stationary Combustion 855,690 16 15.6 344 4,847 860,880

Mobile Combustion 197,377 28 19.1 581 5,915 203,873

Flare 753 1 0.01 17 5 775

Flashing 0 4,245 0 89,142 0 89,142

Fugitive 0 17,142 0 359,973 0 359,973

Indirect Emission 1,177,611 8 18.8 171 5,814 1,183,596

Venting 21 2,662 0 55,907 0 55,928

Total (tonne CO2e) 2,231,452 24,102 53.5 506,135 16,580 2,754,167

Table 6-26 Detailed Summary of Annual GHG Emissions by Source for the Optimal Recovery 

Alternative

Source CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) CO2e

Stationary Combustion 2,306,292 44 42.1 926 13,063 2,320,281

Mobile Combustion 419,221 58 40.1 1,212 12,446 432,879

Flare 1,456 2 0.03 33 9 1,498

Flashing 0 13,709 0 287,883 0 287,883

Fugitive 0 24,870 0 522,260 0 522,260

Indirect Emission 1,792,639 12 28.5 261 8,850 1,801,750

Venting 43 5,622 0 118,072 0 188,115

Total (tonne CO2e) 4,519,651 44,317 110.9 930,647 34,368 5,484,666
6-14 March 2012 

 

Table 6-27 Summary of Input Parameters for GHG Calculations 

Stationary Combustion Sources 

Location Source Description Source Id Units No Action Proposed Action Optimal Recovery 

Fuel Uinta Fuel Gas 

E&P Separator Heater SHTR 106 Btu (HHV) 1,992,900 7,312,410 27,909,360 

E&P Water Injection Compression Engines WICMP 106 Btu (HHV) N/A 518,154 916,734 

Fuel GNB Fuel Gas 

Midstream Chapita Plant Heaters CHPT HTR 106 Btu (HHV) 546,624 546,624 546,624 

Midstream Compression (Gas Fired) CMP 106 Btu (HHV) 6,096,741 7,581,911 13,627,261 

Midstream Flaring FLARE 103 scf 3,367 10,601 20,500 

Mobile Combustion Sources 

Location Source Description Source Id Units No Action Proposed Action Optimal Recovery 

Fuel Gasoline 

E&P Light Truck Traffic (Drilling and Completion) LTDC 103 gal 149 261 523 

E&P Light Truck Traffic (Construction) LTCON 103 gal 6 10 20 

Midstream Light Truck Traffic (Production) LTPRD 103 gal 312 1,146 4,383 

Fuel Diesel / Distillate (No. 2) 

E&P Drill Rig Engines DRENG 103 gal 5,933 10,383 20,776 

E&P Heavy Truck Traffic (Drilling and Completion) HTDC 103 gal 207 362 724 

E&P Mobile Equipment (Drilling and Completion) DRMOB 103 gal 1,871 3,275 6,550 

E&P Heavy Truck Traffic (Construction) HTCON 103 gal 22 81 99 

E&P Mobile Equipment (Construction) CNMOB 103 gal 1,204 2,302 4,279 

E&P Rig Boilers DRBOIL 103 gal 716 1,253 2,507 

Midstream Heavy Truck Traffic (Production) HTPRD 103 gal 133 487 1,865 

Flashing Sources 

Location Input Parameters Source Id Units No Action Proposed Action Optimal Recovery 

Midstream 

Oil Flow 

OIL FLASH 

bbl 1,697,250 4,882,605 16,440,330 

Oil Temperature F 78 78 78 

Oil Pressure psi 90 90 90 

Fraction of CH4 in Flash Gas Volume Fraction 0.496 0.496 0.496 

E&P CH4 emission based on Activity Data WTR FLASH bbl 9,117,000 28,701,000 55,503,000 

Fugitive Sources 

Location Source Description Source Id Units No Action Proposed Action Optimal Recovery 

E&P Onshore Gas Production PRD FUG 106 scf 101,300 318,900 616,700 

E&P Gathering Pipeline Leaks FUG GTH Mile 276 1,036 1,036 

Midstream Compressor Stations FUG CMP Station 6 8 8 

Midstream Gas Processing Plants FUG CHPT 106 scf 101,300 273,750 273,750 

Indirect Sources 

Location Source Description Source Id Units No Action Proposed Action Optimal Recovery 

Midstream Electric Compression – Field ELEC CMP GWh 441 637 1,282 

Midstream Electric Compression – Chapita ELEC CHPT GWh 598 598 598 

Venting Sources 

Location Source Description Source Id Units No Action Proposed Action Optimal Recovery 

E&P Gas Driven Pneumatics EP PNEU Devices 1,820 6,678 25,548 

E&P Workovers WORKOVER Workovers 107 389 1,507 

E&P CO2 emission based on Activity Data Completion - CO2 Completions 192 336 672 

E&P CH4 emission based on Activity Data Completion - CH4 Completions 192 336 672 
7-1 March 2012

7.0 Air Quality Summary 

This technical support document provides details regarding local and regional air quality conditions and 

expected impacts resulting from the reasonably foreseeable future development within the GNBPA. The 

analyses assess the impacts of the Proposed Action and the Optimal Recovery Alternative compared to 

emissions from the Projected Baseline. The Resource Protection Alternative was not modeled because 

emissions related to the development of this alternative are well-characterized by the impacts from the 

Proposed Action. As noted in Chapter 2.0, the regional air quality currently is classified as in attainment or 

unclassifiable. This means that there are no direct measurements of background air quality in the area of 

development. 

7.1 Impact on Class I and II Areas – Air Quality 

The guideline CALPUFF modeling system was used to determine impacts on Class I areas and selected 

Class II areas in the region. For the Proposed Action scenario, the greatest impact on ambient air quality from 

project sources on Class I areas was at Arches National Park, where the maximum impact for all criteria air 

pollutants occurs. The highest PM10 24-hour impact was 0.10 μg/m3 at this site. All other impacts for all criteria 

pollutants at all Class I areas for the Proposed Action scenario were below 0.01 μg/m3

. 

The greatest impacts under the Proposed Action scenario at the identified sensitive Class II areas were at the 

Flaming Gorge National Recreation Area (3.23 μg/m3 for 24-hour PM10 levels and 0.58 μg/m3 for annual PM10). 

All other impacts from all other criteria pollutants at Class II areas were less than 0.5 μg/m3

.

For the Optimal Recovery Alternative, the maximum 24-hour PM10 impact at Class I areas was 0.24 μg/m3 at 

Arches National Park. The highest annual average PM10 impact of 0.02 μg/m3 also occurred at this area. All

other impacts from all other criteria pollutants at Class I areas were less than 0.13 μg/m3

. 

For the Optimal Recovery Alternative at sensitive Class II areas, the maximum impacts were at the Flaming 

Gorge National Recreation Area for all criteria air pollutants. The maximum annual average NO2 impact was 

0.94 μg/m3

. The PM10 impact on a 24-hour average was 7.36 μg/m3, and the annual PM10 impact was

1.38 μg/m3

. Impacts from all other criteria pollutants at all other Class II areas were less than 1.0 μg/m3.

When added to the background concentrations, all cumulative impacts from all sources for each of the 

alternatives, including the modeled non-project sources, were below the established NAAQS for all criteria 

pollutants.

7.2 Impact at Class I and II Areas – Visibility 

The CALPUFF model system was used to evaluate impacts on visibility at the Class I areas and at the listed 

sensitive Class II areas. The results of the simulations under the Proposed Action scenario showed that there 

are no days with a contribution to visibility impacts greater than 5 percent in extinction (0.5 dv) at listed Class I 

areas for either the Method 2 or Method 6 analysis. The conclusion is that the Proposed Action would not 

contribute to an impact on visibility at these sites. The modeling results at the listed sensitive Class II areas 

showed the highest impacts at Flaming Gorge National Recreation Area and Dinosaur National Monument. 

Results from Method 6 showed that up to 102 days would be impacted with greater than 10 percent increase 

in extinction at Flaming Gorge. The same analysis showed the eighth highest increase in extinction for the 

Proposed Action is 32.6 percent. At Dinosaur National Monument, the model predicted 32 days per year with 

an impact above 10 percent and an eighth highest increase in light extinction of 16.6 percent. Except at

Flaming Gorge National Recreation Area and Dinosaur National Monument, modeled results for all other 

Class II areas under Method 6 showed all of the eighth highest impacts were less than a 10 percent increase 

in extinction (1.0 dv).
7-2 March 2012

For the Optimal Recovery Alternative, all project-related impacts were below 10 percent light extinction at all

Class I areas. At Class II areas under the Optimal Recovery Alternative, the eighth highest impacts using 

Method 6 were above 10 percent at Flaming Gorge National Recreation Area and Dinosaur National 

Monument. The eighth highest increase in light extinction for project-related sources was 62.4 percent at 

Flaming Gorge National Recreation Area, with 156 days predicted to be greater than 10 percent. At Dinosaur 

National Monument, the eighth highest increase in light extinction was 32.7 percent, with 71 days predicted to 

be greater than 10 percent.

7.3 Impacts at Class I and II areas – Acid Deposition 

The CALPUFF model system also provided acid deposition results for sulfate and nitrate ion deposition at

Class I and sensitive Class II areas, which were then used to analyze impacts to the ANC of selected sensitive 

lakes in the modeling domain. Impacts from project-related sources under both the Proposed Action and the 

Optimal Recovery Alternative were well below the USFS-established comparative deposition values (5 and 

3 kg/ ha-yr for sulfur and nitrogen deposition, respectively). Cumulative deposition from all modeled sources 

also was below the established comparative deposition values for both alternatives at all Class I and Class II 

areas except Mesa Verde National Park. 

The model showed that project-related impacts at all identified sensitive lakes were below the USFS screening 

threshold for ANC established for further analysis. Therefore, no additional analysis was conducted on these 

impacts.

7.4 Impacts on Ambient Ozone Levels 

Impacts on ozone were evaluated using the CMAQ model system. The modeling system meets the 

USEPA-established criteria for acceptable model accuracy and error statistics at the existing monitoring 

stations in the modeling domain, but not in the region. There are no recent or statistically valid representative 

monitoring data that can be used to compare to baseline modeled impacts actual levels in the GNBPA. This 

lack of concurrent data prevents validation and calibration of the model results; however, the model does 

provide a means to compare the relative change in ambient ozone concentration between the project 

alternatives and baseline air quality.

The model results showed ozone levels below the current ozone standard of 75 ppb for the fourth highest 

annual level in the Uinta Basin for the Projected Baseline and for the project alternatives. The maximum fourth 

highest impact was 2.4 ppb from the Proposed Action scenario and 4.9 ppb from the Optimal Recovery 

Alternative. For both scenarios, the impacts were occurring in areas simulated to remain below the 75 ppb 

ozone standard.

As stated in Section 3.7, the regional inventory for the action alternatives was revised for the analysis 

conducted for the SDEIS due to one additional rig needed to drill slightly more wells per year. While 

this would result in almost no change in VOCs, the project-related NOX emissions would increase by 

6.8 percent for the Proposed Action. This project-related NOX emissions increase could result in 

project-specific impacts to ambient ozone levels slightly different than those modeled for the scenario 

that assumed one less drill rig.

7.5 Localized Impacts on Air Quality 

The AERMOD modeling system was used to evaluate localized impacts on criteria air pollutants at receptors 

within the GNBPA. The analysis was based on a series of source configurations, including well sites, drilling, 

operation, and compression, and provided projected air quality impacts on the near field. A 5-year period of 

meteorological data from the Vernal Airport was utilized. 

Using background data from AQS, the localized impacts on ambient air quality for criteria pollutants of 

single sources plus background were all less than the NAAQS. The impacts of all multiple production 

well scenarios also were below the NAAQS. Near-field modeling showed that simultaneous operation 
7-3 March 2012

of drill rigs on adjacent pads would not cause an exceedance of the NAAQS for 1-hour NO2. The 

modeled ambient air concentrations of HAPs do not exceed USEPA RfCs or TSLs for any scenario or 

pollutant.

7.6 Greenhouse Gas Emissions

The predicted annual increase in GHG emissions (CO2, N2O, and CH4) were tabulated for both the Proposed 

Action and the Optimal Recovery Alternative. Both direct project-related and indirect (from electric power 

generation) emissions were included. During the maximum production year for each alternative, a total 

2.75 million metric tons of CO2 equivalent gases would be emitted by the Proposed Action, and 5.48 million 

metric tons of CO2 equivalent gases would be emitted by the Optimal Recovery Alternative.
8-1 March 2012

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March 2012

Appendix A

Projected Baseline Emissions Calculations Supporting Data
Table A-1 Summary of 2018 Projected Baseline Emissions by County

NOx CO

County

Historical Projected Baseline Baseline/

Historical 

Ratio County

Historical Projected Base

WRAP Uncontrolled Controlled WRAP Uncontrolled Con

2006 2018 2006 2018

Uintah 6,096 10,841 5,888 0.97 Uintah 4,133 8,589 

 

Carbon 995 3,823 1,322 1.33 Carbon 814 3,855 

 

Duchesne 3,053 4,797 2,512 0.82 Duchesne 2,448 4,768 

 

Grand 337 337 213 0.63 Grand 207 207 

 

Emery 273 273 204 0.75 Emery 199 199 

 

Total 10,754 20,071 10,138 0.94 Total 7,800 17,618 

 

SO2 PM10

County

Historical Projected Baseline Baseline/

Historical 

Ratio County

Historical Projected Base

WRAP Uncontrolled Controlled WRAP Uncontrolled Con

2006 2018 2006 2018

Uintah 247 275 20 0.08 Uintah 344 523 

 

Carbon 22 

7 2 0.08 Carbon 40 86 

 

Duchesne 96 58 6 0.07 Duchesne 173 235 

 

Grand 16 16 1 0.05 Grand 22 22 

 

Emery 9 

9 1 0.06 Emery 14 14 

 

Total 391 365 30 0.08 Total 592 879 

 

VOC

County

Historical Projected Baseline Baseline/

Historical 

Ratio

WRAP Uncontrolled Controlled

2006 2018

Uintah 45,646 130,537 126,425 2.77

Carbon 2,747 14,027 13,553 4.93

Duchesne 19,019 41,663 41,495 2.18

Grand 2,360 2,360 2,345 0.99 

Emery 453 453 444 0.98 

Total 70,226 189,040 184,262 2.62

Projected Baseline Emiss
Table A-2 Summary of Emissions Scaling Factors Based on Selected Operational Activity Projections

Well Count (cumulative) Spud Count (spuds

Count

y

Historical UBAQS GNB EIS Projections Emissions 

Scalin

g Ratio

Historical UBAQS GNB EIS Proje

2006 2012 2018 2006 2012 

Uintah 4,035 6,718 7,692 12,207 3.03 685 934 1,049 Carbon 730 258 1,244 1,615 2.21 58 118 120

Duchesne 1,474 2,421 2,082 2,981 2.02 277 389 158 

Grand 368 408 N/A 368 1.00 27 70 N/A 

Emer

y 56 91 N/A 56 1.00 23 22 N/A 

Gas Production (MMscf) Condensate Productio

Count

y

Historical UBAQS GNB EIS Projections Emissions 

Scalin

g Ratio

Historical UBAQS GNB EIS Proje

2006 2012 2018 2006 2012 

Uintah 203,391 323,265 445,153 595,651 2.93 1,554 5,723 4,987 Carbon 20,497 52,904 148,923 121,803 5.94 43 77 180 Duchesne 22,526 43,037 27,536 40,025 1.78 163 394 320 Grand 6,855 6,534 N/A 6,855 1.00

9 11 N/A

Emer

y 951 3,978 N/A 951 1.00

4

2 N/A

Oil Production (bbl)

Count

y

Historical UBAQS GNB EIS Projections Emissions 

2006 2012 2018 Scalin

g Ratio

Uintah 3,399 3,291 4,061 4,828 1.42

Carbon 0.3 0.3 N/A 0.3 1.00

Duchesne 6,402 10,673 10,992 15,093 2.36

Grand 116 119 N/A 116 1.00

Emer

y

4

2

N/A

4 1.00

Emissions S
Uintah County

SCC Description

2006 WRAP Phase III Emissions by Source

Scaling Parameter ESF

Scaled 2018 Baseline (w/o reductions) Rule Co

NOx CO SO2 PM10 VOC NOx CO SO2 PM10 VOC NOx CO 

(tpy) (tpy) (

2310000100 Heaters 595.53 506.08 3.91 46.92 34.02 Well Count 3.03 1,801.66 1,531.05 11.84 141.94 102.92 0% 0

2310000220 Drill rigs 3,062.16 1,156.05 226.73 231.70 266.00 Spud Count 0.99 3,026.40 1,142.55 229.00 224.08 262.89 62.3% 69.4

2310000230 Workover rigs 134.64 54.14 11.15 11.14 12.45 Well Count 3.03 407.34 163.78 33.75 33.69 37.68 62.3% 69.4

2310000300 Pneumatic devices - - - - 9,920.59 Well Count 3.03 - - - - 30,012.56 0% 0

2310000330 Artificial Lift 760.99 878.43 0.40 32.84 234.82 Oil Production 1.42 1,080.80 1,247.59 0.57 46.64 333.50 90% 80

2310000700 Unpermitted Fugitives - - - - 1,271.30 Well Count 3.03 - - - - 3,846.05 0% 0

2310000800 Truck Loading of Condensate - - - - 111.49 Condensate Production 3.76 - - - - 419.07 0% 0

2310000801 Truck Loading of Oil - - - - 335.77 Oil Production 1.42 - - - - 476.88 0% 02310000820 Gas Plant Truck Loading - - - - 2.92 Condensate Production 3.76 - - - - 10.97 0% 0

2310001610 Venting - initial completions - - - - 207.80 Spud Count 0.99 - - - - 205.37 0% 02310001611 Initial completion Flaring 0.36 1.96 - - - Spud Count 0.99 0.36 1.94 - - - 0% 0

2310001620 Venting - recompletions - - - - 32.10 Spud Count 0.99 - - - - 31.73 0% 0

2310001630 Venting - blowdowns - - - - 230.44 Gas Production 2.93 - - - - 674.85 0% 0

2310001640 Venting - Compressor Startup - - - - 651.21 Gas Production 2.93 - - - - 1,907.14 0% 0

2310001650 Venting - Compressor Shutdown - - - - 617.24 Gas Production 2.93 - - - - 1,807.65 0% 0

2310002230 Condensate tank - - - - 5,439.26 Condensate Production 3.76 - - - - 20,445.75 0% 0

2310002231 Condensate tank flaring 0.25 1.38 - - - Condensate Production 3.76 0.96 5.20 - - - 0% 0

2310002240 Oil Tank - - - - 5,001.29 Oil Production 1.42 - - - - 7,103.06 0% 0

2310003100 Miscellaneous engines 95.76 34.68 0.05 0.45 23.12 Well Count 3.03 289.69 104.91 0.15 1.37 69.95 90% 80

2310003200 Pneumatic pumps - - - - 5,614.18 Well Count 3.03 - - - - 16,984.45 0% 0

2310020600 Compressor engines 1,354.87 1,423.11 - 18.75 313.21 Gas Production 2.93 3,967.86 4,167.71 - 54.91 917.26 90% 80

2310021410 Dehydrator 90.91 76.36 - 6.91 15,327.27 Gas Production 2.93 266.23 223.64 - 20.23 44,887.41 0% 0

2310021411 Dehydrator Flaring 0.07 0.38 - - - Gas Production 2.93 0.21 1.13 - - - 0% 0

 6,095.55 4,132.58 343.73 247.22 45,646.48 10,841.49 8,589.49 275.30 522.87 130,537.14 

Carbon County

SCC Description

2006 WRAP Phase III Emissions by Source

Scaling Parameter ESF

Scaled 2018 Baseline (w/o reductions) Rule Co

NOx CO SO2 PM10 VOC NOx CO SO2 PM10 VOC NOx CO 

(tpy) (tpy) (

2310000100 Heaters 107.74 91.56 0.71 8.49 6.16 Well Count 2.21 238.36 202.56 1.57 18.78 13.62 0% 0

2310000220 Drill rigs 254.81 96.20 19.28 18.87 22.13 Spud Count 0.00 - - - - - 62.3% 69.4

2310000230 Workover rigs 28.84 11.60 2.39 2.39 2.67 Well Count 2.21 63.81 25.66 5.29 5.28 5.90 62.3% 69.4

2310000300 Pneumatic devices - - - - 297.05 Well Count 2.21 - - - - 657.18 0% 0

2310000330 Artificial Lift 0.06 0.07 0.00 0.00 0.02 Oil Production 1.00 0.06 0.07 0.00 0.00 0.02 90% 80

2310000700 Unpermitted Fugitives - - - - 36.67 Well Count 2.21 - - - - 81.13 0% 0

2310000800 Truck Loading of Condensate - - - - 3.09 Condensate Production 3.43 - - - - 10.61 0% 0

2310000801 Truck Loading of Oil - - - - 0.03 Oil Production 1.00 - - - - 0.03 0% 0

2310000820 Gas Plant Truck Loading - - - - 0.08 Condensate Production 3.43 - - - - 0.28 0% 0

2310001610 Venting - initial completions - - - - 1.67 Spud Count 0.00 - - - - - 0% 0

2310001611 Initial completion Flaring 0.03 0.16 - - - Spud Count 0.00 - - - - - 0% 0

2310001620 Venting - recompletions - - - - 0.26 Spud Count 0.00 - - - - - 0% 0

2310001630 Venting - blowdowns - - - - 26.48 Gas Production 5.94 - - - - 157.38 0% 0

2310001640 Venting - Compressor Startup - - - - 74.84 Gas Production 5.94 - - - - 444.75 0% 0

2310001650 Venting - Compressor Shutdown - - - - 70.94 Gas Production 5.94 - - - - 421.55 0% 0

2310002230 Condensate tank - - - - 150.77 Condensate Production 3.43 - - - - 517.68 0% 02310002231 Condensate tank flaring 0.00 0.01 - - - Condensate Production 3.43 0.01 0.04 - - - 0% 0

2310002240 Oil Tank - - - - 0.42 Oil Production 1.00 - - - - 0.42 0% 0

2310003100 Miscellaneous engines 17.32 6.27 0.01 0.08 4.18 Well Count 2.21 38.33 13.88 0.02 0.18 9.25 90% 80

2310003200 Pneumatic pumps - - - - 126.80 Well Count 2.21 - - - - 280.53 0% 0

2310020600 Compressor engines 549.17 576.83 - 7.60 126.95 Gas Production 5.94 3,263.50 3,427.89 - 45.17 754.43 90% 80

2310021410 Dehydrator 36.85 30.95 - 2.80 1,795.88 Gas Production 5.94 218.97 183.94 - 16.64 10,672.23 0% 02310021411 Dehydrator Flaring 0.03 0.16 - - - Gas Production 5.94 0.17 0.93 - - - 0% 0

 994.86 813.82 22.39 40.23 2,747.10 3,823.22 3,854.96 6.87 86.05 14,026.99 

Table A-3 Calculation of 2018 Projected Baseline Emissions By Source Category and County
Table A-3 Calculation of 2018 Projected Baseline Emissions By Source Category and County

Duchesne County

SCC Description

2006 WRAP Phase III Emissions by Source

Scaling Parameter ESF

Scaled 2018 Baseline (w/o reductions) Rule Co

NOx CO SO2 PM10 VOC NOx CO SO2 PM10 VOC NOx CO 

(tpy) (tpy) (

2310000100 Heaters 217.55 184.87 1.43 17.14 12.43 Well Count 2.02 439.97 373.89 2.89 34.66 25.13 0% 0

2310000220 Drill rigs 1,238.28 467.48 93.70 91.68 107.57 Spud Count 0.56 697.37 263.28 52.77 51.63 60.58 62.3% 69.4

2310000230 Workover rigs 5.36 2.16 0.44 0.44 0.50 Well Count 2.02 10.84 4.36 0.90 0.90 1.00 62.3% 69.4

2310000300 Pneumatic devices - - - - 3,629.17 Well Count 2.02 - - - - 7,339.60 0% 02310000330 Artificial Lift 1,396.51 1,612.03 0.74 60.26 430.91 Oil Production 2.36 3,292.48 3,800.60 1.74 142.08 1,015.94 90% 80

2310000700 Unpermitted Fugitives - - - - 465.08 Well Count 2.02 - - - - 940.56 0% 02310000800 Truck Loading of Condensate - - - - 11.72 Condensate Production 2.79 - - - - 32.64 0% 0

2310000801 Truck Loading of Oil - - - - 616.18 Oil Production 2.36 - - - - 1,452.75 0% 0

2310000820 Gas Plant Truck Loading - - - - 0.31 Condensate Production 2.79 - - - - 0.85 0% 0

2310001610 Venting - initial completions - - - - 30.72 Spud Count 0.56 - - - - 17.30 0% 0

2310001611 Initial completion Flaring 0.15 0.79 - - - Spud Count 0.56 0.08 0.45 - - - 0% 0

2310001620 Venting - recompletions - - - - 4.75 Spud Count 0.56 - - - - 2.67 0% 0

2310001630 Venting - blowdowns - - - - 25.52 Gas Production 1.78 - - - - 45.34 0% 0

2310001640 Venting - Compressor Startup - - - - 72.12 Gas Production 1.78 - - - - 128.14 0% 0

2310001650 Venting - Compressor Shutdown - - - - 68.35 Gas Production 1.78 - - - - 121.46 0% 0

2310002230 Condensate tank - - - - 571.77 Condensate Production 2.79 - - - - 1,592.50 0% 0

2310002231 Condensate tank flaring 0.33 1.79 - - - Condensate Production 2.79 0.92 4.98 - - - 0% 0

2310002240 Oil Tank - - - - 9,177.96 Oil Production 2.36 - - - - 21,638.40 0% 0

2310003100 Miscellaneous engines 34.98 12.67 0.02 0.17 8.45 Well Count 2.02 70.74 25.62 0.04 0.33 17.08 90% 80

2310003200 Pneumatic pumps - - - - 2,053.93 Well Count 2.02 - - - - 4,153.85 0% 0

2310020600 Compressor engines 149.82 157.37 - 2.07 34.64 Gas Production 1.78 266.22 279.63 - 3.68 61.54 90% 80

2310021410 Dehydrator 10.05 8.44 - 0.76 1,697.36 Gas Production 1.78 17.86 15.00 - 1.36 3,015.98 0% 0

2310021411 Dehydrator Flaring 0.01 0.04 - - - Gas Production 1.78 0.01 0.08 - - - 0% 0

 3,053.04 2,447.65 96.33 19,019.42 172.53 4,796.50 4,767.88 58.33 234.65 41,663.33 

Grand County

SCC Description

2006 WRAP Phase III Emissions by Source

Scaling Parameter ESF

Scaled 2018 Baseline (w/o reductions) Rule Co

NOx CO SO2 PM10 VOC NOx CO SO2 PM10 VOC NOx CO 

(tpy) (tpy) (

2310000100 Heaters 54.31 46.16 0.36 4.28 3.10 Well Count 1.00 54.31 46.16 0.36 4.28 3.10 0% 0

2310000220 Drill rigs 120.70 45.57 9.13 8.94 10.48 Spud Count 1.00 120.70 45.57 9.13 8.94 10.48 62.3% 69.4

2310000230 Workover rigs 78.95 31.75 6.54 6.53 7.30 Well Count 1.00 78.95 31.75 6.54 6.53 7.30 62.3% 69.4

2310000300 Pneumatic devices - - - - 906.06 Well Count 1.00 - - - - 906.06 0% 0

2310000330 Artificial Lift 26.08 30.10 0.01 1.13 8.05 Oil Production 1.00 26.08 30.10 0.01 1.13 8.05 90% 80

2310000700 Unpermitted Fugitives - - - - 116.11 Well Count 1.00 - - - - 116.11 0% 0

2310000800 Truck Loading of Condensate - - - - 0.66 Condensate Production 1.00 - - - - 0.66 0% 0

2310000801 Truck Loading of Oil - - - - 11.51 Oil Production 1.00 - - - - 11.51 0% 0

2310000820 Gas Plant Truck Loading - - - - 0.02 Condensate Production 1.00 - - - - 0.02 0% 0

2310001610 Venting - initial completions - - - - 0.75 Spud Count 1.00 - - - - 0.75 0% 0

2310001611 Initial completion Flaring 0.01 0.08 - - - Spud Count 1.00 0.01 0.08 - - - 0% 0

2310001620 Venting - recompletions - - - - 0.12 Spud Count 1.00 - - - - 0.12 0% 0

2310001630 Venting - blowdowns - - - - 7.77 Gas Production 1.00 - - - - 7.77 0% 0

2310001640 Venting - Compressor Startup - - - - 21.95 Gas Production 1.00 - - - - 21.95 0% 0

2310001650 Venting - Compressor Shutdown - - - - 20.80 Gas Production 1.00 - - - - 20.80 0% 0

2310002230 Condensate tank - - - - 32.01 Condensate Production 1.00 - - - - 32.01 0% 0

2310002231 Condensate tank flaring 0.01 0.04 - - - Condensate Production 1.00 0.01 0.04 - - - 0% 0

2310002240 Oil Tank - - - - 171.37 Oil Production 1.00 - - - - 171.37 0% 02310003100 Miscellaneous engines 8.73 3.16 0.00 0.04 2.11 Well Count 1.00 8.73 3.16 0.00 0.04 2.11 90% 80

2310003200 Pneumatic pumps - - - - 512.79 Well Count 1.00 - - - - 512.79 0% 02310020600 Compressor engines 45.59 47.89 - 0.63 10.54 Gas Production 1.00 45.59 47.89 - 0.63 10.54 90% 80

2310021410 Dehydrator 3.06 2.57 - 0.23 516.52 Gas Production 1.00 3.06 2.57 - 0.23 516.52 0% 0

2310021411 Dehydrator Flaring 0.00 0.01 - - - Gas Production 1.00 0.00 0.01 - - - 0% 0

 337.45 207.31 16.05 21.78 2,359.99 337.45 207.31 16.05 21.78 2,359.99 
Table A-3 Calculation of 2018 Projected Baseline Emissions By Source Category and County

Emery county

SCC Description

2006 WRAP Phase III Emissions by Source

Scaling Parameter ESF

Scaled 2018 Baseline (w/o reductions) Rule Co

NOx CO SO2 PM10 VOC NOx CO SO2 PM10 VOC NOx CO 

(tpy) (tpy) (

2310000100 Heaters 40.44 34.37 0.27 3.19 2.31 Well Count 1.00 40.44 34.37 0.27 3.19 2.31 0% 0

2310000220 Drill rigs 102.82 38.82 7.78 7.61 8.93 Spud Count 1.00 102.82 38.82 7.78 7.61 8.93 62.3% 69.4

2310000230 Workover rigs 7.20 2.90 0.60 0.60 0.67 Well Count 1.00 7.20 2.90 0.60 0.60 0.67 62.3% 69.4

2310000300 Pneumatic devices - - - - 162.78 Well Count 1.00 - - - - 162.78 0% 0

2310000330 Artificial Lift 0.86 0.99 0.00 0.04 0.26 Oil Production 1.00 0.86 0.99 0.00 0.04 0.26 90% 80

2310000700 Unpermitted Fugitives - - - - 20.39 Well Count 1.00 - - - - 20.39 0% 0

2310000800 Truck Loading of Condensate - - - - 0.02 Condensate Production 1.00 - - - - 0.02 0% 0

2310000801 Truck Loading of Oil - - - - 0.38 Oil Production 1.00 - - - - 0.38 0% 0

2310000820 Gas Plant Truck Loading - - - - 0.00 Condensate Production 1.00 - - - - 0.00 0% 0

2310001610 Venting - initial completions - - - - 0.27 Spud Count 1.00 - - - - 0.27 0% 0

2310001611 Initial completion Flaring 0.01 0.07 - - - Spud Count 1.00 0.01 0.07 - - - 0% 0

2310001620 Venting - recompletions - - - - 0.04 Spud Count 1.00 - - - - 0.04 0% 0

2310001630 Venting - blowdowns - - - - 1.88 Gas Production 1.00 - - - - 1.88 0% 0

2310001640 Venting - Compressor Startup - - - - 5.31 Gas Production 1.00 - - - - 5.31 0% 0

2310001650 Venting - Compressor Shutdown - - - - 5.03 Gas Production 1.00 - - - - 5.03 0% 0

2310002230 Condensate tank - - - - 0.76 Condensate Production 1.00 - - - - 0.76 0% 0

2310002231 Condensate tank flaring 0.00 0.00 - - - Condensate Production 1.00 0.00 0.00 - - - 0% 0

2310002240 Oil Tank - - - - 5.62 Oil Production 1.00 - - - - 5.62 0% 0

2310003100 Miscellaneous engines 6.50 2.35 0.00 0.03 1.57 Well Count 1.00 6.50 2.35 0.00 0.03 1.57 90% 80

2310003200 Pneumatic pumps - - - - 78.03 Well Count 1.00 - - - - 78.03 0% 0

2310020600 Compressor engines 107.74 113.17 - 1.49 24.91 Gas Production 1.00 107.74 113.17 - 1.49 24.91 90% 80

2310021410 Dehydrator 7.23 6.07 - 0.55 133.45 Gas Production 1.00 7.23 6.07 - 0.55 133.45 0% 0

2310021411 Dehydrator Flaring 0.01 0.03 - - - Gas Production 1.00 0.01 0.03 - - - 0% 0

 272.81 198.76 8.65 13.50 452.61 272.81 198.76 8.65 13.50 452.61 
March 2012

Appendix B

Project-specific Emissions Calculations Supporting Data
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC 

365 S. MAIN STREET 

BRIGHTON, CO 80601 

(303) 637-0150 

EXTENDED NATURAL GAS LIQUID ANALYSIS (*DHA) 

PROJECT NO. : 200705124 ANALYSIS NO. : 01 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

ACCOUNT NO. : SAMPLE DATE : MAY 14, 2007 

PRODUCER : CYLINDER NO. : Q12374 

LEASE NO. : SAMPLED BY : J. S. JOHNSON 

NAME/DESCRIP : NATURAL BUTTES 

NBU 920 - 25F 

***FIELD DATA*** SAMPLE TEMP. : 78 

SAMPLE PRES. : 140 AMBIENT TEMP.: 

VAPOR PRES. : GRAVITY : 

COMMENTS : GAS VOLUME: 1,061 MCF 

MANUAL; CYL. PRESS: 140 

COMPONENT MOLE % MASS % VOL % 

NITROGEN (AIR) 0.000 0.000 0.000 

CO2 0.219 0.091 0.081 

METHANE 4.224 0.647 1.561 

ETHANE 2.156 0.614 1.257 

PROPANE 2.127 0.888 1.280 

I-BUTANE 1.037 0.571 0.738 

N-BUTANE 1.849 1.018 1.274 

2,2 DIMETHYLPROPANE 0.000 0.000 0.000 

I-PENTANE 1.791 1.224 1.430 

N-PENTANE 1.895 1.295 1.499 

HEXANES PLUS 84.702 93.652 90.880 

TOTALS 100.000 100.000 100.000 

BTEX COMPONENTS MOLE% MASS% (CALC: GPA STD 2145-94 & TP-17 @14.696 & 60 F) 

BENZENE 0.942 0.697 Specific Gravity (H2O=1) = 0.7327 60/60 

TOLUENE 5.668 4.946 API Gravity = 61.62 60/60 

ETHYLBENZENE 0.431 0.433 Molecular Weight = 105.58 

XYLENE 6.198 6.231 Absolute Density = 6.09 LBS/GAL 

TOTAL BTEX 13.239 12.307 Heating Value Liq. Idl Gas= 123403 BTU/GAL 

Vapor/Liquid = 21.89 CUFT/GAL 

Vapor Pressure = 235.91 PSIA & 100 F 

*(DETAILED HYDROCARBON ANALYSIS/NJ 1993) ; ASTM D6730 

THIS DATA HAS BEEN ACQUIRED THROUGH APPLICATION OF CURRENT STATE-OF-THE-ART ANALYTICAL TECHNIQUES. 

THE USE OF THIS INFORMATION IS THE RESPONSIBLITY OF THE USER. EMPACT ANALYTICAL SYSTEMS, ASSUMES NO 

RESPONSIBLITY FOR ACCURACY OF THE REPORTED INFORMATION NOR ANY CONSEQUENCES OF IT'S APPLICATION. 

Page 1 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC 

365 S. MAIN STREET 

BRIGHTON, CO 80601 

(303) 637-0150 

EXTENDED NATURAL GAS LIQUID ANALYSIS (*DHA) 

PROJECT NO. :	 200705124 ANALYSIS NO. : 01 

COMPANY NAME :	 ANADARKO ANALYSIS DATE: MAY 24, 2007 

ACCOUNT NO. :	 SAMPLE DATE : MAY 14, 2007 

PRODUCER :	 CYLINDER NO. : Q12374 

LEASE NO. :	 SAMPLED BY : J. S. JOHNSON 

NAME/DESCRIP :	 NATURAL BUTTES 

NBU 920 - 25F 

***FIELD DATA***	 SAMPLE TEMP. : 78 

SAMPLE PRES. :	 140 AMBIENT TEMP.: 

VAPOR PRES. :	 GRAVITY : 

COMMENTS : GAS VOLUME: 1,061 MCF 

MANUAL; CYL. PRESS: 140 

TOTALS BY CARBON NUMBER 

CARBON NUMBER	 MOLE% MASS % VOL % 

Nitrogen (air)	 0.000 0.000 0.000 

Carbon Dioxide	 0.219 0.091 0.081 

Methanol 0.000 0.000 0.000 

C1 4.224 0.647 1.561 

C2 2.156 0.614 1.257 

C3 2.127 0.888 1.280 

C4 2.886 1.589 2.012 

C5 4.122 2.809 3.211 

C6 10.147 8.138 8.302 

C7 22.854 21.074 20.240 

C8 21.942 23.123 21.913 

C9 12.345 14.780 14.465 

C10 7.924 11.117 11.057 

C11 4.019 6.483 6.290 

C12 2.222 3.584 3.476 

C13 1.535 2.681 2.577 

C14 0.845 1.474 1.418 

C15 0.306 0.636 0.600 

C16 0.114 0.244 0.231 

C17 0.011 0.024 0.023 

C18 0.002 0.004 0.006 

C19 0.000 0.000 0.000 

C20+ 0.000 0.000 0.000 

Total	 100.000 100.000 100.000 

Average Molecular Weight of Hexanes plus = 116.98 

Average Specific Gravity of Hexanes plus = 0.756 

Average Molecular Weight of Decanes plus = 160.26 

Average Specific Gravity of Decanes plus = 0.741 

Page 2 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC
 

365 S. MAIN STREET
 

BRIGHTON, CO 80601
 

(303) 637-0150
 

E & P Tank / GlyCalc Information 

PROJECT NO. : 200705124 ANALYSIS NO. : 01 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

ACCOUNT NO. : SAMPLE DATE : MAY 14, 2007 

PRODUCER : CYLINDER NO. : Q12374 

LEASE NO. : SAMPLED BY : J. S. JOHNSON 

NAME/DESCRIP : NATURAL BUTTES 

NBU 920 - 25F 

***FIELD DATA*** SAMPLE TEMP. : 78 

SAMPLE PRES. : 140 AMBIENT TEMP.: 

VAPOR PRES. : GRAVITY : 

COMMENTS : GAS VOLUME: 1,061 MCF 

COMPONENT Mole % Wt % LV % 

CO2 0.219 0.091 0.081 

HYDROGEN SULFIDE 0.000 0.000 0.000 

METHANOL 0.000 0.000 0.000 

NITROGEN (AIR) 0.000 0.000 0.000 

METHANE 4.224 0.647 1.561 

ETHANE 2.156 0.614 1.257 

PROPANE 2.127 0.888 1.280 

I-BUTANE 1.037 0.571 0.738 

N-BUTANE 1.849 1.018 1.274 

I-PENTANE 1.791 1.224 1.430 

N-PENTANE 1.895 1.295 1.499 

CYCLOPENTANE (N-C5) 0.436 0.290 0.282 

N-HEXANE 2.805 2.289 2.519 

CYCLOHEXANE (OTHER C6) 2.548 2.031 1.891 

OTHER HEXANES 3.852 3.121 3.315 

OTHER HEPTANES 9.898 9.351 9.702 

METHYLCYCLOHEXANE (OTHER C6) 7.288 6.777 6.393 

2,2,4 TRIMETHYLPENTANE 0.000 0.000 0.000 

BENZENE 0.942 0.697 0.577 

TOLUENE 5.668 4.946 4.145 

ETHYLBENZENE 0.431 0.433 0.363 

XYLENES 6.198 6.231 5.200 

OTHER OCTANES 15.313 16.459 16.350 

OCTANES PLUS ---­ 44.636 ---­ 57.486 ---­ 56.493 

NONANES 12.345 14.780 14.465 

DECANES PLUS 16.978 26.247 25.678 

SUBTOTAL 100.000 100.000 100.000 

OXYGEN 0.000 0.000 0.000 

TOTAL 100.000 100.000 100.000 

API Gravity = 61.62 60/60 

Vapor Pressure = 235.91 PSIA & 100 F 

Average Molecular Weight of Decanes plus = 160.26 

Average Specific Gravity of Decanes plus = 0.741 

Page 3 
 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC 

365 S. MAIN STREET 

BRIGHTON, CO 80601 

(303) 637-0150 

EXTENDED NATURAL GAS LIQUID ANALYSIS (*DHA) 

PROJECT NO. : 200705124 ANALYSIS NO. : 01 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

COMPONENT PIANO # MOLE % MASS % VOL % 

NITROGEN (AIR) 0.000 0.000 0.000 

CO2 0.219 0.091 0.081 

METHANE P1 4.224 0.647 1.562 

ETHANE P2 2.156 0.614 1.256 

PROPANE P3 2.127 0.888 1.280 

I-BUTANE I4 1.037 0.571 0.738 

N-BUTANE P4 1.849 1.018 1.274 

2,2 DIMETHYLPROPANE I5 0.000 0.000 0.000 

I-PENTANE I5 1.791 1.224 1.430 

N-PENTANE P5 1.895 1.295 1.499 

2,2 DIMETHYLBUTANE I6 0.157 0.128 0.144 

METHANOL X1 0.000 0.000 0.000 

CYCLOPENTANE N5 0.436 0.290 0.282 

2 METHYLPENTANE I6 1.534 1.252 1.389 

3 METHYLPENTANE I6 0.980 0.800 0.871 

N-HEXANE P6 2.805 2.289 2.519 

2,2-DIMETHYLPENTANE I7 0.075 0.071 0.075 

METHYLCYCLOPENTANE N6 1.181 0.941 0.911 

2,4 DIMETHYLPENTANE I7 0.377 0.358 0.386 

2,2,3 TRIMETHYLBUTANE I7 0.102 0.097 0.104 

BENZENE A6 0.942 0.697 0.577 

3,3 DIMETHYLPENTANE I7 0.139 0.132 0.138 

CYCLOHEXANE N6 2.548 2.031 1.891 

2 METHYLHEXANE I7 0.705 0.669 0.715 

2,3 DIMETHYLPENTANE I7 0.692 0.656 0.686 

1,1 DIMETHYLCYCLOPENTANE N7 0.474 0.441 0.421 

3 METHYLHEXANE I7 1.320 1.253 1.320 

1,C 3 DIMETHYLCYCLOPENTANE N7 0.398 0.370 0.363 

1,T 3 DIMETHYLCYCLOPENTANE N7 0.286 0.266 0.259 

3 ETHYLPENTANE I7 0.131 0.124 0.127 

1,T 2 DIMETHYLCYCLOPENTANE N7 0.877 0.816 0.790 

N-HEPTANE P7 4.063 3.856 4.093 

1,C 2 DIMETHYLCYCLOPENTANE N7 0.008 0.008 0.006 

METHYLCYCLOHEXANE N7 7.288 6.777 6.393 

2,2-DIMETHYLHEXANE I8 1.314 1.421 1.441 

ETHYLCYCLOPENTANE N7 0.251 0.234 0.219 

2,2,3-TRIMETHYLPENTANE I8 0.226 0.245 0.248 

2,4-DIMETHYLHEXANE I8 0.358 0.387 0.404 

1C,2T,4-TRIMETHYLCYCLOPENTANE N8 0.131 0.139 0.133 

Page 4 
 

 

PROJECT NO. : 200705124 ANALYSIS NO. : 01 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

COMPONENT PIANO # MOLE % MASS % VOL % 

3,3-DIMETHYLHEXANE I8 0.170 0.184 0.184 

2,3,4-TRIMETHYLPENTANE I8 0.036 0.039 0.040 

2,3,3-TRIMETHYLPENTANE I8 0.004 0.005 0.006 

TOLUENE A7 5.668 4.946 4.145 

2,3-DIMETHYLHEXANE I8 0.297 0.321 0.329 

2-METHYL-3-ETHYLPENTANE I8 0.127 0.137 0.127 

1,1,2-TRIMETHCYCLOPENTANE N8 0.072 0.078 0.081 

2-METHYLHEPTANE I8 0.747 0.808 0.842 

4-METHYLHEPTANE I8 0.642 0.695 0.715 

3-METHYL-3-ETHYLPENTANE I8 0.095 0.103 0.098 

3,4-DIMETHYLHEXANE I8 0.070 0.075 0.075 

1C,2C,4-TRIMETHYLCYCLOPENTANE N8 0.258 0.274 0.254 

3-METHYLHEPTANE I8 0.710 0.768 0.790 

1C,2T,3-TRIMETHYLCYCLOPENTANE N8 1.266 1.346 1.239 

3-ETHYLHEXANE I8 0.200 0.216 0.219 

1T,4-DIMETHYLCYCLOHEXANE N8 1.922 2.042 1.943 

1,1-DIMETHYLCYCLOHEXANE N8 0.470 0.499 0.461 

3C-ETHYLMETHYLCYCLOPENTANE N8 0.053 0.056 0.052 

3T-ETHYLMETHYLCYCLOPENTANE N8 0.120 0.128 0.115 

2T-ETHYLMETHYLCYCLOPENTANE N8 0.068 0.072 0.063 

1,1-METHYLETHYLCYCLOPENTANE N8 0.115 0.122 0.110 

2,2,4-TRIMETHYLHEXANE I9 0.063 0.077 0.075 

1T,2-DIMETHYLCYCLOHEXANE N8 0.794 0.844 0.778 

N-OCTANE P8 3.439 3.720 3.845 

2,4,4-TRIMETHYLHEXANE I9 0.235 0.286 0.288 

1C,2-DIMETHYLCYCLOHEXANE N8 0.093 0.099 0.092 

2,2-DIMETHYLHEPTANE I9 0.068 0.082 0.081 

2,3,5-TRIMETHYLHEXANE I9 0.121 0.147 0.150 

1,1,4-TRIMETHYLCYCLOHEXANE N9 0.839 1.004 0.945 

2,2,3-TRIMETHYLHEXANE I9 0.447 0.543 0.553 

ETHYLCYCLOHEXANE N9 0.261 0.312 0.294 

N-PROPYLCYCLOPENTANE N8 0.248 0.264 0.248 

1C,3C,5-TRIMETHYLCYCLOHEXANE N9 0.140 0.168 0.156 

3,5-DIMETHYLHEPTANE I9 0.061 0.075 0.075 

2,6-DIMETHYLHEPTANE I9 0.038 0.046 0.046 

2,5-DIMETHYLHEPTANE I9 0.073 0.088 0.092 

3,3-DIMETHYLHEPTANE I9 0.106 0.128 0.127 

ETHYLBENZENE A8 0.431 0.433 0.363 

1C,2T,4T-TRIMETHYLCYCLOHEXANE N9 0.053 0.063 0.058 

1,3-DIMETHYLBENZENE (M-XYLENE) A8 3.655 3.674 3.067 

1,4-DIMETHYLBENZENE (P-XYLENE) A8 1.423 1.431 1.193 

3,4-DIMETHYLHEPTANE I9 1.389 1.686 1.678 

4-METHYLOCTANE I9 0.234 0.285 0.288 

2-METHYLOCTANE I9 0.833 1.012 1.032 

1C,2T,3-TRIMETHYLCYCLOHEXANE N9 0.196 0.239 0.242 

3-ETHYLHEPTANE I9 0.112 0.136 0.138 

Page 5 
 

 

COMPONENT PIANO # MOLE % MASS % VOL % 

3-METHYLOCTANE 

1C,2T,4C-TRIMETHYLCYCLOHEXANE 

1,1,2-TRIMETHYLCYCLOHEXANE 

1,2-DIMETHYLBENZENE (O-XYLENE) 

I-BUTYCYCLOPENTANE 

UNKNOWN OCTANE'S 

N-NONANE 

I-PROPYLBENZENE 

I-PROPYLCYCLOHEXANE 

2,4-DIMETHYLOCTANE 

2,6-DIMETHYLOCTANE 

N-BUTYCYCLOPENTANE 

3,3-DIMETHYLOCTANE 

N-PROPYLBENZENE 

3,6-DIMETHYLOCTANE 

3-METHYL-5-ETHYLHEPTANE 

UNKNOWN NONANE'S 

N-DECANE 

UNKNOWN DECANE'S 

N-UNDECANE 

DODECANES 

TRIDECANES 

TETRADECANES 

PENTADECANES 

HEXADECANES 

HEPTADECANES 

OCTADECANES 

TOTALS 

I9 

N9 

N9 

A8 

N9 

U8 

P9 

A9 

N9 

I10 

I10 

N9 

I10 

A9 

I10 

I10 

U9 

P10 

U10 

P11 

C12'S 

C13'S 

C14'S 

C15'S 

C16'S 

C17'S 

C18'S 

0.537 

0.184 

0.011 

1.120 

0.285 

1.268 

2.777 

0.292 

0.358 

0.324 

0.427 

0.570 

0.316 

0.479 

0.051 

0.069 

1.583 

2.315 

4.422 

4.019 

2.222 

1.535 

0.845 

0.306 

0.114 

0.011 

0.002 

100.000 

0.653 

0.220 

0.012 

1.126 

0.341 

1.372 

3.373 

0.294 

0.360 

0.437 

0.575 

0.682 

0.426 

0.546 

0.069 

0.084 

1.922 

3.273 

6.253 

6.483 

3.584 

2.681 

1.474 

0.636 

0.244 

0.024 

0.004 

100.000 

0.657 

0.202 

0.012 

0.940 

0.306 

1.418 

3.413 

0.242 

0.300 

0.427 

0.582 

0.617 

0.421 

0.455 

0.069 

0.081 

1.943 

3.257 

6.220 

6.290 

3.476 

2.577 

1.418 

0.600 

0.231 

0.023 

0.006 

100.000 

PROJECT NO. : 200705124 

COMPANY NAME : ANADARKO 

ANALYSIS NO. : 01 

ANALYSIS DATE: MAY 24, 2007 

Page 6 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC 

365 S. MAIN STREET 

BRIGHTON, CO 80601 

(303) 637-0150 

EXTENDED NATURAL GAS LIQUID ANALYSIS (*DHA) 

PROJECT NO. : 200705124 ANALYSIS NO. : 02 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

ACCOUNT NO. : SAMPLE DATE : MAY 14, 2007 

PRODUCER : CYLINDER NO. : Q11074 

LEASE NO. : SAMPLED BY : J. S. JOHNSON 

NAME/DESCRIP : NATURAL BUTTES 

NBU 920 - 25O 

***FIELD DATA*** SAMPLE TEMP. : 79 

SAMPLE PRES. : 100 AMBIENT TEMP.: 

VAPOR PRES. : GRAVITY : 

COMMENTS : MANUAL; CYL. PRESS: 100 

COMPONENT MOLE % MASS % VOL % 

NITROGEN (AIR) 0.000 0.000 0.000 

CO2 0.618 0.254 0.229 

METHANE 3.864 0.569 1.423 

ETHANE 1.778 0.499 1.029 

PROPANE 1.794 0.738 1.069 

I-BUTANE 0.845 0.458 0.600 

N-BUTANE 1.561 0.847 1.063 

2,2 DIMETHYLPROPANE 0.000 0.000 0.000 

I-PENTANE 1.544 1.040 1.223 

N-PENTANE 1.647 1.109 1.292 

HEXANES PLUS 86.349 94.486 92.072 

TOTALS 100.000 100.000 100.000 

BTEX COMPONENTS MOLE% MASS% (CALC: GPA STD 2145-94 & TP-17 @14.696 & 60 F) 

BENZENE 0.871 0.635 Specific Gravity (H2O=1) = 0.7353 60/60 

TOLUENE 5.646 4.854 API Gravity = 60.94 60/60 

ETHYLBENZENE 0.466 0.462 Molecular Weight = 107.18 

XYLENE 6.947 6.882 Absolute Density = 6.13 LBS/GAL 

TOTAL BTEX 13.930 12.833 Heating Value Liq. Idl Gas= 123624 BTU/GAL 

Vapor/Liquid = 21.67 CUFT/GAL 

Vapor Pressure = 213.58 PSIA & 100 F 

*(DETAILED HYDROCARBON ANALYSIS/NJ 1993) ; ASTM D6730 

THIS DATA HAS BEEN ACQUIRED THROUGH APPLICATION OF CURRENT STATE-OF-THE-ART ANALYTICAL TECHNIQUES. 

THE USE OF THIS INFORMATION IS THE RESPONSIBLITY OF THE USER. EMPACT ANALYTICAL SYSTEMS, ASSUMES NO 

RESPONSIBLITY FOR ACCURACY OF THE REPORTED INFORMATION NOR ANY CONSEQUENCES OF IT'S APPLICATION. 

Page 1 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC 

365 S. MAIN STREET 

BRIGHTON, CO 80601 

(303) 637-0150 

EXTENDED NATURAL GAS LIQUID ANALYSIS (*DHA) 

PROJECT NO. :	 200705124 ANALYSIS NO. : 02 

COMPANY NAME :	 ANADARKO ANALYSIS DATE: MAY 24, 2007 

ACCOUNT NO. :	 SAMPLE DATE : MAY 14, 2007 

PRODUCER :	 CYLINDER NO. : Q11074 

LEASE NO. :	 SAMPLED BY : J. S. JOHNSON 

NAME/DESCRIP :	 NATURAL BUTTES 

NBU 920 - 25O 

***FIELD DATA***	 SAMPLE TEMP. : 79 

SAMPLE PRES. :	 100 AMBIENT TEMP.: 

VAPOR PRES. :	 GRAVITY : 

COMMENTS :	 MANUAL; CYL. PRESS: 100 

TOTALS BY CARBON NUMBER 

CARBON NUMBER	 MOLE% MASS % VOL % 

Nitrogen (air)	 0.000 0.000 0.000 

Carbon Dioxide	 0.618 0.254 0.229 

Methanol 0.000 0.000 0.000 

C1 3.864 0.569 1.423 

C2 1.778 0.499 1.029 

C3 1.794 0.738 1.069 

C4 2.406 1.305 1.663 

C5 3.611 2.424 2.784 

C6 9.504 7.509 7.688 

C7 22.715 20.631 19.935 

C8 23.337 24.205 23.028 

C9 12.817 15.083 14.796 

C10 8.031 11.102 11.109 

C11 4.344 6.904 6.740 

C12 2.384 3.788 3.699 

C13 1.531 2.634 2.550 

C14 0.784 1.350 1.304 

C15 0.329 0.672 0.640 

C16 0.114 0.241 0.229 

C17 0.024 0.054 0.051 

C18 0.008 0.018 0.017 

C19 0.002 0.006 0.006 

C20+ 0.005 0.014 0.011 

Total	 100.000 100.000 100.000 

Average Molecular Weight of Hexanes plus = 117.50 

Average Specific Gravity of Hexanes plus = 0.755 

Average Molecular Weight of Decanes plus = 159.08 

Average Specific Gravity of Decanes plus = 0.742 

Page 2 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC
 

365 S. MAIN STREET
 

BRIGHTON, CO 80601
 

(303) 637-0150
 

E & P Tank / GlyCalc Information 

PROJECT NO. :	 200705124 ANALYSIS NO. : 02 

COMPANY NAME :	 ANADARKO ANALYSIS DATE: MAY 24, 2007 

ACCOUNT NO. :	 SAMPLE DATE : MAY 14, 2007 

PRODUCER :	 CYLINDER NO. : Q11074 

LEASE NO. :	 SAMPLED BY : J. S. JOHNSON 

NAME/DESCRIP :	 NATURAL BUTTES 

NBU 920 - 25O 

***FIELD DATA***	 SAMPLE TEMP. : 79 

SAMPLE PRES. :	 100 AMBIENT TEMP.: 

VAPOR PRES. :	 GRAVITY : 

COMMENTS :	 MANUAL; CYL. PRESS: 100 

COMPONENT Mole % Wt % LV % 

CO2 0.618 0.254 0.229 

METHANOL 0.000 0.000 0.000 

NITROGEN (AIR) 0.000 0.000 0.000 

METHANE 3.864 0.569 1.423 

ETHANE 1.778 0.499 1.029 

PROPANE 1.794 0.738 1.069 

I-BUTANE 0.845 0.458 0.600 

N-BUTANE 1.561 0.847 1.063 

I-PENTANE 1.544 1.040 1.223 

N-PENTANE 1.647 1.109 1.292 

CYCLOPENTANE (N-C5) 0.420 0.275 0.269 

N-HEXANE 2.588 2.081 2.304 

CYCLOHEXANE (OTHER C6) 2.441 1.917 1.795 

OTHER HEXANES 3.604 2.876 3.063 

OTHER HEPTANES 9.616 8.949 9.358 

METHYLCYCLOHEXANE (OTHER C6) 7.453 6.828 6.483 

2,2,4 TRIMETHYLPENTANE 0.000 0.000 0.000 

BENZENE 0.871 0.635 0.526 

TOLUENE 5.646 4.854 4.094 

ETHYLBENZENE 0.466 0.462 0.389 

XYLENES 6.947 6.882 5.780 

OTHER OCTANES 15.924 16.861 16.859 

OCTANES PLUS ---- 46.297 ---- 58.727 ---- 58.011 

NONANES 12.817 15.083 14.796 

DECANES PLUS 17.556 26.783 26.356 

SUBTOTAL 100.000 100.000 100.000 

OXYGEN 0.000 0.000 0.000 

TOTAL	 100.000 100.000 100.000 

API Gravity = 60.94 60/60 

Vapor Pressure = 213.58 PSIA & 100 F 

Average Molecular Weight of Decanes plus = 159.08 

Average Specific Gravity of Decanes plus = 0.742 

Page 3 
 

 

 

 

 

 

 

 

 

 

EMPACT ANALYTICAL SYSTEMS, INC 

365 S. MAIN STREET 

BRIGHTON, CO 80601 

(303) 637-0150 

EXTENDED NATURAL GAS LIQUID ANALYSIS (*DHA) 

PROJECT NO. : 200705124 ANALYSIS NO. : 02 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

COMPONENT PIANO # MOLE % MASS % VOL % 

NITROGEN (AIR) 0.000 0.000 0.000 

CO2 0.618 0.254 0.229 

METHANE P1 3.864 0.569 1.423 

ETHANE P2 1.778 0.499 1.029 

PROPANE P3 1.794 0.738 1.069 

I-BUTANE I4 0.845 0.458 0.600 

N-BUTANE P4 1.561 0.847 1.063 

2,2 DIMETHYLPROPANE I5 0.000 0.000 0.000 

I-PENTANE I5 1.544 1.040 1.223 

N-PENTANE P5 1.647 1.109 1.292 

2,2 DIMETHYLBUTANE I6 0.148 0.119 0.131 

METHANOL X1 0.000 0.000 0.000 

CYCLOPENTANE N5 0.420 0.275 0.269 

2,3 DIMETHYLBUTANE I6 0.000 0.000 0.000 

2 METHYLPENTANE I6 1.366 1.099 1.229 

3 METHYLPENTANE I6 0.886 0.713 0.783 

N-HEXANE P6 2.588 2.081 2.304 

2,2-DIMETHYLPENTANE I7 0.077 0.072 0.080 

METHYLCYCLOPENTANE N6 1.204 0.945 0.920 

2,4 DIMETHYLPENTANE I7 0.307 0.287 0.314 

2,2,3 TRIMETHYLBUTANE I7 0.091 0.085 0.091 

BENZENE A6 0.871 0.635 0.526 

3,3 DIMETHYLPENTANE I7 0.118 0.110 0.114 

CYCLOHEXANE N6 2.441 1.917 1.795 

2 METHYLHEXANE I7 0.801 0.749 0.806 

2,3 DIMETHYLPENTANE I7 0.567 0.530 0.555 

1,1 DIMETHYLCYCLOPENTANE N7 0.424 0.389 0.377 

3 METHYLHEXANE I7 1.286 1.202 1.281 

1,C 3 DIMETHYLCYCLOPENTANE N7 0.392 0.359 0.354 

1,T 3 DIMETHYLCYCLOPENTANE N7 0.311 0.285 0.280 

3 ETHYLPENTANE I7 0.103 0.096 0.103 

1,T 2 DIMETHYLCYCLOPENTANE N7 0.841 0.771 0.749 

N-HEPTANE P7 4.037 3.775 4.031 

1,C 2 DIMETHYLCYCLOPENTANE N7 0.009 0.008 0.006 

METHYLCYCLOHEXANE N7 7.453 6.828 6.483 

2,2-DIMETHYLHEXANE I8 1.182 1.260 1.286 

ETHYLCYCLOPENTANE N7 0.252 0.231 0.217 

2,5-DIMETHYLHEXANE I8 0.218 0.232 0.246 

2,4-DIMETHYLHEXANE I8 0.332 0.354 0.366 

Page 4 
 

 

PROJECT NO. : 200705124 ANALYSIS NO. : 02 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

COMPONENT PIANO # MOLE % MASS % VOL % 

1C,2T,4-TRIMETHYLCYCLOPENTANE N8 0.137 0.144 0.137 

3,3-DIMETHYLHEXANE I8 0.167 0.178 0.183 

2,3,4-TRIMETHYLPENTANE I8 0.034 0.036 0.034 

2,3,3-TRIMETHYLPENTANE I8 0.006 0.007 0.006 

TOLUENE A7 5.646 4.854 4.094 

2,3-DIMETHYLHEXANE I8 0.327 0.348 0.360 

2-METHYL-3-ETHYLPENTANE I8 0.094 0.100 0.091 

1,1,2-TRIMETHCYCLOPENTANE N8 0.028 0.030 0.029 

2-METHYLHEPTANE I8 0.881 0.939 0.983 

4-METHYLHEPTANE I8 0.704 0.751 0.778 

3-METHYL-3-ETHYLPENTANE I8 0.071 0.075 0.069 

3,4-DIMETHYLHEXANE I8 0.069 0.073 0.074 

1C,2C,4-TRIMETHYLCYCLOPENTANE N8 0.168 0.176 0.166 

3-METHYLHEPTANE I8 0.804 0.857 0.886 

1C,2T,3-TRIMETHYLCYCLOPENTANE N8 1.406 1.472 1.366 

3-ETHYLHEXANE I8 0.330 0.352 0.360 

1T,4-DIMETHYLCYCLOHEXANE N8 1.783 1.867 1.789 

1,1-DIMETHYLCYCLOHEXANE N8 0.482 0.505 0.475 

3C-ETHYLMETHYLCYCLOPENTANE N8 0.047 0.049 0.046 

3T-ETHYLMETHYLCYCLOPENTANE N8 0.122 0.128 0.120 

2T-ETHYLMETHYLCYCLOPENTANE N8 0.068 0.071 0.063 

1,1-METHYLETHYLCYCLOPENTANE N8 0.119 0.124 0.114 

2,2,4-TRIMETHYLHEXANE I9 0.062 0.074 0.074 

1T,2-DIMETHYLCYCLOHEXANE N8 0.811 0.849 0.789 

N-OCTANE P8 4.048 4.314 4.488 

I-PROPYLCYCLOPENTANE N8 0.249 0.260 0.240 

1C,2-DIMETHYLCYCLOHEXANE N8 0.108 0.113 0.103 

2,2-DIMETHYLHEPTANE I9 0.073 0.087 0.086 

2,3,5-TRIMETHYLHEXANE I9 0.118 0.141 0.143 

1,1,4-TRIMETHYLCYCLOHEXANE N9 0.958 1.128 1.069 

2,2,3-TRIMETHYLHEXANE I9 0.442 0.528 0.543 

ETHYLCYCLOHEXANE N9 0.267 0.314 0.297 

N-PROPYLCYCLOPENTANE N8 0.309 0.323 0.303 

1C,3C,5-TRIMETHYLCYCLOHEXANE N9 0.125 0.148 0.137 

3,5-DIMETHYLHEPTANE I9 0.053 0.063 0.063 

2,6-DIMETHYLHEPTANE I9 0.013 0.015 0.017 

2,5-DIMETHYLHEPTANE I9 0.066 0.080 0.080 

3,3-DIMETHYLHEPTANE I9 0.096 0.115 0.114 

ETHYLBENZENE A8 0.466 0.462 0.389 

1C,2T,4T-TRIMETHYLCYCLOHEXANE N9 0.130 0.153 0.143 

1,3-DIMETHYLBENZENE (M-XYLENE) A8 4.309 4.269 3.585 

1,4-DIMETHYLBENZENE (P-XYLENE) A8 1.485 1.471 1.235 

3,4-DIMETHYLHEPTANE I9 0.541 0.648 0.646 

4-METHYLOCTANE I9 0.258 0.309 0.314 

2-METHYLOCTANE I9 0.897 1.073 1.098 

1C,2T,3-TRIMETHYLCYCLOHEXANE N9 0.173 0.207 0.212 

Page 5 
 

 

PROJECT NO. : 200705124 ANALYSIS NO. : 02 

COMPANY NAME : ANADARKO ANALYSIS DATE: MAY 24, 2007 

COMPONENT PIANO # MOLE % MASS % VOL % 

3-ETHYLHEPTANE I9 0.119 0.143 0.143 

3-METHYLOCTANE I9 0.587 0.703 0.715 

1C,2T,4C-TRIMETHYLCYCLOHEXANE N9 0.150 0.177 0.166 

1,1,2-TRIMETHYLCYCLOHEXANE N9 0.015 0.018 0.017 

1,2-DIMETHYLBENZENE (O-XYLENE) A8 1.153 1.142 0.960 

I-BUTYCYCLOPENTANE N9 0.325 0.382 0.349 

UNKNOWN OCTANE'S U8 0.820 0.874 0.909 

N-NONANE P9 3.108 3.719 3.785 

I-PROPYLBENZENE A9 0.346 0.343 0.286 

I-PROPYLCYCLOHEXANE N9 0.372 0.368 0.309 

2,4-DIMETHYLOCTANE I10 0.372 0.494 0.486 

2,6-DIMETHYLOCTANE I10 0.412 0.546 0.560 

N-BUTYCYCLOPENTANE N9 0.599 0.706 0.640 

3,3-DIMETHYLOCTANE I10 0.346 0.460 0.452 

N-PROPYLBENZENE A9 0.764 0.857 0.720 

3,6-DIMETHYLOCTANE I10 0.063 0.084 0.086 

3-METHYL-5-ETHYLHEPTANE I10 0.044 0.052 0.051 

UNKNOWN NONANE'S U9 2.160 2.584 2.630 

N-DECANE P10 2.501 3.485 3.488 

UNKNOWN DECANE'S U10 4.293 5.981 5.986 

N-UNDECANE P11 1.611 2.561 2.498 

UNKNOWN UNDECANE'S U11 2.733 4.343 4.242 

DODECANES C12'S 2.384 3.788 3.699 

TRIDECANES C13'S 1.531 2.634 2.550 

TETRADECANES C14'S 0.784 1.350 1.304 

PENTADECANES C15'S 0.329 0.672 0.640 

HEXADECANES C16'S 0.114 0.241 0.229 

HEPTADECANES C17'S 0.024 0.054 0.051 

OCTADECANES C18'S 0.008 0.018 0.017 

NONADECANES C19'S 0.002 0.006 0.006 

EISCOSANE+ C20'S 0.005 0.014 0.011 

TOTALS 100.000 100.000 100.000 

Page 6 
2a - GNB Old Well 072009 

****************************************************************************************** * Project Setup Information * ****************************************************************************************** Project File Flowsheet Selection Calculation Method Control Efficiency Known Separator Stream Entering Air Composition Filed Name Well Name Date 

: C:\Documents and Settings\ehodek\My Documents\Uintah Old Well : Oil Tank with Separator : RVP Distillation : 100.0% : High Pressure Oil : No : Greater Natural Buttes : Old Well : 2008.03.25 

****************************************************************************************** * Data Input * ****************************************************************************************** Separator Pressure Separator Temperature Ambient Pressure Ambient Temperature C10+ SG C10+ MW 

: 90.00[psig] : 78.00[F] : 14.70[psia] : 70.00[F] : 0.7400 : 159.67 

-- High Pressure Oil ---------------------------------------------------------------------No. 

Component mol %

 1 

H2S 0.0000

 2 

O2 0.0000

 3 

CO2 0.4190

 4 

N2 0.0000

 5 

C1 4.0438

 6 

C2 1.9669

 7 

C3 1.9609

 8 

i-C4 0.9410

 9 

n-C4 1.7049

 10 

i-C5 1.6679

 11 

n-C5 2.1989

 12 

C6 6.2227

 13 

C7 17.1271

 14 

C8 15.6182

 15 

C9 12.5804

 16 

C10+ 17.2661

 17 

Benzene 0.9069

 18 

Toluene 5.6567

 19 

E-Benzene 0.4490 

Page 1 
2a - GNB Old Well 072009

 20 

Xylenes 6.5727

 21 

n-C6 2.6969

 22 

224Trimethylp 0.0000 

-- Sales Oil -----------------------------------------------------------------------------Production Rate : 3[bbl/day]Days of Annual Operation : 365 [days/year]API Gravity : 61.28Reid Vapor Pressure : 7.25[psia]******************************************************************************************* Calculation Results *

******************************************************************************************-- Emission Summary ----------------------------------------------------------------------Item Uncontrolled Uncontrolled Controlled Controlled [ton/yr] 

[lb/hr] [ton/yr] [lb/hr] 

Total HAPs 0.080 0.018 0.013 0.003 Page 1---------------------------------------------------------------- E&P TANK Total HC 2.401 0.548 0.400 0.091 VOCs, C2+ 1.796 0.410 0.299 0.068 VOCs, C3+ 1.273 0.291 0.212 0.048 Uncontrolled Recovery Info. Vapor 

167.4000 x1E-3 [MSCFD] 

HC Vapor 

158.7100 x1E-3 [MSCFD] 

GOR 

55.80 [SCF/bbl] 

-- Emission Composition ------------------------------------------------------------------No Component Uncontrolled Uncontrolled Controlled Controlled [ton/yr] 

[lb/hr] [ton/yr] [lb/hr] 

1 H2S 0.000 0.000 0.000 0.000 2 O2 0.000 0.000 0.000 0.000 3 CO2 0.184 0.042 0.613 0.140 4 N2 0.000 0.000 0.000 0.000 5 C1 0.605 0.138 0.101 0.023 6 C2 0.522 0.119 0.087 0.020 7 C3 0.427 0.097 0.071 0.016 8 i-C4 0.133 0.030 0.022 0.005 9 n-C4 0.177 0.040 0.030 0.007 10 i-C5 0.090 0.021 0.015 0.003 11 n-C5 0.089 0.020 0.015 0.003 12 C6 0.106 0.024 0.018 0.004 13 C7 0.116 0.026 0.019 0.004 14 C8 0.040 0.009 0.007 0.002 15 C9 0.013 0.003 0.002 0.000 16 C10+ 0.003 0.001 0.001 0.000 

Page 2 
2a - GNB Old Well 072009 

17 Benzene 0.010 0.002 0.002 0.000 18 Toluene 0.022 0.005 0.004 0.001 19 E-Benzene 0.001 0.000 0.000 0.000 20 Xylenes 0.009 0.002 0.001 0.000 21 n-C6 0.037 0.008 0.006 0.001 

22 224Trimethylp 0.000 0.000 0.000 0.000 Total 

2.584 0.590 0.431 0.098 

-- Stream Data ---------------------------------------------------------------------------No. Component MW LP Oil Flash Oil Sale Oil Flash Gas W&S Gas Total 

 mol % 

mol % mol % mol % mol % mol % 

1 H2S 34.80 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 O2 32.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 CO2 44.01 0.3769 0.0840 0.0484 5.2604 4.3922 5.1884 N2 28.01 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 C1 16.04 3.0671 0.2776 0.0764 49.5796 16.1487 46.796 C2 30.07 1.8755 0.7128 0.5332 21.2616 24.7510 21.557 C3 44.10 1.9500 1.3882 1.2657 11.3178 19.5050 12.008 i-C4 58.12 0.9460 0.8468 0.8174 2.5996 5.4619 2.8389 n-C4 58.12 1.7176 1.6152 1.5774 3.4243 7.7374 3.78310 i-C5 72.15 1.6854 1.7044 1.6948 1.3689 3.6023 1.55511 n-C5 72.15 2.2232 2.2764 2.2705 1.3361 3.7528 1.53712 C6 86.16 6.2976 6.5962 6.6208 1.3189 4.3371 1.57013 C7 100.20 17.3395 18.3079 18.4224 1.1933 4.6814 1.484

14 C8 114.23 15.8140 16.7422 16.8634 0.3374 1.5895 0.441

15 C9 128.28 12.7386 13.4971 13.5994 0.0921 0.5165 0.127

16 C10+ 159.67 17.4836 18.5312 18.6751 0.0163 0.1260 0.025

17 Benzene 78.11 0.9180 0.9649 0.9696 0.1354 0.4661 0.163

18 Toluene 92.13 5.7273 6.0569 6.0982 0.2326 0.9761 0.294

19 E-Benzene 106.17 0.4546 0.4815 0.4851 0.0060 0.0296 0.007

20 Xylenes 106.17 6.6553 7.0499 7.1026 0.0756 0.3871 0.101

21 n-C6 86.18 2.7297 2.8668 2.8797 0.4440 1.5392 0.535

22 224Trimethylp 114.24 0.0000 0.0000 0.0000 0.0000 0.0000 0.000

MW 

105.65 110.15 110.68 30.68 47.36 32.07 

Stream Mole Ratio 

1.0000 0.9434 0.9361 0.0566 0.0051 0.061

Heating Value 

[BTU/SCF] 1659.60 2560.36 1734.

Gas Gravity 

[Gas/Air] 1.06 1.63 1.11 

Bubble Pt. @ 100F 

[psia] 115.65 19.44 11.71 

RVP @ 100F 

[psia] 29.56 9.23 7.25 

Page 2---------------------------------------------------------------- E&P TANK Spec. Gravity @ 100F 

0.679 0.684 0.685 

Page 3 
2b - GNB New Well 072009 

****************************************************************************************** * Project Setup Information * ****************************************************************************************** Project File Flowsheet Selection Calculation Method Control Efficiency Known Separator Stream Entering Air Composition Filed Name Well Name Date 

: C:\Documents and Settings\ehodek\My Documents\Uintah New Well : Oil Tank with Separator : RVP Distillation : 100.0% : High Pressure Oil : No : Greater Natural Buttes : Old Well : 2008.03.25 

****************************************************************************************** * Data Input * ****************************************************************************************** Separator Pressure Separator Temperature Ambient Pressure Ambient Temperature C10+ SG C10+ MW 

: 90.00[psig] : 78.00[F] : 14.70[psia] : 70.00[F] : 0.7400 : 159.67 

-- High Pressure Oil ---------------------------------------------------------------------No. 

Component mol %

 1 

H2S 0.0000

 2 

O2 0.0000

 3 

CO2 0.4190

 4 

N2 0.0000

 5 

C1 4.0438

 6 

C2 1.9669

 7 

C3 1.9609

 8 

i-C4 0.9410

 9 

n-C4 1.7049

 10 

i-C5 1.6679

 11 

n-C5 2.1989

 12 

C6 6.2227

 13 

C7 17.1271

 14 

C8 15.6182

 15 

C9 12.5804

 16 

C10+ 17.2661

 17 

Benzene 0.9069

 18 

Toluene 5.6567

 19 

E-Benzene 0.4490 

Page 1 
2b - GNB New Well 072009

 20 

Xylenes 6.5727

 21 

n-C6 2.6969

 22 

224Trimethylp 0.0000 

-- Sales Oil -----------------------------------------------------------------------------Production Rate : 10[bbl/day]Days of Annual Operation : 365 [days/year]API Gravity : 61.28Reid Vapor Pressure : 7.25[psia]******************************************************************************************* Calculation Results *

******************************************************************************************-- Emission Summary ----------------------------------------------------------------------Item Uncontrolled Uncontrolled Controlled Controlled [ton/yr] 

[lb/hr] [ton/yr] [lb/hr] 

Total HAPs 0.260 0.059 0.013 0.003 Page 1---------------------------------------------------------------- E&P TANK Total HC 8.002 1.827 0.400 0.091 VOCs, C2+ 5.985 1.366 0.299 0.068 VOCs, C3+ 4.244 0.969 0.212 0.048 Uncontrolled Recovery Info. Vapor 

557.9900 x1E-3 [MSCFD] 

HC Vapor 

529.0400 x1E-3 [MSCFD] 

GOR 

55.80 [SCF/bbl] 

-- Emission Composition ------------------------------------------------------------------No Component Uncontrolled Uncontrolled Controlled Controlled [ton/yr] 

[lb/hr] [ton/yr] [lb/hr] 

1 H2S 0.000 0.000 0.000 0.000 2 O2 0.000 0.000 0.000 0.000 3 CO2 0.613 0.140 0.613 0.140 4 N2 0.000 0.000 0.000 0.000 5 C1 2.017 0.461 0.101 0.023 6 C2 1.741 0.397 0.087 0.020 7 C3 1.422 0.325 0.071 0.016 8 i-C4 0.443 0.101 0.022 0.005 9 n-C4 0.591 0.135 0.030 0.007 10 i-C5 0.301 0.069 0.015 0.003 11 n-C5 0.298 0.068 0.015 0.003 12 C6 0.354 0.081 0.018 0.004 13 C7 0.387 0.088 0.019 0.004 14 C8 0.132 0.030 0.007 0.002 15 C9 0.042 0.010 0.002 0.000 16 C10+ 0.011 0.003 0.001 0.000 

Page 2 
2b - GNB New Well 072009 

17 Benzene 0.034 0.008 0.002 0.000 18 Toluene 0.073 0.017 0.004 0.001 19 E-Benzene 0.002 0.000 0.000 0.000 20 Xylenes 0.029 0.007 0.001 0.000 21 n-C6 0.124 0.028 0.006 0.001 

22 224Trimethylp 0.000 0.000 0.000 0.000 Total 

8.614 1.967 0.431 0.098 

-- Stream Data ---------------------------------------------------------------------------No. Component MW LP Oil Flash Oil Sale Oil Flash Gas W&S Gas Total 

 mol % 

mol % mol % mol % mol % mol % 

1 H2S 34.80 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 O2 32.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 CO2 44.01 0.3769 0.0840 0.0484 5.2604 4.3922 5.1884 N2 28.01 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 C1 16.04 3.0671 0.2776 0.0764 49.5796 16.1487 46.796 C2 30.07 1.8755 0.7128 0.5332 21.2616 24.7510 21.557 C3 44.10 1.9500 1.3882 1.2657 11.3178 19.5050 12.008 i-C4 58.12 0.9460 0.8468 0.8174 2.5996 5.4619 2.8389 n-C4 58.12 1.7176 1.6152 1.5774 3.4243 7.7374 3.78310 i-C5 72.15 1.6854 1.7044 1.6948 1.3689 3.6023 1.55511 n-C5 72.15 2.2232 2.2764 2.2705 1.3361 3.7528 1.53712 C6 86.16 6.2976 6.5962 6.6208 1.3189 4.3371 1.57013 C7 100.20 17.3395 18.3079 18.4224 1.1933 4.6814 1.484

14 C8 114.23 15.8140 16.7422 16.8634 0.3374 1.5895 0.441

15 C9 128.28 12.7386 13.4971 13.5994 0.0921 0.5165 0.127

16 C10+ 159.67 17.4836 18.5312 18.6751 0.0163 0.1260 0.025

17 Benzene 78.11 0.9180 0.9649 0.9696 0.1354 0.4661 0.163

18 Toluene 92.13 5.7273 6.0569 6.0982 0.2326 0.9761 0.294

19 E-Benzene 106.17 0.4546 0.4815 0.4851 0.0060 0.0296 0.007

20 Xylenes 106.17 6.6553 7.0499 7.1026 0.0756 0.3871 0.101

21 n-C6 86.18 2.7297 2.8668 2.8797 0.4440 1.5392 0.535

22 224Trimethylp 114.24 0.0000 0.0000 0.0000 0.0000 0.0000 0.000

MW 

105.65 110.15 110.68 30.68 47.36 32.07 

Stream Mole Ratio 

1.0000 0.9434 0.9361 0.0566 0.0051 0.061

Heating Value 

[BTU/SCF] 1659.60 2560.36 1734.

Gas Gravity 

[Gas/Air] 1.06 1.63 1.11 

Bubble Pt. @ 100F 

[psia] 115.65 19.44 11.71 

RVP @ 100F 

[psia] 29.56 9.23 7.25 

Page 2---------------------------------------------------------------- E&P TANK Spec. Gravity @ 100F 

0.679 0.684 0.685 

Page 3 

























 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supersedes LEHW0813-06

G3608 LE GAS PETROLEUM ENGINE 

1767-1823 bkW (2370-2445 bhp) 

TECHNICAL DATA 

G3608 LE Gas Petroleum Engine — 1000 rpm 

DM5561-03 DM5562-03 DM5136-03 DM8606-02 

Engine Power 

@ 100% Load 

@ 75% Load 

bkW (bhp) 

bkW (bhp) 

1767 (2370) 

1326 (1778) 

1879 (2520) 

1409 (1890) 

1823 (2445) 

1367 (1834) 

1767 (2370) 

1326 (1778) 

Engine Speed 

Max Altitude @ Rated Torque 

and 38°C (100°F) 

Speed Turndown @ Max 

Altitude, Rated Torque, 

and 38°C (100°F) 

rpm 

m (ft) 

% 

1000 

1219.2 (4000) 

20 

1000 

1219.2 (4000) 

20 

1000 

1219.2 (4000) 

20 

1000 

914.4 (3000) 

20 

SCAC Temperature °C (°F) 54 (130) 32 (90) 43 (110) 54 (130) 

Emissions* 

NOx 

CO 

CO2 

VOC** 

g/bkW-hr (g/bhp-hr) 

g/bkW-hr (g/bhp-hr) 

g/bkW-hr (g/bhp-hr) 

g/bkW-hr (g/bhp-hr) 

.94 (0.7) 

3.35 (2.5) 

589 (439) 

0.81 (0.6) 

.94 (0.7) 

3.4 (2.5) 

584 (436) 

0.76 (0.57) 

.94 (0.7) 

3.4 (2.5) 

587 (438) 

0.79 (0.59) 

.67 (0.5) 

3.7 (2.75) 

591 (441) 

0.85 (0.63) 

Fuel Consumption*** 

@ 100% Load 

@ 75% Load 

MJ/bkW-hr (Btu/bhp-hr) 

MJ/bkW-hr (Btu/bhp-hr) 

9.34 (6600) 

9.74 (6883) 

9.28 (6561) 

9.66 (6829) 

9.31 (6580) 

9.7 (6856) 

9.38 (6629) 

9.78 (6914) 

Heat Balance 

Heat Rejection to 

Jacket Water 

@ 100% Load 

@ 75% Load 

bkW (Btu/min) 

bkW (Btu/min) 

420 (23,918) 

364 (20,697) 

449 (25,555) 

388 (22,055) 

435 (24,751) 

376 (21,389) 

420 (23,911) 

366 (20,824) 

Heat Rejection to Aftercooler 

@ 100% Load 

@ 75% Load 

bkW (Btu/min) 

bkW (Btu/min) 

297 (16,916) 

139 (7898) 

394 (22,403) 

207 (11,778) 

344 (19,601) 

172 (9794) 

310 (17,633) 

145 (8279) 

Heat Rejection to Exhaust 

@ 100% Load 

@ 75% Load 

bkW (Btu/min) 

bkW (Btu/min) 

1783 (101,403) 

1437 (81,695) 

1792 (101,922) 

1443 (82,061) 

1789 (101,728) 

1441 (81,932) 

1790 (101,780) 

1442 (82,023) 

Exhaust System 

Exhaust Gas Flow Rate 

@ 100% Load 

@ 75% Load 

m3

/min (cfm) 

m3

/min (cfm) 

451.80 (15,955) 463.55 (16,370) 

359.68 (12,702) 368.23 (13,004) 

457.83 (16,168) 

364.10 (12,858) 

457.15 (16,144) 

363.93 (12,852) 

Exhaust Stack Temperature 

@ 100% Load 

@ 75% Load 

°C (°F) 

°C (°F) 

470 (878) 

492 (918) 

450 (841) 

469 (877) 

460 (859) 

480 (897) 

459 (857) 

480 (897) 

Intake System 

Air Inlet Flow Rate 

@ 100% Load 

@ 75% Load 

m3

/min (scfm) 

m3

/min (scfm) 

170.07 (6006) 

131.36 (4639) 

179.36 (6334) 

138.58 (4894) 

174.71 (6170) 

134.99 (4767) 

174.91 (6177) 

135.13 (4772) 

Gas Pressure kPag (psig) 295-324 

(42.8-47) 

295-324 

(42.8-47) 

295-324 

(42.8-47) 

295-324 

(42.8-47) 

*at 100% load and speed, all values are listed as not to exceed 

**Volatile organic compounds as defined in U.S. EPA 40 CFR 60, subpart JJJJ 

***ISO 3046/1 

LEHW0040-02 Page 3 of 4 
March 2012

Appendix C

Spatially Distributed Project Alternatives Emissions Inventories
Table C-1 Spatially Distributed Production and Drilling Emissions for the Proposed Action 

Total Planned Drilling Production and Operation Drilling and Completion Production an

336 10 3,339 2 13 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons pe

8S 20E 33 08S20E33 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

8S 20E 34 08S20E34 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

8S 20E 35 08S20E35 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

8S 20E 36 08S20E36 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

8S 21E 31 08S21E31 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

8S 21E 32 08S21E32 2 0.06 13 3.77 3.92 0.01 3.33 0.53 0.28 1.55 1.39 0.06 

8S 21E 33 08S21E33 2 0.06 20 3.77 3.92 0.01 3.33 0.53 0.28 2.38 2.14 0.09 

8S 21E 34 08S21E34 2 0.06 18 3.77 3.92 0.01 3.33 0.53 0.28 2.14 1.93 0.08 

8S 21E 35 08S21E35 2 0.06 12 3.77 3.92 0.01 3.33 0.53 0.28 1.43 1.28 0.05 

8S 21E 36 08S21E36 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

8S 22E 31 08S22E31 2 0.06 14 3.77 3.92 0.01 3.33 0.53 0.28 1.66 1.50 0.06 

8S 23E 33 08S23E33 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

8S 23E 34 08S23E34 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

8S 23E 35 08S23E35 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

9S 20E 1 09S20E01 2 0.06 9 3.77 3.92 0.01 3.33 0.53 0.28 1.07 0.96 0.04 

9S 20E 2 09S20E02 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

9S 20E 3 09S20E03 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

9S 20E 4 09S20E04 2 0.06 9 3.77 3.92 0.01 3.33 0.53 0.28 1.07 0.96 0.04 

9S 20E 9 09S20E09 2 0.06 12 3.77 3.92 0.01 3.33 0.53 0.28 1.43 1.28 0.05 

9S 20E 10 09S20E10 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 20E 11 09S20E11 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

9S 20E 12 09S20E12 2 0.06 18 3.77 3.92 0.01 3.33 0.53 0.28 2.14 1.93 0.08 

9S 20E 13 09S20E13 3 0.09 6 5.66 5.88 0.02 4.99 0.80 0.41 0.71 0.64 0.03 

9S 20E 14 09S20E14 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

9S 20E 15 09S20E15 2 0.06 16 1 3.77 3.92 0.01 3.33 0.53 0.28 8.18 2.59 0.14 

9S 20E 20 09S20E20 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

9S 20E 21 09S20E21 2 0.06 12 3.77 3.92 0.01 3.33 0.53 0.28 1.43 1.28 0.05 

9S 20E 22 09S20E22 2 0.06 19 3.77 3.92 0.01 3.33 0.53 0.28 2.26 2.03 0.08 

9S 20E 23 09S20E23 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 20E 24 09S20E24 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 20E 25 09S20E25 2 0.06 13 3.77 3.92 0.01 3.33 0.53 0.28 1.55 1.39 0.06 

9S 20E 26 09S20E26 2 0.06 21 3.77 3.92 0.01 3.33 0.53 0.28 2.50 2.25 0.09 

9S 20E 27 09S20E27 2 0.06 21 3.77 3.92 0.01 3.33 0.53 0.28 2.50 2.25 0.09 

9S 20E 28 09S20E28 - - - - - - - - - - - 

9S 20E 29 09S20E29 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

9S 20E 32 09S20E32 - - - - - - - - - - - 

9S 20E 33 09S20E33 - - - - - - - - - - - 

9S 20E 34 09S20E34 - - - - - - - - - - - 

9S 20E 35 09S20E35 2 0.06 21 3.77 3.92 0.01 3.33 0.53 0.28 2.50 2.25 0.09 

9S 20E 36 09S20E36 2 0.06 21 3.77 3.92 0.01 3.33 0.53 0.28 2.50 2.25 0.09 

9S 21E 1 09S21E01 2 0.06 13 1 3.77 3.92 0.01 3.33 0.53 0.28 7.82 2.27 0.12 

9S 21E 2 09S21E02 2 0.06 14 3.77 3.92 0.01 3.33 0.53 0.28 1.66 1.50 0.06 

9S 21E 3 09S21E03 2 0.06 15 3.77 3.92 0.01 3.33 0.53 0.28 1.78 1.61 0.06 

9S 21E 4 09S21E04 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 21E 5 09S21E05 2 0.06 13 3.77 3.92 0.01 3.33 0.53 0.28 1.55 1.39 0.06 

9S 21E 6 09S21E06 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

9S 21E 7 09S21E07 2 0.06 16 3.77 3.92 0.01 3.33 0.53 0.28 1.90 1.71 0.07 

9S 21E 8 09S21E08 2 0.06 17 3.77 3.92 0.01 3.33 0.53 0.28 2.02 1.82 0.07 

9S 21E 9 09S21E09 2 0.06 13 3.77 3.92 0.01 3.33 0.53 0.28 1.55 1.39 0.06 

9S 21E 10 09S21E10 2 0.06 18 3.77 3.92 0.01 3.33 0.53 0.28 2.14 1.93 0.08 

9S 21E 11 09S21E11 2 0.06 20 3.77 3.92 0.01 3.33 0.53 0.28 2.38 2.14 0.09 

9S 21E 12 09S21E12 2 0.06 21 3.77 3.92 0.01 3.33 0.53 0.28 2.50 2.25 0.09 
Table C-1 Spatially Distributed Production and Drilling Emissions for the Proposed Action 

Total Planned Drilling Production and Operation Drilling and Completion Production an

336 10 3,339 2 13 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons pe

9S 21E 13 09S21E13 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

9S 21E 14 09S21E14 2 0.06 12 3.77 3.92 0.01 3.33 0.53 0.28 1.43 1.28 0.05 

9S 21E 15 09S21E15 2 0.06 13 3.77 3.92 0.01 3.33 0.53 0.28 1.55 1.39 0.06 

9S 21E 16 09S21E16 2 0.06 15 3.77 3.92 0.01 3.33 0.53 0.28 1.78 1.61 0.06 

9S 21E 17 09S21E17 2 0.06 17 3.77 3.92 0.01 3.33 0.53 0.28 2.02 1.82 0.07 

9S 21E 18 09S21E18 2 0.06 15 3.77 3.92 0.01 3.33 0.53 0.28 1.78 1.61 0.06 

9S 21E 19 09S21E19 2 0.06 17 1 3.77 3.92 0.01 3.33 0.53 0.28 8.30 2.70 0.14 

9S 21E 20 09S21E20 2 0.06 17 3.77 3.92 0.01 3.33 0.53 0.28 2.02 1.82 0.07 

9S 21E 21 09S21E21 2 0.06 11 3.77 3.92 0.01 3.33 0.53 0.28 1.31 1.18 0.05 

9S 21E 22 09S21E22 2 0.06 16 3.77 3.92 0.01 3.33 0.53 0.28 1.90 1.71 0.07 

9S 21E 23 09S21E23 2 0.06 18 3.77 3.92 0.01 3.33 0.53 0.28 2.14 1.93 0.08 

9S 21E 24 09S21E24 2 0.06 21 3.77 3.92 0.01 3.33 0.53 0.28 2.50 2.25 0.09 

9S 21E 25 09S21E25 2 0.06 14 3.77 3.92 0.01 3.33 0.53 0.28 1.66 1.50 0.06 

9S 21E 26 09S21E26 2 0.06 13 3.77 3.92 0.01 3.33 0.53 0.28 1.55 1.39 0.06 

9S 21E 27 09S21E27 2 0.06 12 3.77 3.92 0.01 3.33 0.53 0.28 1.43 1.28 0.05 

9S 21E 28 09S21E28 2 0.06 9 3.77 3.92 0.01 3.33 0.53 0.28 1.07 0.96 0.04 

9S 21E 29 09S21E29 2 0.06 16 3.77 3.92 0.01 3.33 0.53 0.28 1.90 1.71 0.07 

9S 21E 30 09S21E30 2 0.06 17 3.77 3.92 0.01 3.33 0.53 0.28 2.02 1.82 0.07 

9S 21E 31 09S21E31 2 0.06 21 3.77 3.92 0.01 3.33 0.53 0.28 2.50 2.25 0.09 

9S 21E 32 09S21E32 2 0.06 20 3.77 3.92 0.01 3.33 0.53 0.28 2.38 2.14 0.09 

9S 21E 33 09S21E33 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

9S 21E 34 09S21E34 2 0.06 14 3.77 3.92 0.01 3.33 0.53 0.28 1.66 1.50 0.06 

9S 21E 35 09S21E35 2 0.06 14 1 1 3.77 3.92 0.01 3.33 0.53 0.28 7.94 2.38 0.13 

9S 21E 36 09S21E36 2 0.06 14 3.77 3.92 0.01 3.33 0.53 0.28 1.66 1.50 0.06 

9S 22E 6 09S22E06 2 0.06 11 3.77 3.92 0.01 3.33 0.53 0.28 1.31 1.18 0.05 

9S 22E 7 09S22E07 2 0.06 11 3.77 3.92 0.01 3.33 0.53 0.28 1.31 1.18 0.05 

9S 22E 15 09S22E15 - - - - - - - - - - - 

9S 22E 18 09S22E18 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

9S 22E 19 09S22E19 2 0.06 18 3.77 3.92 0.01 3.33 0.53 0.28 2.14 1.93 0.08 

9S 22E 20 09S22E20 2 0.06 10 3.77 3.92 0.01 3.33 0.53 0.28 1.19 1.07 0.04 

9S 22E 29 09S22E29 2 0.06 17 3.77 3.92 0.01 3.33 0.53 0.28 2.02 1.82 0.07 

9S 22E 30 09S22E30 2 0.06 15 1 3.77 3.92 0.01 3.33 0.53 0.28 8.06 2.48 0.13 

9S 22E 31 09S22E31 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

9S 22E 32 09S22E32 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 22E 33 09S22E33 1 0.03 10 1.89 1.96 0.01 1.66 0.27 0.14 1.19 1.07 0.04 

9S 22E 34 09S22E34 2 0.06 5 3.77 3.92 0.01 3.33 0.53 0.28 0.59 0.54 0.02 

9S 22E 35 09S22E35 1 0.03 12 1.89 1.96 0.01 1.66 0.27 0.14 1.43 1.28 0.05 

9S 22E 36 09S22E36 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

9S 23E 1 09S23E01 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 23E 2 09S23E02 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

9S 23E 3 09S23E03 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 23E 4 09S23E04 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

9S 23E 8 09S23E05 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

9S 23E 9 09S23E06 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

9S 23E 10 09S23E10 1 0.03 10 1.89 1.96 0.01 1.66 0.27 0.14 1.19 1.07 0.04 

9S 23E 11 09S23E11 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

9S 23E 12 09S23E12 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

9S 23E 13 09S23E13 1 0.03 11 1.89 1.96 0.01 1.66 0.27 0.14 1.31 1.18 0.05 

9S 23E 14 09S23E14 1 0.03 11 1.89 1.96 0.01 1.66 0.27 0.14 1.31 1.18 0.05 

9S 23E 15 09S23E15 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

9S 23E 23 09S23E23 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

9S 23E 24 09S23E24 1 0.03 11 1.89 1.96 0.01 1.66 0.27 0.14 1.31 1.18 0.05 
Table C-1 Spatially Distributed Production and Drilling Emissions for the Proposed Action 

Total Planned Drilling Production and Operation Drilling and Completion Production an

336 10 3,339 2 13 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons pe

9S 23E 25 09S23E25 - - - - - - - - - - - 

9S 23E 26 09S23E26 3 0.09 6 5.66 5.88 0.02 4.99 0.80 0.41 0.71 0.64 0.03 

9S 23E 31 09S23E31 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 

9S 23E 35 09S23E35 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

9S 23E 36 09S23E36 - - 15 - - - - - - 1.78 1.61 0.06 

9S 24E 21 09S24E21 - - - - - - - - - - - 

9S 24E 28 09S24E28 - - - - - - - - - - - 

9S 24E 29 09S24E29 2 0.06 6 3.77 3.92 0.01 3.33 0.53 0.28 0.71 0.64 0.03 

9S 24E 30 09S24E30 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

9S 24E 31 09S24E31 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

9S 24E 32 09S24E32 - - - - - - - - - - - 

9S 24E 33 09S24E33 - - - - - - - - - - - 

9S 24E 34 09S24E34 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

10S 20E 1 10S20E01 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

10S 20E 2 10S20E02 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

10S 20E 11 10S20E11 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

10S 20E 12 10S20E12 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 20E 13 10S20E13 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 20E 14 10S20E14 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

10S 20E 23 10S20E23 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

10S 20E 24 10S20E24 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

10S 20E 25 10S20E25 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

10S 20E 26 10S20E26 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

10S 20E 35 10S20E35 1 0.03 19 1.89 1.96 0.01 1.66 0.27 0.14 2.26 2.03 0.08 

10S 20E 36 10S20E36 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

10S 21E 1 10S21E01 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 21E 2 10S21E02 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 

10S 21E 3 10S21E03 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 

10S 21E 4 10S21E04 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 21E 5 10S21E05 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

10S 21E 6 10S21E06 2 0.06 17 3.77 3.92 0.01 3.33 0.53 0.28 2.02 1.82 0.07 

10S 21E 7 10S21E07 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

10S 21E 8 10S21E08 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

10S 21E 9 10S21E09 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 21E 10 10S21E10 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

10S 21E 11 10S21E11 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

10S 21E 12 10S21E12 1 0.03 19 1.89 1.96 0.01 1.66 0.27 0.14 2.26 2.03 0.08 

10S 21E 13 10S21E13 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 

10S 21E 14 10S21E14 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 

10S 21E 15 10S21E15 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 21E 16 10S21E16 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 21E 17 10S21E17 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 

10S 21E 18 10S21E18 1 0.03 19 1 1.89 1.96 0.01 1.66 0.27 0.14 8.54 2.91 0.15 

10S 21E 19 10S21E19 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

10S 21E 20 10S21E20 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 21E 21 10S21E21 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 21E 22 10S21E22 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

10S 21E 23 10S21E23 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 21E 24 10S21E24 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

10S 21E 25 10S21E25 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 21E 26 10S21E26 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 21E 27 10S21E27 3 0.09 6 5.66 5.88 0.02 4.99 0.80 0.41 0.71 0.64 0.03 
Table C-1 Spatially Distributed Production and Drilling Emissions for the Proposed Action 

Total Planned Drilling Production and Operation Drilling and Completion Production an

336 10 3,339 2 13 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons pe

10S 21E 28 10S21E28 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 21E 29 10S21E29 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 21E 30 10S21E30 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

10S 21E 31 10S21E31 2 0.06 15 1 3.77 3.92 0.01 3.33 0.53 0.28 8.06 2.48 0.13 

10S 21E 32 10S21E32 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 21E 33 10S21E33 - - - - - - - - - - - 

10S 21E 34 10S21E34 1 0.03 11 1.89 1.96 0.01 1.66 0.27 0.14 1.31 1.18 0.05 

10S 21E 35 10S21E35 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 21E 36 10S21E36 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 22E 1 10S22E01 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 

10S 22E 2 10S22E02 2 0.06 5 3.77 3.92 0.01 3.33 0.53 0.28 0.59 0.54 0.02 

10S 22E 3 10S22E03 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

10S 22E 4 10S22E04 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

10S 22E 5 10S22E05 1 0.03 12 1.89 1.96 0.01 1.66 0.27 0.14 1.43 1.28 0.05 

10S 22E 6 10S22E06 1 0.03 11 1.89 1.96 0.01 1.66 0.27 0.14 1.31 1.18 0.05 

10S 22E 7 10S22E07 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 22E 8 10S22E08 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

10S 22E 9 10S22E09 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 22E 10 10S22E10 1 0.03 10 1.89 1.96 0.01 1.66 0.27 0.14 1.19 1.07 0.04 

10S 22E 11 10S22E11 2 0.06 7 1 3.77 3.92 0.01 3.33 0.53 0.28 7.11 1.63 0.10 

10S 22E 12 10S22E12 1 0.03 10 1.89 1.96 0.01 1.66 0.27 0.14 1.19 1.07 0.04 

10S 22E 13 10S22E13 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

10S 22E 14 10S22E14 2 0.06 5 3.77 3.92 0.01 3.33 0.53 0.28 0.59 0.54 0.02 

10S 22E 15 10S22E15 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

10S 22E 16 10S22E16 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 22E 17 10S22E17 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

10S 22E 18 10S22E18 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

10S 22E 19 10S22E19 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 22E 20 10S22E20 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 22E 21 10S22E21 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

10S 22E 22 10S22E22 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

10S 22E 23 10S22E23 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 22E 24 10S22E24 3 0.09 5.66 5.88 0.02 4.99 0.80 0.41 - - - 

10S 22E 25 10S22E25 3 0.09 6 5.66 5.88 0.02 4.99 0.80 0.41 0.71 0.64 0.03 

10S 22E 26 10S22E26 1 0.03 21 1 1.89 1.96 0.01 1.66 0.27 0.14 8.77 3.13 0.16 

10S 22E 27 10S22E27 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

10S 22E 28 10S22E28 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

10S 22E 29 10S22E29 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

10S 22E 30 10S22E30 1 0.03 15 1 1 1.89 1.96 0.01 1.66 0.27 0.14 8.06 2.48 0.13 

10S 22E 31 10S22E31 1 0.03 19 1.89 1.96 0.01 1.66 0.27 0.14 2.26 2.03 0.08 

10S 22E 32 10S22E32 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 22E 33 10S22E33 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 22E 34 10S22E34 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 22E 35 10S22E35 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

10S 22E 36 10S22E36 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

10S 23E 1 10S23E01 1 0.03 16 1 1.89 1.96 0.01 1.66 0.27 0.14 8.18 2.59 0.14 

10S 23E 2 10S23E02 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 23E 3 10S23E03 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 23E 4 10S23E04 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 23E 5 10S23E05 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 23E 6 10S23E06 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 23E 7 10S23E07 1 0.03 14 1.89 1.96 0.01 1.66 0.27 0.14 1.66 1.50 0.06 
Table C-1 Spatially Distributed Production and Drilling Emissions for the Proposed Action 

Total Planned Drilling Production and Operation Drilling and Completion Production an

336 10 3,339 2 13 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons pe

10S 23E 8 10S23E08 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

10S 23E 9 10S23E09 1 0.03 17 1 1.89 1.96 0.01 1.66 0.27 0.14 8.30 2.70 0.14 

10S 23E 10 10S23E10 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 23E 11 10S23E11 1 0.03 17 1.89 1.96 0.01 1.66 0.27 0.14 2.02 1.82 0.07 

10S 23E 12 10S23E12 4 0.12 7.55 7.85 0.02 6.66 1.06 0.55 - - - 

10S 23E 13 10S23E13 - - - - - - - - - - - 

10S 23E 14 10S23E14 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

10S 23E 15 10S23E15 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

10S 23E 16 10S23E16 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

10S 23E 17 10S23E17 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

10S 23E 18 10S23E18 2 0.06 7 3.77 3.92 0.01 3.33 0.53 0.28 0.83 0.75 0.03 

10S 23E 22 10S23E22 - - - - - - - - - - - 

11S 21E 1 11S21E01 - - - - - - - - - - - 

11S 21E 2 11S21E02 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

11S 21E 3 11S21E03 1 0.03 20 1 1.89 1.96 0.01 1.66 0.27 0.14 8.66 3.02 0.15 

11S 21E 4 11S21E04 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

11S 21E 5 11S21E05 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

11S 21E 7 11S21E07 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

11S 21E 8 11S21E08 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

11S 21E 9 11S21E09 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

11S 21E 10 11S21E10 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

11S 21E 11 11S21E11 1 0.03 21 1.89 1.96 0.01 1.66 0.27 0.14 2.50 2.25 0.09 

11S 21E 12 11S21E12 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

11S 21E 13 11S21E13 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

11S 21E 14 11S21E14 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

11S 21E 15 11S21E15 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

11S 21E 16 11S21E16 1 0.03 15 1.89 1.96 0.01 1.66 0.27 0.14 1.78 1.61 0.06 

11S 21E 17 11S21E17 1 0.03 22 1.89 1.96 0.01 1.66 0.27 0.14 2.62 2.36 0.09 

11S 21E 18 11S21E18 1 0.03 11 1.89 1.96 0.01 1.66 0.27 0.14 1.31 1.18 0.05 

11S 21E 24 11S21E24 - - - - - - - - - - - 

11S 22E 2 11S22E02 1 0.03 18 1.89 1.96 0.01 1.66 0.27 0.14 2.14 1.93 0.08 

11S 22E 3 11S22E03 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

11S 22E 4 11S22E04 1 0.03 16 1.89 1.96 0.01 1.66 0.27 0.14 1.90 1.71 0.07 

11S 22E 5 11S22E05 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

11S 22E 6 11S22E06 1 0.03 11 1.89 1.96 0.01 1.66 0.27 0.14 1.31 1.18 0.05 

11S 22E 7 11S22E07 - - - - - - - - - - - 

11S 22E 8 11S22E08 - - - - - - - - - - - 

11S 22E 9 11S22E09 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

11S 22E 10 11S22E10 3 0.09 5 5.66 5.88 0.02 4.99 0.80 0.41 0.59 0.54 0.02 

11S 22E 15 11S22E15 - - - - - - - - - - - 

11S 22E 16 11S22E16 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

11S 22E 17 11S22E17 3 0.09 5 5.66 5.88 0.02 4.99 0.80 0.41 0.59 0.54 0.02 

11S 22E 18 11S22E18 1 0.03 20 1.89 1.96 0.01 1.66 0.27 0.14 2.38 2.14 0.09 

11S 22E 19 11S22E19 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

11S 22E 20 11S22E20 2 0.06 5 3.77 3.92 0.01 3.33 0.53 0.28 0.59 0.54 0.02 

11S 22E 21 11S22E21 1 0.03 13 1.89 1.96 0.01 1.66 0.27 0.14 1.55 1.39 0.06 

11S 22E 22 11S22E22 1 0.03 1.89 1.96 0.01 1.66 0.27 0.14 - - - 

11S 22E 23 11S22E23 - - - - - - - - - - - 

336 10.1 3339 2 13 633.8 659.1 1.8 559.3 89.2 46.2 478.7 368.9 15.2 
Table C-2 Spatially Distributed Production and Drilling Emissions for the Optimal Recovery Alternative 

Total Planned Drilling Production and Operation Drilling and Completion Production and O

672 20 12,774 5 23 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 P

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons per ye

8S 20E 33 08S20E33 2 0.06 57 3.77 3.92 0.01 3.33 0.53 0.28 6.78 6.10 0.24 

8S 20E 34 08S20E34 2 0.06 57 3.77 3.92 0.01 3.33 0.53 0.28 6.78 6.10 0.24 

8S 20E 35 08S20E35 2 0.06 56 3.77 3.92 0.01 3.33 0.53 0.28 6.66 6.00 0.24 

8S 20E 36 08S20E36 2 0.06 57 3.77 3.92 0.01 3.33 0.53 0.28 6.78 6.10 0.24 

8S 21E 31 08S21E31 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

8S 21E 32 08S21E32 4 0.12 45 7.55 7.85 0.02 6.66 1.06 0.55 5.35 4.82 0.19 

8S 21E 33 08S21E33 4 0.12 52 7.55 7.85 0.02 6.66 1.06 0.55 6.18 5.57 0.22 

8S 21E 34 08S21E34 4 0.12 49 7.55 7.85 0.02 6.66 1.06 0.55 5.83 5.25 0.21 

8S 21E 35 08S21E35 4 0.12 42 7.55 7.85 0.02 6.66 1.06 0.55 4.99 4.50 0.18 

8S 21E 36 08S21E36 4 0.12 41 7.55 7.85 0.02 6.66 1.06 0.55 4.88 4.39 0.18 8S 22E 31 08S22E31 4 0.12 45 7.55 7.85 0.02 6.66 1.06 0.55 5.35 4.82 0.19 8S 23E 33 08S23E33 2 0.06 62 3.77 3.92 0.01 3.33 0.53 0.28 7.37 6.64 0.27 

8S 23E 34 08S23E34 4 0.12 60 7.55 7.85 0.02 6.66 1.06 0.55 7.14 6.42 0.26 

8S 23E 35 08S23E35 4 0.12 57 7.55 7.85 0.02 6.66 1.06 0.55 6.78 6.10 0.24 

9S 20E 1 09S20E01 4 0.12 57 7.55 7.85 0.02 6.66 1.06 0.55 6.78 6.10 0.24 

9S 20E 2 09S20E02 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 9S 20E 3 09S20E03 2 0.06 44 3.77 3.92 0.01 3.33 0.53 0.28 5.23 4.71 0.19 9S 20E 4 09S20E04 4 0.12 48 7.55 7.85 0.02 6.66 1.06 0.55 5.71 5.14 0.21 9S 20E 9 09S20E09 4 0.12 56 7.55 7.85 0.02 6.66 1.06 0.55 6.66 6.00 0.24 

9S 20E 10 09S20E10 4 0.12 60 7.55 7.85 0.02 6.66 1.06 0.55 7.14 6.42 0.26 

9S 20E 11 09S20E11 2 0.06 62 1 3.77 3.92 0.01 3.33 0.53 0.28 13.65 7.52 0.33 

9S 20E 12 09S20E12 4 0.12 50 7.55 7.85 0.02 6.66 1.06 0.55 5.95 5.35 0.21 9S 20E 13 09S20E13 6 0.18 57 11.32 11.77 0.03 9.99 1.59 0.83 6.78 6.10 0.24 

9S 20E 14 09S20E14 4 0.12 58 7.55 7.85 0.02 6.66 1.06 0.55 6.90 6.21 0.25 

9S 20E 15 09S20E15 4 0.12 47 7.55 7.85 0.02 6.66 1.06 0.55 5.59 5.03 0.20 9S 20E 20 09S20E20 2 0.06 56 3.77 3.92 0.01 3.33 0.53 0.28 6.66 6.00 0.24 

9S 20E 21 09S20E21 4 0.12 56 7.55 7.85 0.02 6.66 1.06 0.55 6.66 6.00 0.24 

9S 20E 22 09S20E22 4 0.12 50 7.55 7.85 0.02 6.66 1.06 0.55 5.95 5.35 0.21 9S 20E 23 09S20E23 4 0.12 60 7.55 7.85 0.02 6.66 1.06 0.55 7.14 6.42 0.26 

9S 20E 24 09S20E24 4 0.12 59 7.55 7.85 0.02 6.66 1.06 0.55 7.02 6.32 0.25 

9S 20E 25 09S20E25 4 0.12 44 7.55 7.85 0.02 6.66 1.06 0.55 5.23 4.71 0.19 

9S 20E 26 09S20E26 4 0.12 53 7.55 7.85 0.02 6.66 1.06 0.55 6.30 5.67 0.23 

9S 20E 27 09S20E27 4 0.12 53 7.55 7.85 0.02 6.66 1.06 0.55 6.30 5.67 0.23 

9S 20E 28 09S20E28 - - 65 1 - - - - - - 14.01 7.84 0.35 

9S 20E 29 09S20E29 2 0.06 63 3.77 3.92 0.01 3.33 0.53 0.28 7.49 6.75 0.27 

9S 20E 32 09S20E32 - - 65 - - - - - - 7.73 6.96 0.28 

9S 20E 33 09S20E33 - - 65 - - - - - - 7.73 6.96 0.28 

9S 20E 34 09S20E34 - - 65 - - - - - - 7.73 6.96 0.28 

9S 20E 35 09S20E35 4 0.12 52 7.55 7.85 0.02 6.66 1.06 0.55 6.18 5.57 0.22 9S 20E 36 09S20E36 4 0.12 52 1 7.55 7.85 0.02 6.66 1.06 0.55 12.46 6.45 0.29 

9S 21E 1 09S21E01 4 0.12 37 1 7.55 7.85 0.02 6.66 1.06 0.55 10.68 4.84 0.23 

9S 21E 2 09S21E02 4 0.12 40 7.55 7.85 0.02 6.66 1.06 0.55 4.76 4.28 0.17 9S 21E 3 09S21E03 4 0.12 41 7.55 7.85 0.02 6.66 1.06 0.55 4.88 4.39 0.18 9S 21E 4 09S21E04 4 0.12 38 7.55 7.85 0.02 6.66 1.06 0.55 4.52 4.07 0.16 9S 21E 5 09S21E05 4 0.12 43 7.55 7.85 0.02 6.66 1.06 0.55 5.11 4.60 0.18 9S 21E 6 09S21E06 4 0.12 34 7.55 7.85 0.02 6.66 1.06 0.55 4.04 3.64 0.15 9S 21E 7 09S21E07 4 0.12 47 7.55 7.85 0.02 6.66 1.06 0.55 5.59 5.03 0.20 

9S 21E 8 09S21E08 4 0.12 48 7.55 7.85 0.02 6.66 1.06 0.55 5.71 5.14 0.21 9S 21E 9 09S21E09 4 0.12 45 1 7.55 7.85 0.02 6.66 1.06 0.55 11.63 5.70 0.26 9S 21E 10 09S21E10 4 0.12 49 7.55 7.85 0.02 6.66 1.06 0.55 5.83 5.25 0.21 

9S 21E 11 09S21E11 4 0.12 52 7.55 7.85 0.02 6.66 1.06 0.55 6.18 5.57 0.22 

9S 21E 12 09S21E12 4 0.12 52 7.55 7.85 0.02 6.66 1.06 0.55 6.18 5.57 0.22 

9S 21E 13 09S21E13 4 0.12 42 7.55 7.85 0.02 6.66 1.06 0.55 4.99 4.50 0.18 
Table C-2 Spatially Distributed Production and Drilling Emissions for the Optimal Recovery Alternative 

Total Planned Drilling Production and Operation Drilling and Completion Production and O

672 20 12,774 5 23 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 P

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons per ye

9S 21E 14 09S21E14 4 0.12 43 7.55 7.85 0.02 6.66 1.06 0.55 5.11 4.60 0.18 

9S 21E 15 09S21E15 4 0.12 44 7.55 7.85 0.02 6.66 1.06 0.55 5.23 4.71 0.19 

9S 21E 16 09S21E16 4 0.12 47 7.55 7.85 0.02 6.66 1.06 0.55 5.59 5.03 0.20 9S 21E 17 09S21E17 4 0.12 48 7.55 7.85 0.02 6.66 1.06 0.55 5.71 5.14 0.21 

9S 21E 18 09S21E18 4 0.12 46 7.55 7.85 0.02 6.66 1.06 0.55 5.47 4.93 0.20 

9S 21E 19 09S21E19 4 0.12 48 1 1 7.55 7.85 0.02 6.66 1.06 0.55 11.98 6.02 0.27 

9S 21E 20 09S21E20 4 0.12 49 7.55 7.85 0.02 6.66 1.06 0.55 5.83 5.25 0.21 

9S 21E 21 09S21E21 4 0.12 42 7.55 7.85 0.02 6.66 1.06 0.55 4.99 4.50 0.18 

9S 21E 22 09S21E22 4 0.12 48 7.55 7.85 0.02 6.66 1.06 0.55 5.71 5.14 0.21 

9S 21E 23 09S21E23 4 0.12 50 7.55 7.85 0.02 6.66 1.06 0.55 5.95 5.35 0.21 

9S 21E 24 09S21E24 4 0.12 53 1 7.55 7.85 0.02 6.66 1.06 0.55 12.58 6.55 0.29 

9S 21E 25 09S21E25 4 0.12 46 7.55 7.85 0.02 6.66 1.06 0.55 5.47 4.93 0.20 9S 21E 26 09S21E26 4 0.12 44 7.55 7.85 0.02 6.66 1.06 0.55 5.23 4.71 0.19 

9S 21E 27 09S21E27 4 0.12 44 7.55 7.85 0.02 6.66 1.06 0.55 5.23 4.71 0.19 9S 21E 28 09S21E28 4 0.12 41 7.55 7.85 0.02 6.66 1.06 0.55 4.88 4.39 0.18 

9S 21E 29 09S21E29 4 0.12 47 7.55 7.85 0.02 6.66 1.06 0.55 5.59 5.03 0.20 

9S 21E 30 09S21E30 4 0.12 48 7.55 7.85 0.02 6.66 1.06 0.55 5.71 5.14 0.21 

9S 21E 31 09S21E31 4 0.12 52 7.55 7.85 0.02 6.66 1.06 0.55 6.18 5.57 0.22 

9S 21E 32 09S21E32 4 0.12 52 7.55 7.85 0.02 6.66 1.06 0.55 6.18 5.57 0.22 

9S 21E 33 09S21E33 4 0.12 42 7.55 7.85 0.02 6.66 1.06 0.55 4.99 4.50 0.18 

9S 21E 34 09S21E34 4 0.12 46 7.55 7.85 0.02 6.66 1.06 0.55 5.47 4.93 0.20 

9S 21E 35 09S21E35 4 0.12 46 1 1 7.55 7.85 0.02 6.66 1.06 0.55 11.75 5.80 0.26 

9S 21E 36 09S21E36 4 0.12 44 7.55 7.85 0.02 6.66 1.06 0.55 5.23 4.71 0.19 

9S 22E 6 09S22E06 4 0.12 42 7.55 7.85 0.02 6.66 1.06 0.55 4.99 4.50 0.18 

9S 22E 7 09S22E07 4 0.12 39 7.55 7.85 0.02 6.66 1.06 0.55 4.64 4.18 0.17 

9S 22E 15 09S22E15 - - 5 - - - - - - 0.59 0.54 0.02 

9S 22E 18 09S22E18 4 0.12 38 7.55 7.85 0.02 6.66 1.06 0.55 4.52 4.07 0.16 9S 22E 19 09S22E19 4 0.12 50 7.55 7.85 0.02 6.66 1.06 0.55 5.95 5.35 0.21 9S 22E 20 09S22E20 4 0.12 38 7.55 7.85 0.02 6.66 1.06 0.55 4.52 4.07 0.16 9S 22E 29 09S22E29 4 0.12 48 7.55 7.85 0.02 6.66 1.06 0.55 5.71 5.14 0.21 9S 22E 30 09S22E30 4 0.12 46 7.55 7.85 0.02 6.66 1.06 0.55 5.47 4.93 0.20 

9S 22E 31 09S22E31 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

9S 22E 32 09S22E32 4 0.12 41 7.55 7.85 0.02 6.66 1.06 0.55 4.88 4.39 0.18 

9S 22E 33 09S22E33 2 0.06 42 3.77 3.92 0.01 3.33 0.53 0.28 4.99 4.50 0.18 

9S 22E 34 09S22E34 4 0.12 19 7.55 7.85 0.02 6.66 1.06 0.55 2.26 2.03 0.08 

9S 22E 35 09S22E35 2 0.06 39 3.77 3.92 0.01 3.33 0.53 0.28 4.64 4.18 0.17 

9S 22E 36 09S22E36 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

9S 23E 1 09S23E01 4 0.12 60 7.55 7.85 0.02 6.66 1.06 0.55 7.14 6.42 0.26 

9S 23E 2 09S23E02 2 0.06 62 3.77 3.92 0.01 3.33 0.53 0.28 7.37 6.64 0.27 

9S 23E 3 09S23E03 4 0.12 59 1 7.55 7.85 0.02 6.66 1.06 0.55 13.29 7.20 0.32 

9S 23E 4 09S23E04 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

9S 23E 8 09S23E05 2 0.06 63 3.77 3.92 0.01 3.33 0.53 0.28 7.49 6.75 0.27 

9S 23E 9 09S23E06 4 0.12 59 7.55 7.85 0.02 6.66 1.06 0.55 7.02 6.32 0.25 

9S 23E 10 09S23E10 2 0.06 45 3.77 3.92 0.01 3.33 0.53 0.28 5.35 4.82 0.19 

9S 23E 11 09S23E11 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 9S 23E 12 09S23E12 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

9S 23E 13 09S23E13 2 0.06 59 3.77 3.92 0.01 3.33 0.53 0.28 7.02 6.32 0.25 

9S 23E 14 09S23E14 2 0.06 59 3.77 3.92 0.01 3.33 0.53 0.28 7.02 6.32 0.25 

9S 23E 15 09S23E15 2 0.06 58 3.77 3.92 0.01 3.33 0.53 0.28 6.90 6.21 0.25 

9S 23E 23 09S23E23 2 0.06 56 3.77 3.92 0.01 3.33 0.53 0.28 6.66 6.00 0.24 

9S 23E 24 09S23E24 2 0.06 60 3.77 3.92 0.01 3.33 0.53 0.28 7.14 6.42 0.26 

9S 23E 25 09S23E25 - - 65 1 - - - - - - 14.01 7.84 0.35 

9S 23E 26 09S23E26 6 0.18 35 11.32 11.77 0.03 9.99 1.59 0.83 4.16 3.75 0.15 
Table C-2 Spatially Distributed Production and Drilling Emissions for the Optimal Recovery Alternative 

Total Planned Drilling Production and Operation Drilling and Completion Production and O

672 20 12,774 5 23 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 P

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons per ye

9S 23E 31 09S23E31 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

9S 23E 35 09S23E35 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

9S 23E 36 09S23E36 - - 49 - - - - - - 5.83 5.25 0.21 

9S 24E 21 09S24E21 - - 66 - - - - - - 7.85 7.07 0.28 

9S 24E 28 09S24E28 - - 65 - - - - - - 7.73 6.96 0.28 

9S 24E 29 09S24E29 4 0.12 59 7.55 7.85 0.02 6.66 1.06 0.55 7.02 6.32 0.25 

9S 24E 30 09S24E30 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

9S 24E 31 09S24E31 2 0.06 59 3.77 3.92 0.01 3.33 0.53 0.28 7.02 6.32 0.25 

9S 24E 32 09S24E32 - - 66 1 - - - - - - 14.13 7.95 0.35 

9S 24E 33 09S24E33 - - 66 - - - - - - 7.85 7.07 0.28 

9S 24E 34 09S24E34 2 0.06 63 3.77 3.92 0.01 3.33 0.53 0.28 7.49 6.75 0.27 

10S 20E 1 10S20E01 2 0.06 53 3.77 3.92 0.01 3.33 0.53 0.28 6.30 5.67 0.23 10S 20E 2 10S20E02 2 0.06 57 3.77 3.92 0.01 3.33 0.53 0.28 6.78 6.10 0.24 10S 20E 11 10S20E11 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 10S 20E 12 10S20E12 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 20E 13 10S20E13 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 20E 14 10S20E14 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 10S 20E 23 10S20E23 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

10S 20E 24 10S20E24 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

10S 20E 25 10S20E25 2 0.06 63 3.77 3.92 0.01 3.33 0.53 0.28 7.49 6.75 0.27 

10S 20E 26 10S20E26 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

10S 20E 35 10S20E35 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

10S 20E 36 10S20E36 2 0.06 53 3.77 3.92 0.01 3.33 0.53 0.28 6.30 5.67 0.23 

10S 21E 1 10S21E01 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

10S 21E 2 10S21E02 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 21E 3 10S21E03 2 0.06 45 3.77 3.92 0.01 3.33 0.53 0.28 5.35 4.82 0.19 

10S 21E 4 10S21E04 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 21E 5 10S21E05 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 21E 6 10S21E06 4 0.12 49 7.55 7.85 0.02 6.66 1.06 0.55 5.83 5.25 0.21 

10S 21E 7 10S21E07 2 0.06 55 1 3.77 3.92 0.01 3.33 0.53 0.28 12.82 6.77 0.30 

10S 21E 8 10S21E08 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

10S 21E 9 10S21E09 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 21E 10 10S21E10 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 21E 11 10S21E11 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 21E 12 10S21E12 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

10S 21E 13 10S21E13 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 21E 14 10S21E14 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 21E 15 10S21E15 2 0.06 47 1 3.77 3.92 0.01 3.33 0.53 0.28 11.87 5.91 0.27 

10S 21E 16 10S21E16 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

10S 21E 17 10S21E17 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 21E 18 10S21E18 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

10S 21E 19 10S21E19 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

10S 21E 20 10S21E20 2 0.06 58 3.77 3.92 0.01 3.33 0.53 0.28 6.90 6.21 0.25 

10S 21E 21 10S21E21 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 21E 22 10S21E22 2 0.06 56 3.77 3.92 0.01 3.33 0.53 0.28 6.66 6.00 0.24 

10S 21E 23 10S21E23 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 21E 24 10S21E24 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

10S 21E 25 10S21E25 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 21E 26 10S21E26 2 0.06 59 3.77 3.92 0.01 3.33 0.53 0.28 7.02 6.32 0.25 

10S 21E 27 10S21E27 6 0.18 58 11.32 11.77 0.03 9.99 1.59 0.83 6.90 6.21 0.25 

10S 21E 28 10S21E28 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

10S 21E 29 10S21E29 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

10S 21E 30 10S21E30 2 0.06 54 1 3.77 3.92 0.01 3.33 0.53 0.28 12.70 6.66 0.30 
Table C-2 Spatially Distributed Production and Drilling Emissions for the Optimal Recovery Alternative 

Total Planned Drilling Production and Operation Drilling and Completion Production and O

672 20 12,774 5 23 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 P

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons per ye

10S 21E 31 10S21E31 4 0.12 47 7.55 7.85 0.02 6.66 1.06 0.55 5.59 5.03 0.20 

10S 21E 32 10S21E32 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 21E 33 10S21E33 - - 65 - - - - - - 7.73 6.96 0.28 

10S 21E 34 10S21E34 2 0.06 60 3.77 3.92 0.01 3.33 0.53 0.28 7.14 6.42 0.26 

10S 21E 35 10S21E35 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 21E 36 10S21E36 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 22E 1 10S22E01 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 22E 2 10S22E02 4 0.12 20 7.55 7.85 0.02 6.66 1.06 0.55 2.38 2.14 0.09 

10S 22E 3 10S22E03 4 0.12 40 7.55 7.85 0.02 6.66 1.06 0.55 4.76 4.28 0.17 

10S 22E 4 10S22E04 4 0.12 11 7.55 7.85 0.02 6.66 1.06 0.55 1.31 1.18 0.05 

10S 22E 5 10S22E05 2 0.06 11 1 3.77 3.92 0.01 3.33 0.53 0.28 7.58 2.06 0.11 

10S 22E 6 10S22E06 2 0.06 43 3.77 3.92 0.01 3.33 0.53 0.28 5.11 4.60 0.18 

10S 22E 7 10S22E07 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 22E 8 10S22E08 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 22E 9 10S22E09 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 22E 10 10S22E10 2 0.06 42 3.77 3.92 0.01 3.33 0.53 0.28 4.99 4.50 0.18 

10S 22E 11 10S22E11 4 0.12 25 1 1 7.55 7.85 0.02 6.66 1.06 0.55 9.25 3.56 0.17 10S 22E 12 10S22E12 2 0.06 30 3.77 3.92 0.01 3.33 0.53 0.28 3.57 3.21 0.13 

10S 22E 13 10S22E13 2 0.06 33 3.77 3.92 0.01 3.33 0.53 0.28 3.92 3.53 0.14 

10S 22E 14 10S22E14 4 0.12 24 7.55 7.85 0.02 6.66 1.06 0.55 2.85 2.57 0.10 

10S 22E 15 10S22E15 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

10S 22E 16 10S22E16 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 22E 17 10S22E17 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

10S 22E 18 10S22E18 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

10S 22E 19 10S22E19 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 22E 20 10S22E20 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 22E 21 10S22E21 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

10S 22E 22 10S22E22 2 0.06 53 3.77 3.92 0.01 3.33 0.53 0.28 6.30 5.67 0.23 10S 22E 23 10S22E23 2 0.06 44 3.77 3.92 0.01 3.33 0.53 0.28 5.23 4.71 0.19 

10S 22E 24 10S22E24 6 0.18 22 11.32 11.77 0.03 9.99 1.59 0.83 2.62 2.36 0.09 10S 22E 25 10S22E25 6 0.18 57 11.32 11.77 0.03 9.99 1.59 0.83 6.78 6.10 0.24 

10S 22E 26 10S22E26 2 0.06 53 3.77 3.92 0.01 3.33 0.53 0.28 6.30 5.67 0.23 10S 22E 27 10S22E27 2 0.06 53 3.77 3.92 0.01 3.33 0.53 0.28 6.30 5.67 0.23 10S 22E 28 10S22E28 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 10S 22E 29 10S22E29 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

10S 22E 30 10S22E30 2 0.06 47 1 1 3.77 3.92 0.01 3.33 0.53 0.28 11.87 5.91 0.27 

10S 22E 31 10S22E31 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

10S 22E 32 10S22E32 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 22E 33 10S22E33 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 22E 34 10S22E34 2 0.06 58 1 3.77 3.92 0.01 3.33 0.53 0.28 13.17 7.09 0.32 

10S 22E 35 10S22E35 2 0.06 56 3.77 3.92 0.01 3.33 0.53 0.28 6.66 6.00 0.24 

10S 22E 36 10S22E36 2 0.06 51 3.77 3.92 0.01 3.33 0.53 0.28 6.07 5.46 0.22 

10S 23E 1 10S23E01 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

10S 23E 2 10S23E02 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 23E 3 10S23E03 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 23E 4 10S23E04 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 23E 5 10S23E05 2 0.06 47 3.77 3.92 0.01 3.33 0.53 0.28 5.59 5.03 0.20 

10S 23E 6 10S23E06 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 23E 7 10S23E07 2 0.06 46 3.77 3.92 0.01 3.33 0.53 0.28 5.47 4.93 0.20 

10S 23E 8 10S23E08 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

10S 23E 9 10S23E09 2 0.06 49 1 1 3.77 3.92 0.01 3.33 0.53 0.28 12.10 6.13 0.28 

10S 23E 10 10S23E10 2 0.06 50 3.77 3.92 0.01 3.33 0.53 0.28 5.95 5.35 0.21 

10S 23E 11 10S23E11 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 
Table C-2 Spatially Distributed Production and Drilling Emissions for the Optimal Recovery Alternative 

Total Planned Drilling Production and Operation Drilling and Completion Production and O

672 20 12,774 5 23 

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 P

TN RG SE Model ID 

Producing Wellbores 

Nonproducing Wells (above Water Tank Water Injection 

(number of sites) (tons per year) (tons per ye

10S 23E 12 10S23E12 8 0.24 26 15.09 15.69 0.04 13.32 2.12 1.10 3.09 2.78 0.11 10S 23E 13 10S23E13 - - 55 - - - - - - 6.54 5.89 0.24 

10S 23E 14 10S23E14 4 0.12 37 7.55 7.85 0.02 6.66 1.06 0.55 4.40 3.96 0.16 

10S 23E 15 10S23E15 2 0.06 44 3.77 3.92 0.01 3.33 0.53 0.28 5.23 4.71 0.19 

10S 23E 16 10S23E16 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

10S 23E 17 10S23E17 2 0.06 43 3.77 3.92 0.01 3.33 0.53 0.28 5.11 4.60 0.18 

10S 23E 18 10S23E18 4 0.12 30 7.55 7.85 0.02 6.66 1.06 0.55 3.57 3.21 0.13 

10S 23E 22 10S23E22 - - 55 - - - - - - 6.54 5.89 0.24 

11S 21E 1 11S21E01 - - 66 - - - - - - 7.85 7.07 0.28 

11S 21E 2 11S21E02 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

11S 21E 3 11S21E03 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

11S 21E 4 11S21E04 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

11S 21E 5 11S21E05 2 0.06 55 3.77 3.92 0.01 3.33 0.53 0.28 6.54 5.89 0.24 

11S 21E 7 11S21E07 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

11S 21E 8 11S21E08 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

11S 21E 9 11S21E09 2 0.06 54 1 3.77 3.92 0.01 3.33 0.53 0.28 12.70 6.66 0.30 11S 21E 10 11S21E10 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

11S 21E 11 11S21E11 2 0.06 54 3.77 3.92 0.01 3.33 0.53 0.28 6.42 5.78 0.23 

11S 21E 12 11S21E12 2 0.06 56 1 3.77 3.92 0.01 3.33 0.53 0.28 12.94 6.87 0.31 

11S 21E 13 11S21E13 2 0.06 57 3.77 3.92 0.01 3.33 0.53 0.28 6.78 6.10 0.24 

11S 21E 14 11S21E14 2 0.06 58 3.77 3.92 0.01 3.33 0.53 0.28 6.90 6.21 0.25 

11S 21E 15 11S21E15 2 0.06 57 3.77 3.92 0.01 3.33 0.53 0.28 6.78 6.10 0.24 

11S 21E 16 11S21E16 2 0.06 48 3.77 3.92 0.01 3.33 0.53 0.28 5.71 5.14 0.21 

11S 21E 17 11S21E17 2 0.06 55 3.77 3.92 0.01 3.33 0.53 0.28 6.54 5.89 0.24 

11S 21E 18 11S21E18 2 0.06 60 3.77 3.92 0.01 3.33 0.53 0.28 7.14 6.42 0.26 

11S 21E 24 11S21E24 - - 5 - - - - - - 0.59 0.54 0.02 

11S 22E 2 11S22E02 2 0.06 49 3.77 3.92 0.01 3.33 0.53 0.28 5.83 5.25 0.21 

11S 22E 3 11S22E03 2 0.06 56 3.77 3.92 0.01 3.33 0.53 0.28 6.66 6.00 0.24 

11S 22E 4 11S22E04 2 0.06 58 3.77 3.92 0.01 3.33 0.53 0.28 6.90 6.21 0.25 

11S 22E 5 11S22E05 2 0.06 56 3.77 3.92 0.01 3.33 0.53 0.28 6.66 6.00 0.24 

11S 22E 6 11S22E06 2 0.06 60 3.77 3.92 0.01 3.33 0.53 0.28 7.14 6.42 0.26 

11S 22E 7 11S22E07 - - 66 - - - - - - 7.85 7.07 0.28 

11S 22E 8 11S22E08 - - 66 1 - - - - - - 14.13 7.95 0.35 

11S 22E 9 11S22E09 2 0.06 62 3.77 3.92 0.01 3.33 0.53 0.28 7.37 6.64 0.27 

11S 22E 10 11S22E10 6 0.18 53 11.32 11.77 0.03 9.99 1.59 0.83 6.30 5.67 0.23 

11S 22E 15 11S22E15 - - 57 - - - - - - 6.78 6.10 0.24 

11S 22E 16 11S22E16 2 0.06 62 3.77 3.92 0.01 3.33 0.53 0.28 7.37 6.64 0.27 

11S 22E 17 11S22E17 6 0.18 56 11.32 11.77 0.03 9.99 1.59 0.83 6.66 6.00 0.24 

11S 22E 18 11S22E18 2 0.06 52 3.77 3.92 0.01 3.33 0.53 0.28 6.18 5.57 0.22 

11S 22E 19 11S22E19 2 0.06 59 3.77 3.92 0.01 3.33 0.53 0.28 7.02 6.32 0.25 

11S 22E 20 11S22E20 4 0.12 59 7.55 7.85 0.02 6.66 1.06 0.55 7.02 6.32 0.25 

11S 22E 21 11S22E21 2 0.06 59 3.77 3.92 0.01 3.33 0.53 0.28 7.02 6.32 0.25 

11S 22E 22 11S22E22 2 0.06 62 1 3.77 3.92 0.01 3.33 0.53 0.28 13.65 7.52 0.33 11S 22E 23 11S22E23 - - 62 - - - - - - 7.37 6.64 0.27 

672 20.2 12774 5 23 1,318.1 1,267.6 3.5 178.4 1,118.7 92.5 1,388.0 1,663.5 56.3 

1,4
March 2012

Appendix D

Project Alternatives Emissions Inputs to CALPUFF
5

101520253035404550556065707580

Table D-1 CALPUFF Model Inputs: 2018 Non-Project Point Sources Less Than 100 TPY 

Source_ID Grid Cell Assignment Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (

nog_le_pt1 0 38.4583 -113.0627 -1383.5843 -47.8729 1540.0 7.27 0.28 345.29 3.73 19.09684 2.02562 11.15479 3.42953 0.00000 0.0

nog_le_pt2 1 40.7386 -113.6436 -1387.1471 209.0673 1288.0 12.48 0.66 398.64 7.77 36.11201 0.04630 16.92711 0.00000 0.00000 0.0

nog_le_pt3 2 38.2268 -112.9523 -1378.6435 -74.7533 1705.0 3.05 0.01 295.37 0.00 2.95733 0.21102 2.66366 1.68486 0.04390 0.0

nog_le_pt4 3 38.3906 -112.9987 -1379.4398 -56.2156 1581.0 3.05 0.01 295.37 0.00 4.70366 0.25367 7.31878 7.08492 0.00924 2.3

nog_le_pt5 4 37.8257 -112.6223 -1357.9961 -123.4109 2743.0 5.90 0.40 394.48 3.80 21.16310 5.95129 5.00040 3.34623 0.06698 0.5nog_le_pt6 40.8117 -113.2086 -1349.8483 210.4710 1421.0 13.38 0.68 417.59 9.12 3.44743 0.23953 18.46028 12.09074 0.36660 2.2

nog_le_pt7 6 38.8500 -112.5041 -1328.5914 -13.5492 1459.0 17.22 2.59 763.15 0.30 34.88999 2.01203 0.09061 0.00496 0.00000 0.0

nog_le_pt8 7 38.6634 -112.2642 -1311.6782 -37.3715 2066.0 3.05 0.01 295.37 0.00 3.22934 1.38422 3.72104 3.49866 0.09907 0.0nog_le_pt9 8 38.6838 -112.1480 -1301.4117 -36.8180 1636.0 13.38 0.68 417.59 9.12 16.90804 0.36560 13.55786 0.29646 0.01456 0.0

nog_le_pt10 9 39.5688 -112.4011 -1306.4453 63.2883 1477.0 3.05 0.01 295.37 0.00 6.92606 0.68877 6.28284 1.77134 0.00264 0.0

nog_le_pt11 40.4719 -112.5240 -1299.7923 163.4768 1753.0 11.93 0.59 400.48 7.84 0.30280 0.02523 1.61985 0.39528 0.00431 0.0

nog_le_pt12 11 40.6878 -112.5288 -1296.1296 187.0775 1278.0 14.82 1.12 377.40 7.20 9.36371 0.06370 44.90778 3.45246 0.00000 0.0

nog_le_pt13 12 40.7508 -112.6588 -1305.6782 195.8048 1279.0 12.81 0.93 340.33 10.46 19.46001 1.87297 1.06768 32.58972 0.24741 0.0

nog_le_pt14 13 38.7152 -112.0226 -1290.1656 -35.1818 2050.0 3.05 0.01 295.37 0.00 0.87491 0.08058 1.88775 0.65648 0.02389 0.0

nog_le_pt15 14 40.3209 -112.3173 -1285.4526 144.0764 2024.0 20.53 1.03 425.56 13.33 62.26067 22.87453 1.06810 5.32947 1.11692 0.6

nog_le_pt16 40.4685 -112.3604 -1286.2891 160.7784 2283.0 3.05 0.01 295.37 0.00 3.56871 0.96701 5.07655 3.10125 0.15165 0.1

nog_le_pt17 16 40.5407 -112.3584 -1284.7800 168.6218 1494.0 7.96 0.35 374.55 5.56 62.61010 12.37046 7.68350 10.09331 0.50149 0.8nog_le_pt18 17 38.8578 -111.9539 -1281.7362 -20.6007 1950.0 11.05 0.57 413.61 9.17 18.06734 0.12695 43.26303 3.83874 0.03109 0.2

nog_le_pt19 18 40.0567 -112.1684 -1277.9276 113.1689 2070.0 45.72 5.03 349.82 8.55 27.39982 0.90002 9.49986 0.00000 0.00000 0.0

nog_le_pt20 19 40.6325 -112.2846 -1276.9652 177.5913 1707.0 3.05 0.01 295.37 0.00 20.95057 22.17591 3.91799 8.51916 0.08232 3.3

nog_le_pt21 41.1200 -112.4327 -1280.1055 232.8352 1265.0 13.38 0.68 417.59 9.12 0.51985 0.00032 3.89660 0.00160 0.00000 0.0

nog_le_pt22 21 37.8300 -111.6020 -1270.0203 -137.6948 2072.0 18.90 0.87 699.82 9.53 3.49393 0.00000 3.15634 8.40559 1.17680 3.2nog_le_pt23 22 39.0506 -111.8668 -1270.8657 -0.7927 1566.0 12.90 0.68 412.15 13.89 1.10877 0.65060 10.56129 4.73127 0.09760 0.1

nog_le_pt24 23 39.1492 -111.8132 -1264.5553 9.2165 1706.0 13.38 0.68 417.59 9.12 16.13074 4.20018 4.94954 11.54098 0.20705 1.7

nog_le_pt25 24 40.1559 -112.0282 -1264.4184 122.0268 1577.0 13.88 2.14 689.98 2.17 50.92652 2.37346 9.24489 5.05232 0.02296 0.3

nog_le_pt26 40.2833 -112.0165 -1261.1255 135.7613 1785.0 3.05 0.01 295.37 0.00 14.92558 0.00000 0.00000 0.00181 0.00000 0.0

nog_le_pt27 26 40.5110 -112.0916 -1263.2118 161.6426 1567.0 5.33 0.41 657.04 1.83 0.13473 0.00000 0.00040 0.00000 0.00000 0.0

nog_le_pt28 27 40.5970 -112.1179 -1263.8177 171.3892 1651.0 10.09 0.47 378.70 6.22 10.67427 7.85102 22.04003 27.77132 0.16235 1.4

nog_le_pt29 28 40.7263 -112.1579 -1264.7561 186.0496 1342.0 7.76 0.32 351.15 4.16 21.97855 2.77820 15.99665 8.80740 0.92392 0.4nog_le_pt30 29 39.8504 -111.8205 -1252.5846 85.8221 2804.0 3.05 0.01 295.37 0.00 3.68383 0.26612 3.85066 2.14783 0.13299 0.0

nog_le_pt31 39.9720 -111.8255 -1250.8195 99.1590 1554.0 13.38 0.68 417.59 9.12 11.28471 11.90083 16.14501 0.00000 0.00000 0.0

nog_le_pt32 31 40.4415 -111.9214 -1250.3510 151.7067 1645.0 9.12 0.41 367.52 5.38 93.79752 26.90185 91.59364 52.04833 0.33812 3.4

nog_le_pt33 32 40.5623 -112.0527 -1259.0500 166.6989 1491.0 13.38 0.68 417.59 9.12 0.00220 0.00000 0.39195 20.95693 0.28278 1.2

nog_le_pt34 33 40.6402 -112.0380 -1256.4124 174.9939 1419.0 17.91 1.39 476.16 12.17 162.54536 4.79788 86.84732 30.59133 0.10917 2.8

nog_le_pt35 34 40.7575 -111.9953 -1250.7461 187.2030 1295.0 9.62 0.57 388.60 6.75 54.39266 1.94743 25.25487 24.67782 0.65512 8.7

nog_le_pt36 40.8353 -111.9878 -1248.7133 195.5891 1302.0 3.05 0.01 295.37 0.00 2.51565 0.14382 0.01009 0.14382 0.05322 0.0

nog_le_pt37 36 41.0320 -112.0275 -1248.4089 217.5986 1315.0 3.05 0.01 295.37 0.00 14.26787 1.27971 15.01811 5.22182 0.01932 0.2nog_le_pt38 37 41.1569 -112.1548 -1256.5928 232.9815 1283.0 13.38 0.68 417.59 9.12 4.73332 0.61608 15.70054 6.48112 0.01584 0.4

nog_le_pt39 38 40.0541 -111.7284 -1241.2344 106.7867 1405.0 8.70 0.30 480.42 11.73 7.91541 0.02805 3.14261 32.11606 3.04013 14.8

nog_le_pt40 39 40.0982 -111.6757 -1236.0477 110.8815 1419.0 3.05 0.01 295.37 0.00 24.64955 15.53090 6.97662 3.09484 0.22828 0.1

nog_le_pt41 40.2231 -111.7192 -1237.4520 125.1057 1388.0 13.38 0.68 417.59 9.12 2.28388 0.00825 0.01778 0.00000 0.00000 0.0

nog_le_pt42 41 40.3096 -111.7664 -1239.8376 135.1896 1426.0 9.88 0.62 387.82 9.04 30.10829 14.33700 69.98156 22.30456 0.54769 2.2

nog_le_pt43 42 40.4245 -111.8313 -1243.1738 148.6155 1502.0 11.49 0.82 918.52 12.03 52.07647 5.11629 25.10209 7.32238 0.06517 0.2

nog_le_pt44 43 40.5526 -111.8702 -1244.0973 163.1271 1524.0 12.60 0.63 408.41 8.43 5.47736 0.00023 56.88028 5.97472 0.02077 0.2

nog_le_pt45 44 40.6583 -111.8724 -1242.3750 174.6922 1358.0 9.40 0.57 447.34 10.38 136.35460 7.36807 70.24726 31.63198 4.67583 3.8

nog_le_pt46 40.7454 -111.9012 -1243.1865 184.5914 1393.0 10.87 0.57 436.34 11.87 242.44248 9.74612 123.05599 37.00526 1.29125 20.1

nog_le_pt47 46 40.8444 -111.9223 -1243.1409 195.6841 1645.0 7.47 0.66 355.73 3.51 163.98132 38.46965 45.18932 20.63693 0.59227 1.4

nog_le_pt48 47 40.9768 -111.8934 -1238.3653 209.7396 2444.0 12.99 0.65 412.94 8.77 4.70620 0.31541 6.57664 16.62045 0.01216 0.6

nog_le_pt49 48 41.1031 -111.9432 -1240.1814 224.2038 1997.0 12.69 1.01 432.57 7.42 71.18001 0.46869 102.97054 53.39824 0.45185 2.1

nog_le_pt50 49 41.2009 -111.9862 -1241.9415 235.4653 1465.0 11.61 0.55 389.62 9.20 28.03898 1.60940 128.98722 12.46147 0.35310 2.4nog_le_pt51 38.9153 -111.4163 -1235.0473 -21.7701 2562.0 13.38 0.68 417.59 9.12 0.06974 0.00076 21.58962 1.14799 0.00195 0.0

nog_le_pt52 51 39.4742 -111.5189 -1233.9314 40.6389 1886.0 3.05 0.01 295.37 0.00 0.21873 0.02302 0.77550 0.32189 0.01790 0.0

nog_le_pt53 52 40.0614 -111.6006 -1230.4281 105.8455 2056.0 11.09 0.52 351.26 6.68 81.15210 3.26948 27.94461 11.34760 0.73435 0.2

nog_le_pt54 53 40.1447 -111.6318 -1231.5579 115.3611 1461.0 13.37 0.71 462.39 14.50 127.94882 2.06231 23.28168 4.01821 0.10408 0.3

nog_le_pt55 54 40.2262 -111.6503 -1231.6549 124.5080 2316.0 11.59 0.55 404.87 7.59 6.38720 0.65369 2.69260 13.00423 0.82455 3.9

nog_le_pt56 40.7649 -111.7728 -1232.2201 184.9710 2016.0 10.56 0.53 429.73 7.15 15.41160 1.26289 8.63625 2.96164 0.51584 0.1

nog_le_pt57 56 40.8489 -111.6979 -1224.5310 193.1286 2560.0 11.80 0.80 462.20 12.49 8.67847 2.41278 0.03600 0.06335 0.00000 0.0

nog_le_pt58 57 41.2168 -111.8600 -1231.2904 235.4836 1890.0 3.05 0.01 295.37 0.00 1.08701 0.08524 0.17076 0.15270 0.01223 0.0nog_le_pt59 58 39.5256 -111.4071 -1223.6126 44.7388 2584.0 3.05 0.01 295.37 0.00 12.16352 0.93878 11.05073 21.53432 0.14867 0.0

nog_le_pt60 59 40.5931 -111.6117 -1221.9415 164.0405 3149.0 8.04 0.33 418.05 9.12 1.99983 0.06582 0.22722 0.00000 0.00000 0.0nog_le_pt61 40.6640 -111.5086 -1212.1464 170.4015 2255.0 3.05 0.01 295.37 0.00 1.94552 0.18419 6.09602 2.84241 0.16167 0.1

nog_le_pt62 61 41.0471 -111.6282 -1215.2603 213.8345 2059.0 3.05 0.01 295.37 0.00 14.87180 1.59303 4.85749 3.24063 0.73241 0.2

nog_le_pt63 62 41.0898 -111.7286 -1222.7660 219.8438 2073.0 3.05 0.01 295.37 0.00 7.57421 0.74686 2.41519 1.01466 0.03511 0.0

nog_le_pt64 63 39.3305 -111.1239 -1203.0952 19.6506 2796.0 3.14 0.02 295.89 0.19 46.42800 4.97444 28.44862 10.83058 0.01409 0.0

nog_le_pt65 64 39.6842 -111.2018 -1203.5900 59.3171 2804.0 13.38 0.68 417.59 9.12 4.19082 0.03938 0.55446 0.00273 0.00001 0.0

nog_le_pt66 40.4618 -111.4287 -1209.0633 147.2556 1910.0 12.28 0.61 404.62 8.15 0.74924 0.05601 6.90209 2.89176 0.09148 0.0

nog_le_pt67 66 40.6334 -111.4847 -1210.7038 166.7412 2161.0 3.05 0.01 295.37 0.00 12.66155 1.31749 0.07713 1.16850 0.86300 0.2

nog_le_pt68 67 40.6823 -111.4657 -1208.2718 171.8287 2194.0 13.38 0.68 417.59 9.12 0.41639 0.00000 30.14883 8.07220 0.08747 0.5

nog_le_pt69 68 39.1750 -111.0405 -1198.6937 1.5611 1706.0 10.79 0.63 378.77 10.96 2.93365 0.31887 22.44446 2.33390 0.01971 0.1

nog_le_pt70 69 39.4081 -111.0961 -1199.4207 27.7601 2683.0 3.05 0.01 295.37 0.00 8.37384 1.03066 9.29941 2.04459 0.11175 0.0

nog_le_pt71 39.5274 -111.0318 -1191.9644 39.9475 2194.0 3.05 0.01 295.37 0.00 26.65440 4.78340 22.87423 5.45608 0.05483 0.3

nog_le_pt72 71 39.6936 -111.0494 -1190.6178 58.3365 2682.0 13.38 0.68 417.59 9.12 0.00000 0.00000 1.13363 0.64760 0.00819 0.0

nog_le_pt73 72 40.6053 -111.2872 -1194.8195 161.0580 2255.0 3.05 0.01 295.37 0.00 7.22956 0.69073 0.99381 1.11485 0.48648 0.1

nog_le_pt74 73 40.7310 -111.3220 -1195.5236 175.2476 2166.0 4.33 0.15 417.59 9.12 20.50424 6.02907 0.16230 0.67148 0.00944 0.0

nog_le_pt75 74 40.8432 -111.3915 -1199.3193 188.4200 2255.0 3.05 0.01 295.37 0.00 14.69751 1.00213 6.29281 2.93916 0.74218 0.2

nog_le_pt76 40.9220 -111.4037 -1198.9516 197.1889 1889.0 3.05 0.01 295.37 0.00 1.32494 0.10192 2.08551 1.96576 0.00000 0.0

nog_le_pt77 76 39.2160 -110.8073 -1178.2531 2.9916 2073.0 3.05 0.01 295.37 0.00 0.17268 0.01151 0.96469 0.38353 0.02043 0.0

nog_le_pt78 77 39.5514 -110.8743 -1178.2864 40.5160 1768.0 3.05 0.01 295.37 0.00 4.52640 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt79 78 39.6562 -110.9001 -1178.6948 52.3035 1830.0 5.49 0.31 415.05 10.17 34.88577 1.30118 23.05331 8.45235 0.11722 0.4

nog_le_pt80 79 40.8914 -111.1922 -1182.0175 191.0750 2444.0 8.27 0.62 496.96 0.30 87.07794 0.00000 0.00379 0.17350 0.00000 0.1nog_le_pt81 39.5170 -110.7673 -1169.8432 35.3739 1694.0 3.05 0.01 295.37 0.00 23.25214 1.53059 31.77505 12.20457 0.15138 0.6

nog_le_pt82 81 39.5912 -110.8024 -1171.5615 43.9363 1726.0 3.05 0.01 295.37 0.00 0.48471 0.05102 0.06881 0.04587 0.00001 0.0
Table D-1 CALPUFF Model Inputs: 2018 Non-Project Point Sources Less Than 100 TPY 

Source_ID Grid Cell Assignment Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (

nog_le_pt83 82 39.6508 -110.8328 -1173.1227 50.8426 1945.0 5.08 0.14 446.69 0.33 81.39299 2.40149 43.45291 18.45498 0.03994 0.2

nog_le_pt84 83 39.8028 -110.8586 -1172.7406 67.7882 2288.0 3.05 0.01 295.37 0.00 13.72834 7.96077 0.68932 0.59721 0.21540 0.0

nog_le_pt85 84 40.9211 -111.0459 -1169.4246 192.4282 2852.0 3.05 0.01 295.37 0.00 48.41339 0.00000 3.20787 0.55440 0.00000 0.5nog_le_pt86 85 41.0576 -111.0695 -1169.0452 207.6524 2316.0 3.96 0.11 358.62 6.05 7.24009 0.00000 0.00725 5.29327 0.00000 5.2nog_le_pt87 86 41.1880 -111.0950 -1168.9183 222.2349 2195.0 12.19 0.63 418.71 8.37 0.00000 0.00000 0.00066 0.00315 0.00000 0.0

nog_le_pt88 87 39.5258 -110.6858 -1162.8246 35.2899 1768.0 3.05 0.01 295.37 0.00 0.90254 0.02302 0.55733 0.33421 0.01069 0.0

nog_le_pt89 88 39.7028 -110.7280 -1163.4376 55.1791 2438.0 3.05 0.01 295.37 0.00 6.61393 0.43367 3.73822 1.22592 0.00457 0.0

nog_le_pt90 89 39.6600 -110.5830 -1151.9458 48.6527 2410.0 13.38 0.68 417.59 9.12 0.00198 1.49570 5.15650 0.00745 0.00006 0.0

nog_le_pt91 90 41.1369 -110.8651 -1150.8610 213.7136 2222.0 17.07 1.59 792.24 16.17 43.66244 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt92 91 41.3128 -110.8698 -1148.2892 233.0095 2318.0 12.70 1.15 460.99 23.28 69.52669 0.07582 0.02655 0.12686 0.00000 0.0

nog_le_pt93 92 40.3183 -110.3947 -1125.4022 118.2893 1990.0 9.12 0.30 697.14 21.13 19.88070 0.00000 0.00190 1.27024 0.00000 1.2

nog_le_pt94 93 40.3723 -110.3430 -1120.2160 123.5582 2003.0 3.05 0.01 295.37 0.00 9.07244 0.02236 0.00576 0.02754 0.00000 0.0

nog_le_pt95 94 41.2873 -110.5468 -1122.1676 226.1850 2262.0 12.52 0.97 585.04 4.25 8.30523 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt96 95 37.2646 -109.6232 -1107.7676 -225.4246 1465.0 3.05 0.01 295.37 0.00 12.58531 1.25846 3.13699 2.44231 0.05889 0.0

nog_le_pt97 96 38.6250 -109.9419 -1114.1952 -72.5643 1584.0 13.38 0.68 417.59 9.12 0.49559 0.00000 0.00000 0.02351 0.00000 0.0nog_le_pt98 97 38.6358 -109.9169 -1111.8883 -71.6884 1584.0 13.38 0.68 417.59 9.12 4.90209 0.00000 0.00000 0.10578 0.00000 0.0nog_le_pt99 98 40.2998 -110.2480 -1113.4618 114.4582 1829.0 3.05 0.01 295.37 0.00 6.63831 9.07751 0.66884 0.46011 0.00046 0.0nog_le_pt100 99 40.3553 -110.2461 -1112.4117 120.5078 1891.0 9.47 0.38 661.89 27.02 87.07277 0.00000 0.76377 6.90413 0.00000 6.9

nog_le_pt101 100 40.9633 -110.3091 -1107.8508 187.8121 2926.0 4.31 0.26 638.43 26.97 70.49806 0.07290 0.04244 0.06496 0.00000 0.0

nog_le_pt102 101 38.5219 -109.7519 -1099.5404 -86.1648 1829.0 13.38 0.68 417.59 9.12 5.86003 0.00000 0.00000 0.04813 0.00000 0.0

nog_le_pt103 102 38.5988 -109.8060 -1102.9801 -77.0901 1707.0 13.38 0.68 417.59 9.12 5.69537 0.00000 0.00000 0.05877 0.00000 0.0

nog_le_pt104 103 40.0726 -110.0718 -1102.3573 87.4474 1627.0 3.05 0.01 295.37 0.00 36.22370 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt105 104 40.3052 -109.9953 -1092.2843 111.9825 1569.0 3.05 0.01 295.37 0.00 0.67044 0.00000 0.01928 0.05783 0.00202 0.0nog_le_pt106 105 40.3833 -110.0833 -1098.3906 121.5918 1727.0 8.61 0.33 659.89 18.19 99.39395 0.00000 0.01983 0.06441 0.00000 0.0

nog_le_pt107 106 41.0163 -110.2705 -1103.8075 193.1432 2545.0 6.60 0.57 526.62 11.85 36.18684 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt108 107 41.1450 -110.1630 -1092.8736 205.9324 2560.0 9.20 0.61 596.48 59.89 25.70655 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt109 108 37.5708 -109.4780 -1090.4700 -193.6330 1767.0 7.55 0.27 331.59 5.09 23.01827 2.31605 0.00000 1.96944 0.00000 0.2

nog_le_pt110 109 37.6281 -109.3761 -1080.7598 -188.5718 1877.0 3.05 0.01 295.37 0.00 1.87714 0.01458 0.00104 0.79372 0.00000 0.7

nog_le_pt111 110 38.6039 -109.5838 -1083.8878 -79.2052 1463.0 15.55 0.69 386.67 9.20 13.21351 0.08026 5.77052 15.69657 0.00112 0.0

nog_le_pt112 111 38.9556 -109.7311 -1091.0626 -38.9317 1584.0 3.05 0.01 295.37 0.00 37.40557 8.80698 0.09368 0.14833 0.00000 0.0

nog_le_pt113 112 41.3958 -110.0924 -1083.0684 232.5490 2136.0 11.44 1.03 508.62 22.58 40.58697 1.34138 0.00000 0.00000 0.00000 0.0

nog_le_pt114 113 37.2984 -109.2635 -1075.8933 -226.0421 1529.0 3.05 0.01 295.37 0.00 11.12499 33.40296 0.09004 0.00000 0.00000 0.0

nog_le_pt115 114 37.4678 -109.3162 -1077.9566 -206.8503 1596.0 3.05 0.01 295.37 0.00 15.33286 0.02916 0.00000 0.01413 0.00109 0.0

nog_le_pt116 115 37.8699 -109.3420 -1074.1795 -162.4805 2089.0 3.05 0.01 295.37 0.00 0.15769 0.03079 0.09753 0.16457 0.01308 0.0

nog_le_pt117 116 38.4834 -109.4572 -1074.8727 -93.9066 1767.0 3.05 0.01 295.37 0.00 21.55289 9.87077 2.34893 0.82519 0.08009 0.0

nog_le_pt118 117 39.9477 -109.7716 -1079.1447 70.1718 1615.0 3.05 0.01 295.37 0.00 19.29463 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt119 118 37.2483 -109.0272 -1056.0161 -234.3066 1584.0 3.05 1.52 523.71 23.99 12.35197 0.00640 0.00362 0.00000 0.00000 0.0

nog_le_pt120 119 38.1486 -109.3116 -1067.3872 -132.3011 1856.0 3.05 0.01 295.37 0.00 49.12462 2.82731 0.03545 0.05612 0.00000 0.0

nog_le_pt121 120 38.9314 -109.3519 -1059.1310 -46.0681 1340.0 15.64 0.91 699.64 0.92 54.05942 0.00000 0.05995 0.09386 0.00000 0.0

nog_le_pt122 121 40.2042 -109.5512 -1056.7363 95.6719 1524.0 3.05 0.01 295.37 0.00 26.80451 0.00000 0.00000 0.18806 0.00000 0.1

nog_le_pt123 122 40.2513 -109.5658 -1057.2398 101.0009 1524.0 12.69 0.64 409.46 8.51 10.62781 0.00000 0.04701 0.09403 0.00000 0.0

nog_le_pt124 123 40.4340 -109.5982 -1057.1562 121.3901 1709.0 6.86 0.35 344.83 5.38 14.37987 0.85039 3.92188 1.09163 0.14504 0.0

nog_le_pt125 124 40.9390 -109.7600 -1062.8272 178.5936 2073.0 13.38 0.68 417.59 9.12 0.00000 0.00000 1.75810 0.08408 0.00000 0.0

nog_le_pt126 125 37.4720 -108.9288 -1044.1874 -210.9131 1964.0 3.37 0.17 791.81 17.03 51.90884 0.05230 0.02250 0.00000 0.00000 0.0

nog_le_pt127 126 37.5699 -108.9877 -1047.8891 -199.5001 2042.0 3.11 0.18 604.34 6.71 92.90352 0.02731 0.03669 0.00000 0.00000 0.0

nog_le_pt128 127 37.6539 -108.9874 -1046.6410 -190.2936 2041.0 2.44 1.22 872.04 1.16 1.52738 0.00600 0.00460 0.00000 0.00000 0.0

nog_le_pt129 128 39.2611 -109.2658 -1046.8879 -10.9453 1585.0 6.33 0.30 954.78 19.38 35.41103 0.13363 0.00000 0.05742 0.00000 0.0

nog_le_pt130 129 40.4487 -109.5357 -1051.7214 122.2752 1617.0 3.05 0.01 295.37 0.00 11.09710 0.35341 0.01013 0.01604 0.00000 0.0nog_le_pt131 130 40.6000 -109.4833 -1045.0615 138.2466 1829.0 13.38 0.68 417.59 9.12 0.32640 0.02648 59.64034 18.66125 0.10438 0.8

nog_le_pt132 131 41.2951 -109.6808 -1050.7936 216.6855 1915.0 7.55 0.53 596.39 16.51 72.35786 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt133 132 37.2118 -108.7592 -1033.1391 -241.3905 1831.0 2.13 0.21 523.71 7.25 2.60084 0.00080 0.00061 0.00000 0.00000 0.0

nog_le_pt134 133 37.2471 -108.7814 -1034.5737 -237.2655 2259.0 12.95 0.84 316.48 13.11 0.00000 0.00000 1.62261 0.00000 0.00000 0.0

nog_le_pt135 134 37.4444 -108.9018 -1042.2362 -214.2498 1950.0 3.23 0.28 802.91 24.99 69.74248 0.23452 0.54545 0.00000 0.00000 0.0nog_le_pt136 135 37.7458 -108.8762 -1035.6630 -181.4909 2176.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.35104 0.00000 0.00000 0.0

nog_le_pt137 136 37.7806 -108.8838 -1035.8201 -177.5883 2255.0 5.47 0.24 844.72 58.87 108.37872 0.07304 0.06914 0.00000 0.00000 0.0

nog_le_pt138 137 37.9094 -108.9656 -1041.0388 -162.5316 2255.0 4.57 0.15 363.71 1.55 0.00086 0.00595 0.00051 0.00000 0.00000 0.0

nog_le_pt139 138 38.1236 -108.9014 -1032.3919 -139.7802 1777.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.51891 0.00000 0.00000 0.0

nog_le_pt140 139 39.1688 -109.1260 -1036.3850 -22.6614 1518.0 3.05 0.01 295.37 0.00 8.92024 0.74924 0.01063 0.01684 0.00000 0.0

nog_le_pt141 140 40.5683 -109.3308 -1032.8479 133.0296 2110.0 3.05 0.01 295.37 0.00 0.75062 0.01458 0.01697 0.02687 0.00000 0.0nog_le_pt142 141 37.2100 -108.7200 -1029.7398 -242.0328 1737.0 3.05 0.01 295.37 0.00 0.00000 0.00000 22.19294 9.63808 0.00051 0.2

nog_le_pt143 142 37.2902 -108.6727 -1024.4704 -233.7688 1830.0 12.95 0.84 316.48 13.11 0.00000 0.00000 7.30183 0.00000 0.00000 0.0

nog_le_pt144 143 37.4716 -108.7548 -1029.0477 -212.9418 2023.0 12.68 0.82 588.57 8.55 16.10986 23.28299 5.56487 0.00000 0.00000 0.0

nog_le_pt145 144 37.5705 -108.7152 -1024.1939 -202.5410 2187.0 15.85 1.22 802.59 31.30 32.59414 0.90397 0.03710 0.00000 0.00000 0.0

nog_le_pt146 145 37.9767 -108.7734 -1023.4498 -157.3354 1776.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.69045 0.00000 0.00000 0.0

nog_le_pt147 146 38.0278 -108.8299 -1027.6000 -151.0944 1749.0 4.57 0.25 533.15 15.24 0.01414 0.00004 0.00003 0.00000 0.00000 0.0

nog_le_pt148 147 38.6796 -108.9688 -1030.1310 -78.0644 2133.0 3.05 0.01 295.37 0.00 0.00000 0.00000 19.26142 0.00000 0.00000 0.0nog_le_pt149 148 39.2586 -108.9971 -1024.1256 -14.2810 1493.0 3.05 0.01 295.37 0.00 3.54178 0.00120 0.00092 0.00000 0.00000 0.0

nog_le_pt150 149 39.3308 -109.0011 -1023.4139 -6.3224 1527.0 7.62 0.44 541.48 13.99 19.03694 0.01441 0.01105 0.00000 0.00000 0.0

nog_le_pt151 150 39.3952 -108.9774 -1020.4688 0.4699 1950.0 6.10 0.24 523.71 3.99 21.91460 0.01881 0.01442 0.00000 0.00000 0.0

nog_le_pt152 151 39.8014 -109.0775 -1022.9956 46.1171 1950.0 3.05 0.01 295.37 0.00 45.27935 0.09896 0.09368 0.14833 0.00000 0.0

nog_le_pt153 152 41.4750 -109.4760 -1031.2061 234.0565 2073.0 12.50 1.22 479.26 20.12 4.58277 0.00000 0.02843 0.01531 0.00000 0.0

nog_le_pt154 153 36.8833 -108.4832 -1013.6013 -280.5462 1727.0 32.49 0.61 321.30 20.97 0.00000 0.00000 0.94225 0.96885 0.03323 0.0nog_le_pt155 154 37.3046 -108.5841 -1016.5341 -233.1838 1942.0 3.28 0.06 373.79 0.56 0.00742 0.01237 0.63639 0.00000 0.00000 0.0nog_le_pt156 155 37.3645 -108.5737 -1014.7849 -226.7276 1861.0 2.02 0.52 402.22 12.75 4.61049 0.11818 0.92159 0.00000 0.00000 0.0

nog_le_pt157 156 38.0463 -108.6426 -1011.1587 -151.1666 2003.0 5.30 0.17 592.01 12.83 79.06156 0.12283 0.09417 0.00000 0.00000 0.0

nog_le_pt158 157 38.1217 -108.7314 -1017.7548 -141.9061 1955.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.77664 0.00000 0.00000 0.0

nog_le_pt159 158 39.1911 -108.8034 -1008.6510 -23.8469 1432.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.03445 0.00000 0.00000 0.0

nog_le_pt160 159 39.3679 -108.9232 -1016.2725 -3.1300 1584.0 7.61 0.40 413.73 10.98 108.12534 0.37141 0.34772 0.00000 0.00000 0.0

nog_le_pt161 160 39.6966 -108.9433 -1013.2130 33.1264 2229.0 1.83 0.06 523.71 70.16 1.49971 0.00240 0.00184 0.00000 0.00000 0.0

nog_le_pt162 161 39.8312 -108.9062 -1008.1393 47.4694 2194.0 0.91 0.05 523.71 15.11 1.66020 0.00023 0.00018 0.00000 0.00000 0.0

nog_le_pt163 162 39.8516 -108.9622 -1012.5576 50.3283 2133.0 4.70 0.28 712.71 23.97 40.48098 0.10493 0.02075 0.00000 0.00000 0.0

nog_le_pt164 163 40.0365 -108.9747 -1010.9232 70.7367 1648.0 2.44 0.05 523.71 13.02 5.47865 0.00320 0.00245 0.00000 0.00000 0.0
Table D-1 CALPUFF Model Inputs: 2018 Non-Project Point Sources Less Than 100 TPY 

Source_ID Grid Cell Assignment Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (

nog_le_pt165 164 41.5230 -109.3180 -1017.5093 237.5383 1969.0 8.53 0.61 674.26 36.27 42.32810 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt166 165 36.7000 -108.3000 -1000.0303 -302.6999 1798.0 9.14 0.91 310.93 64.71 63.87902 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt167 166 36.7717 -108.3226 -1001.0340 -294.5781 1706.0 4.03 0.32 790.27 37.89 22.92605 0.00000 0.00000 0.07480 0.00000 0.0

nog_le_pt168 167 37.0851 -108.3525 -999.3431 -259.8422 2133.0 3.05 0.01 295.37 0.00 0.00000 0.00000 5.54725 0.00000 0.00000 0.0

nog_le_pt169 168 37.4215 -108.4360 -1001.9841 -222.0009 2255.0 5.75 0.41 677.86 68.07 43.75766 0.11430 6.12813 0.00000 0.00000 0.0

nog_le_pt170 169 38.0667 -108.5339 -1001.4835 -150.1326 2076.0 5.49 0.15 363.71 1.55 0.00246 0.01699 0.00144 0.00000 0.00000 0.0

nog_le_pt171 170 38.2204 -108.5601 -1001.5900 -132.9843 1770.0 3.05 0.01 295.37 0.00 0.00000 0.00000 15.46177 0.00000 0.00000 0.0

nog_le_pt172 171 38.2652 -108.5499 -1000.0830 -128.1827 1837.0 3.05 0.01 295.37 0.00 0.00000 0.00000 83.65873 0.00000 0.00000 0.0

nog_le_pt173 172 38.4817 -108.5645 -998.3022 -104.2756 2865.0 3.05 0.01 295.37 0.00 0.00000 0.00000 7.35366 0.00000 0.00000 0.0

nog_le_pt174 173 39.1581 -108.7460 -1004.2436 -28.1007 1383.0 6.50 1.28 443.95 8.26 56.87770 1.45500 56.53869 0.00000 0.00000 0.0

nog_le_pt175 174 39.4419 -108.7684 -1002.0958 3.2637 2255.0 3.36 0.02 295.35 0.18 0.00000 0.00000 17.13733 0.00000 0.00000 0.0

nog_le_pt176 175 39.8194 -108.7758 -997.3287 44.7368 1979.0 8.04 0.28 610.55 31.59 102.10240 0.26082 0.19015 0.00000 0.00000 0.0

nog_le_pt177 176 39.8575 -108.8829 -1005.7985 50.0945 2127.0 4.65 0.27 544.65 20.12 69.03654 0.40870 0.08693 0.00000 0.00000 0.0

nog_le_pt178 177 39.9682 -108.8807 -1004.0176 62.2068 1877.0 0.50 0.15 523.71 7.25 3.52349 0.00133 0.00184 0.00000 0.00000 0.0

nog_le_pt179 178 40.1082 -108.8924 -1002.9805 77.6855 1645.0 7.69 0.61 483.28 9.81 31.40391 3.39224 7.25810 0.00000 0.00000 0.0

nog_le_pt180 179 41.3641 -109.1200 -1003.5900 217.9109 2222.0 7.66 0.33 725.52 16.32 54.29859 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt181 180 41.5165 -109.1850 -1006.6855 235.3442 2073.0 9.08 0.70 645.93 33.96 45.13521 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt182 181 36.7219 -108.1851 -989.6160 -301.5527 1676.0 18.87 2.08 504.34 19.00 69.46081 0.00000 0.06663 0.00000 0.00000 0.0

nog_le_pt183 182 36.7442 -108.1843 -989.2426 -299.1124 1706.0 6.77 0.31 683.91 36.64 160.79356 0.00000 2.56925 4.29297 0.05085 0.2

nog_le_pt184 183 36.9092 -108.1641 -985.2276 -281.2119 1828.0 5.37 0.30 753.37 30.58 23.88779 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt185 184 37.3304 -108.3493 -995.6827 -232.9520 2133.0 3.05 0.01 295.37 0.00 0.00000 0.00000 9.46790 0.00000 0.00000 0.0

nog_le_pt186 185 37.6541 -108.3937 -995.0803 -196.9410 2654.0 15.24 0.58 523.71 37.34 23.18626 0.14163 0.10858 0.00000 0.00000 0.0

nog_le_pt187 186 37.9743 -108.4272 -993.5494 -161.4406 2621.0 7.15 0.36 308.09 7.71 0.00000 0.00000 2.50831 0.00000 0.00000 0.0

nog_le_pt188 187 38.1243 -108.4505 -993.4800 -144.7292 2088.0 4.83 0.13 774.14 13.52 66.40007 0.01448 0.00522 0.00000 0.00000 0.0

nog_le_pt189 188 38.1709 -108.4057 -988.9684 -140.1054 2065.0 3.00 0.01 302.64 0.16 2.71166 0.12206 115.24026 0.00000 0.00000 0.0

nog_le_pt190 189 38.2820 -108.4128 -988.0420 -127.8394 1966.0 3.05 0.01 295.37 0.00 0.00000 0.00000 17.55523 0.00000 0.00000 0.0

nog_le_pt191 190 39.0730 -108.5832 -991.5969 -39.2204 1422.0 5.11 0.26 311.46 3.55 108.23901 1.36457 190.89234 0.00000 0.00000 0.0

nog_le_pt192 191 39.1210 -108.6328 -995.1423 -33.4142 1402.0 8.30 0.46 314.37 9.14 80.71300 6.28046 17.38799 0.00000 0.00000 0.0

nog_le_pt193 192 39.2303 -108.6475 -994.8482 -21.2671 1534.0 6.10 0.25 999.82 11.13 9.64695 0.00729 0.00268 0.00000 0.00000 0.0

nog_le_pt194 193 39.3314 -108.5917 -988.6861 -10.7889 2072.0 6.40 0.34 510.93 6.80 6.41050 0.07290 0.00335 0.00000 0.00000 0.0

nog_le_pt195 194 39.8307 -108.7011 -990.8768 45.1587 2013.0 5.58 0.25 485.08 8.94 35.99298 0.01246 5.39709 0.00000 0.00000 0.0nog_le_pt196 195 39.9091 -108.7466 -993.5909 54.2528 1950.0 4.78 0.32 743.26 17.12 66.64565 0.15179 0.10555 0.00000 0.00000 0.0nog_le_pt197 196 40.1488 -108.7081 -986.9469 80.1197 1706.0 3.08 0.01 295.47 0.05 0.01117 0.00343 4.49300 0.00000 0.00000 0.0nog_le_pt198 197 40.1948 -108.7235 -987.5834 85.3318 1706.0 4.63 0.06 295.28 0.91 0.00000 0.00000 97.14555 0.00000 0.00000 0.0

nog_le_pt199 198 36.6686 -108.0610 -979.4068 -308.7514 1767.0 4.25 0.26 772.32 33.94 26.92709 0.00000 0.00000 0.03995 0.00399 0.0

nog_le_pt200 199 36.7876 -108.0448 -976.3829 -295.8544 1802.0 7.32 0.44 790.93 17.47 35.13636 0.00000 0.00000 0.00831 0.00000 0.0

nog_le_pt201 200 36.9392 -108.0617 -975.8327 -279.0222 1979.0 3.66 0.43 882.50 16.54 21.09521 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt202 201 37.1188 -108.1083 -977.5003 -258.7983 2133.0 3.14 0.05 452.59 4.23 7.34369 2.85010 20.05243 0.00000 0.00000 0.0

nog_le_pt203 202 37.2513 -108.1095 -975.8179 -244.2366 2377.0 3.05 0.01 295.37 0.00 0.00000 0.00000 61.08458 0.00000 0.00000 0.0

nog_le_pt204 203 37.7857 -108.2479 -980.6153 -184.0838 3163.0 3.05 0.01 295.37 0.00 0.53980 0.00000 0.06622 0.00000 0.00000 0.0

nog_le_pt205 204 38.1377 -108.2330 -974.5235 -145.6140 2294.0 14.50 0.34 296.00 6.94 0.00246 0.01699 3.08022 0.00000 0.00000 0.0nog_le_pt206 205 38.1525 -108.2514 -975.9095 -143.7924 2278.0 3.05 0.01 295.37 0.00 0.00000 0.00000 4.87932 0.00000 0.00000 0.0

nog_le_pt207 206 38.7942 -108.3201 -973.0218 -72.6464 1767.0 3.05 0.01 295.37 0.00 0.00000 0.00000 8.22747 0.00000 0.00000 0.0

nog_le_pt208 207 38.8858 -108.3575 -974.9573 -62.1961 1630.0 3.05 0.01 295.37 0.00 0.00000 0.00000 4.43804 0.00000 0.00000 0.0

nog_le_pt209 208 38.9787 -108.4425 -980.9255 -51.0904 1454.0 4.72 0.11 296.82 1.57 0.00000 0.00000 71.14913 0.00000 0.00000 0.0nog_le_pt210 209 39.0559 -108.4442 -979.9984 -42.6038 1493.0 3.09 0.01 299.30 0.07 0.25157 0.32682 65.54874 0.00000 0.00000 0.0nog_le_pt211 210 39.5064 -108.5145 -979.6918 7.5686 2255.0 6.71 0.34 500.93 13.50 14.09192 0.01511 0.00104 0.00000 0.00000 0.0

nog_le_pt212 211 39.8713 -108.5255 -975.5192 47.7118 2197.0 6.64 0.26 533.05 56.84 16.31258 0.04298 0.03295 0.00000 0.00000 0.0nog_le_pt213 212 39.9203 -108.5510 -976.9790 53.3605 2222.0 4.43 0.23 402.80 7.15 5.81069 0.01361 0.01043 0.00000 0.00000 0.0nog_le_pt214 213 40.1678 -108.6094 -978.4047 81.1363 1718.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.70439 0.00000 0.00000 0.0nog_le_pt215 214 40.9743 -108.6942 -974.0647 170.5190 2075.0 6.29 0.30 586.76 20.96 71.35378 0.21615 2.21578 0.00000 0.00000 0.0

nog_le_pt216 215 41.3584 -108.8184 -978.8407 213.9960 2195.0 5.59 0.43 588.43 16.93 33.06120 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt217 216 36.7034 -107.9676 -970.7133 -305.9307 1709.0 7.34 0.51 723.85 40.56 349.91929 0.44625 0.03134 0.07230 0.00000 0.0

nog_le_pt218 217 36.8305 -107.9925 -971.2093 -291.7026 1801.0 6.98 0.33 664.88 39.44 593.30826 0.00000 0.00381 0.22410 0.00000 0.1

nog_le_pt219 218 36.9238 -107.9073 -962.4819 -282.3603 1889.0 12.09 0.54 704.25 39.99 178.88527 0.00000 0.16097 0.00582 0.00000 0.0

nog_le_pt220 219 36.9901 -107.9629 -966.4816 -274.4876 2072.0 6.46 0.52 752.54 29.76 26.50148 0.00160 0.00123 0.00000 0.00000 0.0

nog_le_pt221 220 37.1213 -107.9397 -962.7031 -260.3236 2011.0 5.54 0.27 574.88 24.17 102.35735 0.17223 0.06079 0.00000 0.00000 0.0

nog_le_pt222 221 37.2025 -108.0275 -969.3043 -250.4727 2392.0 14.57 0.34 295.54 6.98 0.00000 0.00000 6.50175 0.00000 0.00000 0.0

nog_le_pt223 222 37.3841 -108.0615 -969.8390 -230.1692 3752.0 3.50 0.09 297.15 0.34 0.42993 0.07974 99.03807 0.00000 0.00000 0.0

nog_le_pt224 223 37.4336 -108.0056 -964.3004 -225.3289 3068.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.00671 0.00000 0.00000 0.0

nog_le_pt225 224 38.7690 -108.2258 -965.3010 -76.4170 1584.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.72129 0.00000 0.00000 0.0

nog_le_pt226 225 38.9064 -108.2887 -968.7996 -60.6719 1950.0 3.05 0.01 295.37 0.00 0.00000 0.00000 57.70617 0.00000 0.00000 0.0

nog_le_pt227 226 39.0812 -108.2443 -962.6234 -41.9647 3048.0 5.83 0.23 408.73 28.11 31.10110 3.81543 0.06149 0.00000 0.00000 0.0

nog_le_pt228 227 39.1550 -108.3203 -968.0823 -33.0603 1950.0 3.05 0.01 295.37 0.00 0.00000 0.00000 59.73203 0.00000 0.00000 0.0

nog_le_pt229 228 39.3688 -108.2912 -962.6770 -9.9126 1649.0 3.66 0.09 438.15 49.90 12.78340 0.00460 0.00353 0.00000 0.00000 0.0nog_le_pt230 229 39.8592 -108.4447 -968.8846 45.5200 2164.0 3.05 0.01 295.37 0.00 5.85460 0.00209 0.00160 0.00000 0.00000 0.0

nog_le_pt231 230 40.9564 -108.5821 -965.0300 167.3590 2072.0 4.57 0.30 523.71 28.38 8.68846 0.02245 0.01721 0.00000 0.00000 0.0

nog_le_pt232 231 40.9868 -108.5997 -966.0603 170.8818 2145.0 3.35 0.15 777.54 32.56 13.29695 0.00520 0.00276 0.00000 0.00000 0.0

nog_le_pt233 232 36.7636 -107.7351 -949.4471 -301.7726 1945.0 6.78 0.38 653.81 40.00 573.13204 0.00000 0.00000 0.49582 0.00000 0.4

nog_le_pt234 233 36.8061 -107.7568 -950.8020 -296.8757 1912.0 11.93 0.32 728.42 40.09 87.75403 0.00000 0.00000 0.00077 0.00000 0.0nog_le_pt235 234 36.9366 -107.8451 -956.8508 -281.6110 2139.0 6.83 0.30 718.47 35.89 54.64379 0.00000 0.00000 0.00029 0.00000 0.0nog_le_pt236 235 37.1365 -107.8061 -950.8025 -260.0605 2011.0 9.97 0.65 478.75 23.86 182.79123 2.51173 23.94169 0.00000 0.00000 0.0

nog_le_pt237 236 37.2341 -107.8305 -951.6555 -249.0842 2143.0 5.80 0.23 374.16 7.49 62.39324 0.29631 62.51051 0.00000 0.00000 0.0nog_le_pt238 237 37.3656 -107.8450 -951.1916 -234.4890 2812.0 3.31 0.03 295.31 0.32 0.00000 0.00000 11.94874 0.00000 0.00000 0.0

nog_le_pt239 238 37.8553 -107.8831 -948.0464 -180.3144 3662.0 14.57 0.34 294.26 6.98 0.00000 0.00000 48.80415 0.00000 0.00000 0.0

nog_le_pt240 239 37.9578 -107.9186 -949.7654 -168.6896 2986.0 3.46 0.05 295.83 1.42 0.29163 0.02856 1.97762 0.00000 0.00000 0.0

nog_le_pt241 240 38.5404 -108.0685 -954.9132 -103.1655 1775.0 15.24 0.91 523.71 1.10 35.00898 0.13102 0.13950 0.00000 0.00000 0.0

nog_le_pt242 241 38.7043 -108.0632 -952.2575 -85.2326 1569.0 3.15 0.11 295.31 1.10 0.00000 0.00000 1.99102 0.00000 0.00000 0.0

nog_le_pt243 242 38.7454 -108.0976 -954.6501 -80.3610 1526.0 3.08 0.01 299.58 0.03 9.62855 0.24746 49.06985 0.00000 0.00000 0.0nog_le_pt244 243 39.1694 -108.1184 -950.7091 -33.6117 1828.0 23.31 0.44 359.86 7.47 4.66514 0.78986 10.09516 0.00000 0.00000 0.0

nog_le_pt245 244 39.3370 -108.2283 -957.7749 -14.0663 1676.0 5.27 0.26 361.90 6.33 58.80260 0.02857 13.26958 0.00000 0.00000 0.0

nog_le_pt246 245 39.3883 -108.2606 -959.8150 -8.0967 1706.0 6.97 0.25 531.70 36.27 29.38538 0.01800 0.01495 0.00000 0.00000 0.0
Table D-1 CALPUFF Model Inputs: 2018 Non-Project Point Sources Less Than 100 TPY 

Source_ID Grid Cell Assignment Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (

nog_le_pt247 246 39.5693 -108.2492 -956.3772 11.6431 2606.0 5.63 0.37 487.92 17.48 25.48883 0.01733 0.01329 0.00000 0.00000 0.0nog_le_pt248 247 39.5938 -108.2498 -956.0935 14.3377 2560.0 13.89 1.65 350.04 15.07 22.02191 0.00972 0.00748 0.00000 0.00000 0.0

nog_le_pt249 248 39.6966 -108.2830 -957.4929 25.9669 2451.0 4.27 0.17 762.94 45.81 18.42812 0.02278 0.01747 0.00000 0.00000 0.0nog_le_pt250 249 39.8399 -108.2946 -956.5080 41.8125 2011.0 4.09 0.14 519.38 12.37 43.08920 0.01634 0.04804 0.00000 0.00000 0.0nog_le_pt251 250 39.8977 -108.3096 -956.9783 48.3125 2072.0 3.57 0.04 359.46 10.22 21.20084 0.04102 0.03145 0.00000 0.00000 0.0nog_le_pt252 251 40.0456 -108.2827 -952.6886 64.2586 1950.0 5.87 0.19 484.70 10.99 13.61381 0.01529 17.64743 0.00000 0.00000 0.0

nog_le_pt253 252 40.1676 -108.3545 -957.0384 78.4000 1828.0 3.05 0.01 295.37 0.00 0.00000 0.00000 15.11233 0.00000 0.00000 0.0

nog_le_pt254 253 40.8052 -108.3975 -951.8226 148.8195 2012.0 3.28 0.09 785.35 25.37 97.88424 0.04664 0.03576 0.00000 0.00000 0.0

nog_le_pt255 254 41.5902 -108.5036 -949.6707 236.0971 2105.0 12.08 0.43 686.26 14.33 94.56035 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt256 255 36.7059 -107.6397 -941.7942 -309.1063 2072.0 3.37 0.04 462.79 9.94 18.11510 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt257 256 36.8546 -107.6306 -939.0719 -292.8584 1923.0 5.79 0.26 710.30 29.51 99.89299 0.00000 0.00469 0.00000 0.00000 0.0

nog_le_pt258 257 36.9138 -107.6676 -941.5582 -285.9701 2072.0 7.85 0.50 647.59 36.31 27.13914 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt259 258 37.0865 -107.6863 -940.9594 -266.8005 2011.0 3.44 0.19 675.08 41.30 143.18432 0.12097 0.09275 0.00000 0.00000 0.0

nog_le_pt260 259 37.1496 -107.7455 -945.3244 -259.2536 2037.0 2.49 0.12 720.13 23.45 19.49644 0.05775 0.04428 0.00000 0.00000 0.0

nog_le_pt261 260 37.2387 -107.6940 -939.6575 -249.9993 2257.0 1.84 0.08 438.15 73.80 10.19920 0.01694 0.00399 0.00000 0.00000 0.0

nog_le_pt262 261 38.4890 -107.9086 -941.8656 -110.4762 1772.0 6.12 0.21 302.91 3.15 3.41295 1.66910 117.21830 0.00000 0.00000 0.0

nog_le_pt263 262 38.5192 -107.8717 -938.2963 -107.5425 1915.0 6.09 0.61 478.25 12.48 14.31995 0.04804 0.18886 0.00000 0.00000 0.0

nog_le_pt264 263 38.6272 -107.9914 -947.1362 -94.4453 1642.0 3.05 0.01 295.37 0.00 0.00000 0.00000 10.58135 0.00000 0.00000 0.0nog_le_pt265 264 38.7868 -107.9504 -941.4990 -77.3527 1706.0 7.39 0.29 294.87 4.66 0.00000 0.00000 72.07968 0.00000 0.00000 0.0nog_le_pt266 265 38.9089 -107.9506 -939.8933 -63.9481 1974.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.49483 0.00000 0.00000 0.0

nog_le_pt267 266 39.2393 -107.9978 -939.5145 -27.1944 1889.0 5.80 0.29 555.87 8.57 45.35267 0.03638 12.39477 0.00000 0.00000 0.0

nog_le_pt268 267 39.2908 -108.0556 -943.7368 -20.9431 2438.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.47460 0.00000 0.00000 0.0

nog_le_pt269 268 39.4673 -108.0703 -942.6140 -1.4194 1712.0 6.72 0.36 656.70 45.20 129.20135 0.37035 0.54338 0.00000 0.00000 0.0

nog_le_pt270 269 39.4805 -108.1184 -946.5111 0.5292 2032.0 7.31 0.42 565.30 22.04 94.44397 0.50737 0.18324 0.00000 0.00000 0.0

nog_le_pt271 270 39.9017 -108.1929 -947.0995 47.5288 2260.0 7.84 0.33 671.82 15.43 89.77270 0.06701 5.19533 0.00000 0.00000 0.0nog_le_pt272 271 39.9326 -108.1681 -944.5928 50.6618 2255.0 3.51 0.16 783.77 9.37 15.00516 0.01032 5.01667 0.00000 0.00000 0.0nog_le_pt273 272 40.1019 -108.1938 -944.4552 69.5091 1841.0 5.93 0.57 700.42 22.49 172.59638 0.67703 3.31082 0.00000 0.00000 0.0

nog_le_pt274 273 40.1365 -108.1960 -944.1697 73.3292 2011.0 2.44 0.05 523.71 14.08 3.70767 0.00200 0.00153 0.00000 0.00000 0.0

nog_le_pt275 274 40.9450 -108.3025 -942.0117 163.1742 2072.0 3.11 0.14 575.99 45.81 49.50699 0.01555 0.01452 0.00000 0.00000 0.0

nog_le_pt276 275 41.5961 -108.4142 -942.2475 235.8143 2160.0 45.87 0.40 997.65 16.18 15.14527 45.21313 0.00000 0.00000 0.00000 0.0

nog_le_pt277 276 36.7538 -107.5477 -933.0736 -304.7907 2072.0 10.11 0.49 707.83 42.41 144.55570 0.00000 1.05861 0.00000 0.00000 0.0

nog_le_pt278 277 36.8121 -107.5160 -929.5370 -298.7075 2011.0 9.84 0.45 624.69 18.25 55.73208 0.00000 0.00671 0.00000 0.00000 0.0

nog_le_pt279 278 36.9084 -107.5645 -932.5688 -287.6266 1970.0 12.66 0.60 677.57 45.07 61.65553 0.00000 0.00402 0.00000 0.00000 0.0

nog_le_pt280 279 37.1103 -107.6092 -933.8949 -264.9808 2011.0 3.05 0.01 295.37 0.00 0.00000 0.00000 18.96504 0.00000 0.00000 0.0

nog_le_pt281 280 37.1914 -107.5817 -930.4427 -256.3516 2133.0 3.05 0.01 295.37 0.00 0.00000 0.00000 10.08240 0.00000 0.00000 0.0

nog_le_pt282 281 38.0875 -107.7108 -930.0877 -156.5971 2926.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.22241 0.00000 0.00000 0.0

nog_le_pt283 282 38.1824 -107.7381 -931.2102 -145.8962 2214.0 3.05 0.01 295.37 0.00 0.00000 0.00000 12.48672 0.00000 0.00000 0.0

nog_le_pt284 283 38.5114 -107.7869 -931.1142 -109.2711 2164.0 3.05 0.01 295.37 0.00 0.00000 0.00000 23.20415 0.00000 0.00000 0.0

nog_le_pt285 284 39.2654 -107.8845 -929.5373 -25.4945 2255.0 2.67 0.04 437.12 19.57 10.40396 0.00360 6.36252 0.00000 0.00000 0.0

nog_le_pt286 285 39.2888 -107.8332 -924.8694 -23.4491 2438.0 2.44 0.10 647.22 27.10 17.52621 0.00640 0.00491 0.00000 0.00000 0.0

nog_le_pt287 286 39.4870 -107.9544 -932.5315 -0.4529 1719.0 3.37 0.16 442.78 32.38 38.79330 0.05075 0.03891 0.00000 0.00000 0.0

nog_le_pt288 287 39.5260 -107.9355 -930.4127 3.6344 2133.0 6.32 0.37 585.62 27.45 143.29427 0.32077 11.81762 0.00000 0.00000 0.0

nog_le_pt289 288 39.8421 -107.9120 -924.2361 38.0949 2760.0 3.05 0.01 295.37 0.00 0.00000 0.00000 5.51369 0.00000 0.00000 0.0

nog_le_pt290 289 40.0261 -108.0292 -931.6510 59.4903 1889.0 3.97 0.08 428.88 14.92 14.75367 0.01721 0.01319 0.00000 0.00000 0.0

nog_le_pt291 290 40.2888 -108.0213 -927.4723 88.2473 2499.0 6.10 0.19 458.21 11.67 2.18066 0.01308 0.01529 0.00000 0.00000 0.0

nog_le_pt292 291 40.4889 -108.0498 -927.1746 110.5056 1889.0 3.05 0.01 295.37 0.00 0.00000 0.00000 15.86175 0.00000 0.00000 0.0nog_le_pt293 292 36.8208 -107.4434 -923.0377 -298.4912 1950.0 6.81 0.38 517.62 9.24 23.79800 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt294 293 36.9559 -107.3527 -913.3568 -284.5568 2194.0 2.90 0.29 859.17 6.43 12.26737 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt295 294 38.8214 -107.6900 -918.7659 -76.2193 1712.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.34386 0.00000 0.00000 0.0

nog_le_pt296 295 38.9061 -107.6527 -914.4795 -67.2949 2499.0 3.62 0.46 294.23 2.36 0.00000 0.00000 53.63171 0.00000 0.00000 0.0

nog_le_pt297 296 39.4744 -107.7275 -913.4707 -4.1407 1826.0 5.90 2.04 600.41 15.49 92.11067 0.27416 0.19254 0.00000 0.00000 0.0

nog_le_pt298 297 39.5270 -107.8105 -919.8149 2.4717 1645.0 4.61 0.16 443.26 13.15 112.51988 0.13240 61.34159 0.00000 0.00000 0.0

nog_le_pt299 298 40.0139 -107.8729 -918.6727 56.5598 2012.0 9.95 0.39 294.55 4.73 0.00000 0.00000 16.19297 0.00000 0.00000 0.0nog_le_pt300 299 40.1947 -107.9173 -920.0099 76.8593 2561.0 7.17 0.28 764.90 15.00 18.55937 1.37655 0.14760 0.00000 0.00000 0.0

nog_le_pt301 300 40.9855 -108.0684 -922.0537 165.2198 1974.0 4.57 0.15 672.05 12.57 6.81364 0.00400 0.00307 0.00000 0.00000 0.0

nog_le_pt302 301 36.8648 -107.2229 -903.0855 -295.8694 2194.0 6.10 0.15 756.48 43.89 4.13034 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt303 302 37.0092 -107.2226 -901.2656 -279.9962 2135.0 3.05 0.01 295.37 0.00 0.00000 0.00000 9.34583 0.00000 0.00000 0.0

nog_le_pt304 303 37.2206 -107.3425 -909.1351 -255.5637 2168.0 3.05 0.01 295.37 0.00 15.22853 1.00141 10.60942 0.00000 0.00000 0.0

nog_le_pt305 304 38.3669 -107.4874 -907.2180 -128.1691 2778.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.47053 0.00000 0.00000 0.0

nog_le_pt306 305 38.6614 -107.5289 -907.0275 -95.4084 2743.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.90960 0.00000 0.00000 0.0

nog_le_pt307 306 38.9163 -107.5444 -905.0939 -67.2590 2186.0 3.05 0.01 295.37 0.00 0.00000 0.00000 32.94599 0.00000 0.00000 0.0

nog_le_pt308 307 39.3860 -107.5996 -903.7670 -15.1267 2622.0 6.04 0.27 589.80 23.95 21.07985 0.02677 0.02096 0.00000 0.00000 0.0

nog_le_pt309 308 39.4944 -107.6738 -908.6600 -2.4830 1828.0 4.62 0.33 326.78 6.00 27.89294 0.07324 13.38652 0.00000 0.00000 0.0

nog_le_pt310 309 39.5402 -107.7007 -910.3445 2.8154 1691.0 3.05 0.01 295.37 0.00 0.00000 0.00000 5.57879 0.00000 0.00000 0.0

nog_le_pt311 310 40.5777 -107.7818 -903.6315 117.5568 2073.0 3.08 0.13 525.37 11.54 24.41930 2.44423 2.32975 0.00000 0.00000 0.0

nog_le_pt312 311 40.8685 -107.9171 -911.0619 150.8452 2073.0 7.62 0.44 541.48 4.27 5.53413 0.00000 0.00675 0.00000 0.00000 0.0nog_le_pt313 312 41.6722 -107.9809 -905.6409 239.7678 2080.0 8.22 1.51 682.56 15.41 22.45517 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt314 313 38.9325 -107.4694 -898.4789 -66.2239 2391.0 3.05 0.01 295.37 0.00 0.00000 0.00000 90.13543 0.00000 0.00000 0.0

nog_le_pt315 314 39.3655 -107.5236 -897.5779 -18.1313 2804.0 8.38 0.51 294.26 6.61 8.46691 0.00366 0.00280 0.00000 0.00000 0.0

nog_le_pt316 315 40.4752 -107.6115 -890.7447 104.6171 1956.0 3.05 0.01 295.37 0.00 0.00000 0.00000 11.58083 0.00000 0.00000 0.0

nog_le_pt317 316 37.1564 -107.0558 -884.8221 -265.4512 2377.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.45209 0.00000 0.00000 0.0

nog_le_pt318 317 37.3008 -107.0761 -884.8334 -249.3771 2368.0 2.74 0.15 1009.26 5.73 0.00000 0.00000 0.00228 0.00000 0.00000 0.0nog_le_pt319 318 39.3906 -107.2735 -876.0253 -17.8147 2072.0 7.46 0.27 706.05 44.67 20.32028 0.05152 0.00357 0.00000 0.00000 0.0

nog_le_pt320 319 39.5470 -107.3296 -878.8270 -0.0908 2438.0 4.88 0.51 560.93 11.46 0.01670 0.04454 0.00033 0.00000 0.00000 0.0

nog_le_pt321 320 39.5708 -107.4058 -884.9811 3.2632 2299.0 3.05 0.01 295.37 0.00 0.00000 0.00000 6.00243 0.00000 0.00000 0.0

nog_le_pt322 321 40.2001 -107.4658 -882.0651 72.9758 2438.0 2.04 0.08 894.26 81.38 26.85123 0.02112 0.40344 0.00000 0.00000 0.0nog_le_pt323 322 40.4886 -107.5395 -884.5567 105.3859 1951.0 3.15 0.02 321.21 5.85 23.65612 0.00818 57.71807 0.00000 0.00000 0.0

nog_le_pt324 323 40.6172 -107.5142 -880.8008 119.2686 2010.0 2.97 0.14 630.43 41.95 36.47416 0.11179 0.25564 0.00000 0.00000 0.0

nog_le_pt325 324 40.7221 -107.5709 -884.1827 131.3442 2012.0 4.94 0.26 667.73 20.25 20.01083 0.01470 1.77727 0.00000 0.00000 0.0

nog_le_pt326 325 40.7522 -107.5518 -882.2066 134.4656 2368.0 4.88 0.15 831.48 5.76 8.87096 0.01121 0.00859 0.00000 0.00000 0.0nog_le_pt327 326 40.9225 -107.6091 -884.7813 153.7338 2012.0 3.05 0.08 418.85 21.80 5.43423 0.00656 0.00503 0.00000 0.00000 0.0

nog_le_pt328 327 40.9647 -107.6295 -885.9300 158.5691 2018.0 3.49 0.52 568.45 18.53 21.01995 0.01601 0.01227 0.00000 0.00000 0.0
Table D-1 CALPUFF Model Inputs: 2018 Non-Project Point Sources Less Than 100 TPY 

Source_ID Grid Cell Assignment Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (

nog_le_pt329 328 37.0346 -106.8440 -867.7161 -280.8880 2377.0 6.03 0.10 295.41 1.80 0.00206 0.00014 22.64009 0.00000 0.00000 0.0

nog_le_pt330 329 37.3182 -106.9482 -873.4368 -248.7012 2504.0 3.05 0.01 295.37 0.00 0.00000 0.00000 19.18148 0.00000 0.00000 0.0

nog_le_pt331 330 39.0353 -107.1678 -871.4364 -57.8677 4023.0 3.05 0.01 295.37 0.00 10.82809 0.00000 0.00000 0.00000 0.00000 0.0nog_le_pt332 331 39.4013 -107.2198 -871.3329 -17.1554 2011.0 16.49 1.31 294.26 10.67 0.00059 0.00439 0.00167 0.00000 0.00000 0.0

nog_le_pt333 332 39.4458 -107.2667 -874.7599 -11.8157 2133.0 3.05 0.01 295.37 0.00 0.00000 0.00000 37.99343 0.00000 0.00000 0.0nog_le_pt334 333 40.3633 -107.2922 -865.4573 89.2377 2256.0 15.33 0.82 294.26 10.16 0.00000 0.00000 29.18971 0.00000 0.00000 0.0

nog_le_pt335 334 40.4625 -107.3764 -871.2569 100.9427 2073.0 3.05 0.01 295.37 0.00 0.00000 0.00000 21.73685 0.00000 0.00000 0.0

nog_le_pt336 335 40.9819 -107.3872 -865.6073 158.1242 2256.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.13868 0.00000 0.00000 0.0nog_le_pt337 336 37.2148 -106.7058 -853.4558 -262.3760 3535.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.91881 0.00000 0.00000 0.0

nog_le_pt338 337 37.3408 -106.8297 -862.8036 -247.3480 3052.0 3.05 0.01 295.37 0.00 0.00000 0.00000 11.18452 0.00000 0.00000 0.0

nog_le_pt339 338 38.5582 -106.9617 -859.6151 -112.2603 2387.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.57128 0.00000 0.00000 0.0

nog_le_pt340 339 38.8680 -107.0292 -861.6435 -77.5733 3029.0 12.50 0.27 294.26 15.81 0.00000 0.00000 0.09503 0.00000 0.00000 0.0

nog_le_pt341 340 39.3861 -107.0809 -859.7254 -20.1485 2438.0 3.70 0.19 296.22 0.19 0.00742 0.01979 18.88037 0.00000 0.00000 0.0nog_le_pt342 341 39.6736 -107.0714 -855.4027 11.3560 2573.0 3.05 0.01 295.37 0.00 0.00000 0.00000 29.07225 0.00000 0.00000 0.0

nog_le_pt343 342 40.2897 -107.1859 -857.4668 80.1419 2499.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.38682 0.00000 0.00000 0.0nog_le_pt344 343 40.4913 -107.2189 -857.7312 102.6093 2012.0 3.05 0.01 295.37 0.00 0.00000 0.00000 9.18865 0.00000 0.00000 0.0nog_le_pt345 344 41.5319 -107.3611 -856.5183 218.3376 2524.0 3.05 0.01 295.37 0.00 17.82259 0.00000 0.00000 0.00000 0.00000 0.0nog_le_pt346 345 38.5412 -106.8608 -851.1461 -115.0785 2560.0 3.05 0.01 295.37 0.00 0.00000 0.00000 4.21768 0.00000 0.00000 0.0

nog_le_pt347 346 38.6111 -106.8803 -851.9840 -107.2124 2654.0 17.07 0.36 533.15 10.29 0.71379 0.01167 0.46585 0.00000 0.00000 0.0

nog_le_pt348 347 38.8421 -106.8362 -845.4370 -82.2326 3352.0 3.05 0.01 295.37 0.00 0.00000 0.00000 17.94559 0.00000 0.00000 0.0

nog_le_pt349 348 39.2505 -106.8823 -844.4830 -36.9134 2577.0 3.05 0.01 295.37 0.00 0.00000 0.00000 38.97103 0.00000 0.00000 0.0nog_le_pt350 349 39.2680 -106.8794 -844.0262 -35.0169 2629.0 3.05 0.01 295.37 0.00 0.00000 0.00000 10.85346 0.00000 0.00000 0.0nog_le_pt351 350 39.4393 -106.8942 -843.2275 -16.0509 3535.0 6.10 2.43 294.75 1.99 0.00000 0.00000 17.42820 0.00000 0.00000 0.0nog_le_pt352 351 39.6496 -106.9328 -843.9676 7.4224 2073.0 3.05 0.01 295.37 0.00 0.00000 0.00000 25.89602 0.00000 0.00000 0.0

nog_le_pt353 352 40.4387 -107.1082 -849.1238 95.7885 2438.0 0.61 0.06 523.71 5.67 1.95888 0.00080 0.00061 0.00000 0.00000 0.0nog_le_pt354 353 40.4707 -107.0283 -842.0496 98.5625 2110.0 3.05 0.01 295.37 0.00 0.00000 0.00000 49.49515 0.00000 0.00000 0.0nog_le_pt355 354 39.6522 -106.8367 -835.8032 6.8200 2215.0 3.13 0.02 318.78 0.23 1.06927 0.29493 57.45649 0.00000 0.00000 0.0

nog_le_pt356 355 39.8772 -106.8564 -834.7774 31.7347 2179.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.05202 0.00000 0.00000 0.0nog_le_pt357 356 40.1567 -106.9144 -836.3049 62.9932 2621.0 7.62 0.63 394.26 16.11 0.71756 0.01938 0.00846 0.00000 0.00000 0.0

nog_le_pt358 357 40.2754 -106.9677 -839.3460 76.5331 2541.0 5.20 0.43 665.65 13.76 7.19627 0.74779 0.15801 0.00000 0.00000 0.0

nog_le_pt359 358 40.4941 -106.9214 -832.8274 100.1499 2106.0 3.05 0.01 295.37 0.00 0.00000 0.00000 39.23982 0.00000 0.00000 0.0nog_le_pt360 359 40.7083 -106.9336 -831.2628 123.8124 2493.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.73232 0.00000 0.00000 0.0nog_le_pt361 360 37.1546 -106.3172 -820.0891 -272.5775 2987.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.44221 0.00000 0.00000 0.0

nog_le_pt362 361 37.7003 -106.3458 -816.4008 -212.2757 2438.0 3.13 0.05 296.75 1.50 0.59057 0.07723 21.04151 0.00000 0.00000 0.0

nog_le_pt363 362 39.7261 -106.6619 -820.1402 13.3518 2537.0 8.27 0.30 295.11 2.60 0.00000 0.00000 16.11658 0.00000 0.00000 0.0nog_le_pt364 363 39.9736 -106.7044 -820.8171 40.9484 2865.0 3.05 0.01 295.37 0.00 0.00000 0.00000 27.34836 0.00000 0.00000 0.0nog_le_pt365 364 40.3959 -106.8244 -825.8887 88.4679 2499.0 6.02 0.23 295.19 3.46 0.16931 0.01099 46.30756 0.00000 0.00000 0.0nog_le_pt366 365 40.5019 -106.8566 -827.3159 100.4156 2219.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.14614 0.00000 0.00000 0.0nog_le_pt367 366 41.5359 -106.9139 -819.6516 214.6533 2072.0 13.96 0.82 396.92 12.13 26.37454 1.17570 70.37120 0.00000 0.00000 0.0

nog_le_pt368 367 41.7061 -106.9364 -819.4489 233.5814 2073.0 5.30 0.28 308.65 6.59 2.48529 0.00000 60.66109 50.00723 0.91519 10.1

nog_le_pt369 368 37.6941 -106.3287 -814.9826 -213.1113 2433.0 3.05 0.01 295.37 0.00 0.00000 0.00000 4.16064 0.00000 0.00000 0.0

nog_le_pt370 369 38.1354 -106.3405 -811.0025 -164.4591 2743.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.67738 0.00000 0.00000 0.0

nog_le_pt371 370 38.4036 -106.2972 -804.2273 -135.3424 3304.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.82776 0.00000 0.00000 0.0

nog_le_pt372 371 39.6447 -106.5108 -808.3018 3.0473 2852.0 6.64 0.14 294.81 1.80 0.00000 0.00000 2.30720 0.00000 0.00000 0.0

nog_le_pt373 372 41.1791 -106.7882 -813.5439 174.2735 2451.0 18.29 0.01 295.37 0.00 0.00000 0.21302 0.00000 0.00000 0.00000 0.0

nog_le_pt374 373 41.7179 -106.8614 -813.1466 234.2060 2067.0 11.72 2.43 1001.96 24.14 21.86710 0.00000 0.00000 0.00000 0.00000 0.0

nog_le_pt375 374 37.0473 -106.0081 -794.1480 -287.1335 2407.0 7.45 0.45 358.75 12.71 14.59448 0.07864 46.35578 0.00000 0.00000 0.0

nog_le_pt376 375 37.3993 -106.0964 -798.0153 -247.6127 2347.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.00896 0.00000 0.00000 0.0

nog_le_pt377 376 37.5268 -106.1251 -799.1109 -233.3283 2290.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.91051 0.00000 0.00000 0.0

nog_le_pt378 377 37.5959 -106.1317 -798.9202 -225.6658 2320.0 3.16 0.07 300.46 0.64 0.54513 1.10544 35.93917 0.00000 0.00000 0.0nog_le_pt379 378 37.7565 -106.1967 -802.7931 -207.4207 2329.0 3.05 0.01 295.37 0.00 0.00000 0.00000 24.71846 0.00000 0.00000 0.0

nog_le_pt380 379 38.0522 -106.1289 -793.6153 -175.4804 2346.0 3.05 0.01 295.37 0.00 0.00000 0.00000 14.44524 0.00000 0.00000 0.0

nog_le_pt381 380 39.1541 -106.2901 -795.1469 -52.8554 3208.0 19.20 1.03 301.16 11.93 0.00000 0.00000 4.14760 0.00000 0.00000 0.0nog_le_pt382 381 39.2388 -106.2896 -794.1486 -43.5435 3352.0 3.10 0.02 296.50 0.26 0.00000 0.00000 18.61696 0.00000 0.00000 0.0

nog_le_pt383 382 39.5802 -106.4184 -801.2150 -4.8642 3119.0 3.08 0.01 296.23 0.13 0.05453 0.00363 16.91488 0.00000 0.00000 0.0nog_le_pt384 383 39.6426 -106.3837 -797.5624 1.6934 2930.0 6.66 0.27 571.85 2.39 1.15153 0.42849 0.33138 0.00000 0.00000 0.0

nog_le_pt385 384 40.0290 -106.3869 -793.4279 44.2210 2658.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.55473 0.00000 0.00000 0.0nog_le_pt386 385 40.1111 -106.4650 -799.0616 53.9355 2529.0 12.95 0.84 316.48 13.11 0.00000 0.00000 6.57365 0.00000 0.00000 0.0nog_le_pt387 386 40.4759 -106.4526 -793.8297 93.9527 2573.0 3.05 0.01 295.37 0.00 0.00000 0.00000 18.65990 0.00000 0.00000 0.0nog_le_pt388 387 37.6444 -105.9495 -782.5045 -221.9134 2290.0 5.50 0.34 536.30 3.87 6.64092 0.01334 0.00123 0.00000 0.00000 0.0

nog_le_pt389 388 38.1135 -106.0197 -783.4817 -169.6829 2361.0 3.05 0.01 295.37 0.00 0.00000 0.00000 4.87662 0.00000 0.00000 0.0

nog_le_pt390 389 38.2594 -106.1355 -791.8877 -152.6257 3131.0 3.05 0.01 295.37 0.00 0.00000 0.00000 37.46725 0.00000 0.00000 0.0nog_le_pt391 390 38.7468 -106.1293 -785.9471 -99.0577 2438.0 5.79 0.30 1223.71 2.44 0.13742 0.28950 0.22851 0.00000 0.00000 0.0nog_le_pt392 391 38.8326 -106.1271 -784.8071 -89.6377 2753.0 7.01 0.41 383.81 11.21 43.39438 0.36716 38.84848 0.00000 0.00000 0.0

nog_le_pt393 392 39.2272 -106.2194 -788.2979 -45.4307 4027.0 9.14 0.34 291.48 25.39 0.00000 0.00000 10.02400 0.00000 0.00000 0.0

nog_le_pt394 393 39.4847 -106.1575 -780.1590 -17.6387 3413.0 8.23 0.67 1144.26 10.06 0.29057 0.18366 0.34463 0.00000 0.00000 0.0

nog_le_pt395 394 40.0814 -106.3728 -791.6437 49.8618 2438.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.02884 0.00000 0.00000 0.0

nog_le_pt396 395 37.4679 -105.8829 -778.6051 -241.9137 2285.0 10.22 3.77 785.91 44.88 67.14244 16.04938 1.98852 0.00000 0.00000 0.0nog_le_pt397 396 37.5015 -105.8210 -772.8363 -238.7431 2285.0 7.63 0.69 453.45 5.73 14.50696 0.39473 6.39071 0.00000 0.00000 0.0nog_le_pt398 397 37.7569 -105.8633 -773.7799 -210.2687 2287.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.35741 0.00000 0.00000 0.0

nog_le_pt399 398 38.0195 -105.8771 -772.1485 -181.2480 2294.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.66361 0.00000 0.00000 0.0

nog_le_pt400 399 38.4335 -105.8924 -769.0026 -135.5566 2486.0 3.05 0.01 295.37 0.00 0.00000 0.00000 4.57672 0.00000 0.00000 0.0

nog_le_pt401 400 38.5355 -105.9979 -776.9815 -123.4352 2460.0 3.45 0.05 300.58 0.99 1.65031 0.00180 44.88231 0.00000 0.00000 0.0nog_le_pt402 401 38.8549 -105.9952 -773.2592 -88.3149 3000.0 3.05 0.01 295.37 0.00 0.00000 0.00000 21.46675 0.00000 0.00000 0.0

nog_le_pt403 402 39.2531 -106.0402 -772.7422 -44.1205 3230.0 3.05 0.01 295.37 0.00 0.00000 0.00000 40.01020 0.00000 0.00000 0.0nog_le_pt404 403 39.5295 -106.0407 -769.7495 -13.7059 2987.0 3.05 0.01 295.37 0.00 0.00000 0.00000 7.15052 0.00000 0.00000 0.0

nog_le_pt405 404 39.5725 -106.0836 -772.9155 -8.6108 2896.0 7.32 0.37 702.59 34.93 0.04640 0.12372 0.09155 0.00000 0.00000 0.0

nog_le_pt406 405 39.6827 -106.1033 -773.3676 3.6810 2934.0 3.05 0.01 295.37 0.00 0.00000 0.00000 59.74594 0.00000 0.00000 0.0

nog_le_pt407 406 39.8626 -106.0898 -770.2381 23.3593 3003.0 5.49 0.21 733.15 21.64 7.58178 0.07290 0.00335 0.00000 0.00000 0.0

nog_le_pt408 407 40.0425 -106.0913 -768.3780 43.1661 2987.0 4.60 0.08 295.09 0.91 0.00000 0.00000 12.23984 0.00000 0.00000 0.0

nog_le_pt409 408 37.1446 -105.5989 -757.1664 -279.9119 2346.0 4.16 0.11 295.19 2.32 0.00000 0.00000 13.29542 0.00000 0.00000 0.0

nog_le_pt410 409 38.4351 -105.7932 -760.4338 -136.2153 2524.0 3.05 0.01 295.37 0.00 0.00000 0.00000 11.19802 0.00000 0.00000 0.0
Table D-1 CALPUFF Model Inputs: 2018 Non-Project Point Sources Less Than 100 TPY 

Source_ID Grid Cell Assignment Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (

nog_le_pt411 410 39.1908 -105.9719 -767.6020 -51.5539 3048.0 3.05 0.01 295.37 0.00 0.00000 0.00000 17.15354 0.00000 0.00000 0.0nog_le_pt412 411 39.2417 -105.9742 -767.2433 -45.9340 3108.0 3.05 0.01 295.37 0.00 0.00000 0.00000 20.84909 0.00000 0.00000 0.0nog_le_pt413 412 39.5184 -105.9528 -762.4105 -15.6682 3379.0 3.05 0.01 295.37 0.00 0.00000 0.00000 44.32122 0.00000 0.00000 0.0nog_le_pt414 413 39.6079 -105.9949 -765.0061 -5.4665 3031.0 3.13 0.01 296.20 0.06 0.02889 0.00340 32.06373 0.00000 0.00000 0.0nog_le_pt415 414 40.6134 -106.0968 -762.5316 106.0350 2650.0 3.05 0.01 295.37 0.00 0.00000 0.00000 13.48963 0.00000 0.00000 0.0nog_le_pt416 415 37.1900 -105.5600 -753.2789 -275.2350 2377.0 3.05 0.03 295.28 1.94 0.00000 0.00000 1.35910 0.00000 0.00000 0.0

nog_le_pt417 416 38.3444 -105.5955 -744.3355 -147.8354 2438.0 3.05 0.01 295.37 0.00 0.00000 0.00000 2.20507 0.00000 0.00000 0.0

nog_le_pt418 417 38.3942 -105.6302 -746.8092 -142.0688 2255.0 3.05 0.01 295.37 0.00 0.00000 0.00000 9.44109 0.00000 0.00000 0.0

nog_le_pt419 418 39.0108 -105.7038 -746.6389 -73.5958 2743.0 3.05 0.01 295.37 0.00 0.00000 0.00000 5.69765 0.00000 0.00000 0.0

nog_le_pt420 419 39.7372 -105.8481 -751.1709 7.5373 3810.0 14.31 0.84 294.43 12.99 62.88848 2.47672 27.38395 0.00000 0.00000 0.0

nog_le_pt421 420 39.9717 -105.8625 -749.8647 33.4638 2621.0 10.18 0.26 294.26 3.58 0.00000 0.00000 1.26166 0.00000 0.00000 0.0

nog_le_pt422 421 40.0603 -105.9280 -754.4279 43.7566 2593.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.86499 0.00000 0.00000 0.0nog_le_pt423 422 40.1051 -105.9115 -752.5531 48.5501 2619.0 10.76 0.33 294.26 5.44 0.00000 0.00000 5.41475 0.00000 0.00000 0.0

nog_le_pt424 423 40.2936 -105.8536 -745.6514 68.8194 3048.0 3.05 0.01 295.37 0.00 0.00000 0.00000 0.26696 0.00000 0.00000 0.0

nog_le_pt425 424 37.4290 -105.4575 -741.8282 -249.7556 2442.0 7.45 0.22 298.37 2.93 0.00000 0.00000 74.99327 0.00000 0.00000 0.0

nog_le_pt426 425 38.1398 -105.5258 -740.4370 -170.9292 2399.0 3.05 0.01 295.37 0.00 0.00000 0.00000 9.92920 0.00000 0.00000 0.0

nog_le_pt427 426 38.6301 -105.4896 -732.2450 -117.2442 2438.0 3.05 0.01 295.37 0.00 0.00000 0.00000 1.49738 0.00000 0.00000 0.0

nog_le_pt428 427 39.7611 -105.7022 -738.5700 8.9719 2893.0 12.04 0.34 294.26 6.83 0.51560 0.00000 18.36310 0.00000 0.00000 0.0nog_le_pt429 428 37.9938 -105.3483 -726.5467 -188.4378 2630.0 3.05 0.01 295.37 0.00 0.00000 0.00000 10.37367 0.00000 0.00000 0.0

nog_le_pt430 429 38.0936 -105.3813 -728.3941 -177.1838 2721.0 3.05 0.01 295.37 0.00 0.00000 0.00000 12.49782 0.00000 0.00000 0.0

nog_le_pt431 430 38.4919 -105.3865 -724.7860 -133.2861 1889.0 12.74 0.82 294.28 12.83 0.00000 0.00000 49.74457 0.00000 0.00000 0.0

nog_le_pt432 431 38.8919 -105.4963 -730.1188 -88.3695 2743.0 3.05 0.01 295.37 0.00 0.00000 0.00000 10.51784 0.00000 0.00000 0.0

nog_le_pt433 432 39.7430 -105.5251 -723.7713 5.5545 2591.0 6.39 6.08 1039.72 0.09 0.22320 0.12411 0.07465 0.00000 0.00000 0.0

nog_le_pt434 433 40.8251 -105.6144 -720.0030 125.4059 2560.0 3.05 0.01 295.37 0.00 0.00000 0.00000 3.12053 0.00000 0.00000 0.0
Table D-2 CALPUFF Model Inputs: 2018 Non-Project Point Sources Greater Than 100 TPY 

Source ID Plant Name Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2(TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) 

nog_gr_pt1 QUESTAR_ROCK SPRINGS COMPLEX 41.5208 -109.3149 -1017.2877 237.2623 2012.0 5.82 1.49 731.35 15.94 101.5751 0.0000 0.0000 0.0000 0.0000 nog_gr_pt2 Bonnett-Geothermal Power Plant 38.3988 -113.0100 -1380.2451 -55.1514 1558.0 13.33 0.68 416.94 9.07 0.5090 0.0332 101.4372 0.0000 0.0000 nog_gr_pt3 EXXON MOBIL CORPORATION -PICEANCE CREEK 39.8938 -108.1944 -947.3331 46.6775 2286.0 8.87 0.31 480.88 27.71 100.9692 0.2369 0.9107 0.0000 0.0000 

nog_gr_pt4 PacifiCorp Lakeside Plant 40.3286 -111.7533 -1238.4078 137.0846 1455.0 45.72 5.49 354.70 14.59 94.5011 2.6000 5.2000 0.0000 0.0000 

nog_gr_pt5 Rubber Hose Manufacturing Facility 39.7251 -111.8108 -1254.0202 72.0169 2072.0 20.85 0.89 466.75 11.86 16.9995 19.7272 58.0050 8.8735 0.0887 nog_gr_pt6 Pump Mesa C.S. 36.7649 -107.7321 -949.1660 -301.6611 1937.0 6.10 0.30 650.37 45.72 104.3924 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt7 COLORADO INTERSTATE GAS CO GREASEWOOD 39.9017 -108.1912 -946.9564 47.5111 2258.0 8.05 0.89 708.44 10.36 104.3283 0.1984 0.2444 0.0000 0.0000 

nog_gr_pt8 ExxonMobile, McElmo Creek Plant 37.2601 -109.2054 -1071.3942 -230.9270 1524.0 3.05 0.01 295.37 0.00 10.0315 95.1592 0.0000 0.0000 0.0000 nog_gr_pt9 Rattlesnake Compressor Station 36.8606 -107.7371 -948.3579 -291.0931 1950.0 13.72 0.21 836.29 45.69 105.4328 0.0000 0.0000 0.0108 0.0000 

nog_gr_pt10 AMERICAN SODA LLP - PARACHUTE FACILITY 39.4806 -108.0855 -943.7229 0.1980 2072.0 17.67 0.69 331.13 9.18 31.6495 0.2269 73.9851 0.0000 0.0000 

nog_gr_pt11 Santaquin Pit 40.0350 -111.6226 -1232.7338 103.2619 2464.0 13.38 0.68 417.59 9.12 9.8284 1.6528 94.6782 0.0000 0.0000 

nog_gr_pt12 MOUNTAIN COAL CO. LLC (WEST ELK MINE) 38.9242 -107.4461 -896.5934 -67.3657 2499.0 3.05 0.01 295.37 0.00 0.0000 0.0000 107.2450 0.0000 0.0000 nog_gr_pt13 Petroleum Products Refining 40.8675 -111.9111 -1241.7988 198.0520 1519.0 10.48 0.33 467.84 12.28 110.9724 1.8978 0.0393 0.2154 0.0011 

nog_gr_pt14 NORTH OPERATIONS CENTER 40.7654 -111.9232 -1244.6438 187.0751 1379.0 4.67 0.14 424.02 9.39 113.8439 0.0460 0.0192 0.0133 0.0000 nog_gr_pt15 CHEVRON USA _ PAINTER RESERVOIR EAST 41.3112 -110.8650 -1147.9218 232.7738 2320.0 17.96 0.44 573.35 17.66 118.7083 0.2004 0.0505 0.0000 0.0000 nog_gr_pt16 32-7 CDP Compressor Station 36.8794 -107.6363 -939.2527 -290.0741 1968.0 6.71 0.30 699.93 45.55 120.2920 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt17 SENECA COAL COMPANY 40.4197 -107.1255 -850.8047 93.8619 2448.0 3.24 0.03 295.77 0.25 0.0000 0.0000 120.4384 0.0000 0.0000 

nog_gr_pt18 Western Fiberglass - Salt Lake City Plan 40.7514 -111.9941 -1250.7578 186.5209 1295.0 13.83 0.88 326.27 17.96 22.9467 11.7111 8.0881 77.8267 1.5566 

nog_gr_pt19 EL PASO NATURAL GAS CO FLORIDA RIVER CS 37.1321 -107.7943 -949.8268 -260.6673 2022.0 12.26 1.01 785.63 56.46 119.7083 0.4438 0.4792 0.0000 0.0000 

nog_gr_pt20 Power Plant 40.6548 -111.8072 -1237.0396 173.4208 2728.0 14.65 0.80 641.66 31.01 117.8217 2.5244 0.3621 1.4376 0.1204 

nog_gr_pt21 WILLIAMS FIELD SVCS PLA 9 STA 37.0030 -107.9233 -962.8362 -273.4910 2087.0 5.99 0.28 600.90 32.10 121.7839 0.3194 0.2589 0.0000 0.0000 

nog_gr_pt22 San Arroyo Plant 39.4000 -109.1247 -1032.8740 2.6601 2133.0 8.48 0.38 713.93 32.92 122.5818 0.0740 0.0000 0.3776 0.0102 nog_gr_pt23 Altamont Main Gas Processing Plant 40.3578 -110.3272 -1119.1334 121.7771 1961.0 10.87 0.35 636.86 26.55 119.7360 0.0000 0.2217 3.6949 0.0000 

nog_gr_pt24 Altamont South Compressor Station 40.2719 -110.4350 -1129.5193 113.7136 1905.0 9.31 0.34 661.88 12.68 118.5888 0.0000 0.1324 6.2017 0.0000 nog_gr_pt25 Pipe Casting Plant 40.1978 -111.6319 -1230.6249 121.1587 2743.0 29.83 0.93 461.47 21.80 49.9748 45.0063 29.9824 0.0000 0.0000 

nog_gr_pt26 Detergent Manufacturing 40.7292 -111.9750 -1249.5818 183.8358 1296.0 13.38 0.68 417.59 9.12 22.9210 0.0988 105.7784 3.8454 0.0000 nog_gr_pt27 CANYON GAS RESOURCES-FOUNDATION CREEK 39.6734 -108.7921 -1000.7904 28.9075 2732.0 4.63 1.31 431.40 3.40 133.9353 0.2175 0.1511 0.0000 0.0000 

nog_gr_pt28 Gobernador - Manzanares Compressor Stati 36.7610 -107.6465 -941.6807 -302.9802 2011.0 12.19 0.61 677.59 45.72 134.8927 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt29 CATALYST MANUFACTURE FACILITY 40.7362 -111.9590 -1248.1319 184.3797 1302.0 10.61 0.14 306.30 390.51 112.3226 9.1839 5.4558 9.5689 0.0805 

nog_gr_pt30 Bountiful Sanitary Landfill 40.9101 -111.9233 -1242.0353 202.8679 1329.0 12.60 0.63 408.35 8.43 9.5887 0.9589 104.8061 24.1966 0.0895 

nog_gr_pt31 NUCLEAR FUEL SERVICE 37.6870 -110.7160 -1195.9429 -165.3399 1354.0 11.28 0.30 422.04 26.36 115.1174 19.5702 1.4965 3.5917 2.6618 

nog_gr_pt32 Plant #12 (Geneva Slag Operations) 40.3139 -111.7467 -1238.1213 135.3903 1451.0 3.05 0.01 295.37 0.00 45.5870 4.3745 40.5401 50.1575 1.3565 

nog_gr_pt33 Salt Lake Operations 40.6668 -112.0804 -1259.4364 178.4828 1464.0 16.63 0.56 671.16 7.66 102.1764 0.9323 35.9618 6.8451 0.1399 

nog_gr_pt34 Bloomfield Compressor Station 36.7280 -107.9481 -968.6686 -303.4362 1767.0 15.24 1.22 755.37 8.14 147.5257 0.0000 0.0867 0.1373 0.0000 

nog_gr_pt35 WEST TEXAS - PICEANCE CREEK GP 39.8981 -108.1920 -947.0726 47.1244 2264.0 7.59 0.31 731.33 41.10 148.8353 0.0975 0.0322 0.0000 0.0000 

nog_gr_pt36 NATURAL SODA, INC. 39.9433 -108.3882 -962.9642 54.1459 2021.0 21.15 1.19 428.75 4.32 66.6264 0.2935 83.0324 0.0000 0.0000 

nog_gr_pt37 Pump Canyon Compressor Station 36.7947 -107.7330 -948.8567 -298.3771 1893.0 16.15 0.61 677.59 45.72 150.2030 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt38 COLORADO INTERSTATE GAS_LARAMIE COMP STN 41.4341 -105.9348 -740.0838 195.0456 2226.0 13.15 0.96 684.62 19.48 153.4812 0.0000 0.0000 0.0000 0.0000 nog_gr_pt39 Middle Mesa CDP 36.7649 -107.7321 -949.1660 -301.6611 1937.0 6.71 0.30 644.82 45.72 155.0869 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt40 CLIMAX MINE / MILL 39.3681 -106.1834 -783.6586 -30.2427 4206.0 16.04 1.13 287.08 18.52 14.1050 0.0507 143.7881 0.0000 0.0000 

nog_gr_pt41 CANYON GAS RESOURCES - RIFLE C.S. 39.5310 -107.8298 -921.3967 3.1064 1660.0 4.97 0.19 498.86 21.05 159.8956 0.0598 0.0494 0.0000 0.0000 

nog_gr_pt42 Thompson Compressor Station 36.8312 -107.9954 -971.4549 -291.5947 1798.0 10.40 0.35 643.22 35.21 163.0152 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt43 Bluffview Power Plant 36.7143 -108.2144 -992.2987 -302.0679 1733.0 21.34 3.96 368.71 11.31 99.1012 11.2000 0.0000 56.9991 0.0000 

nog_gr_pt44 Steel Manufacturing Facility 40.2909 -111.7049 -1235.0523 132.3112 1470.0 28.90 2.86 438.91 14.68 72.5095 75.6516 11.8921 7.9719 0.0558 nog_gr_pt45 MOFFAT COUNTY ROAD DEPARTMENT 40.6372 -107.6292 -890.1328 122.5863 2134.0 12.95 0.84 316.48 13.11 0.0000 0.0000 171.2288 0.0000 0.0000 

nog_gr_pt46 East Carbon Landfill 39.5316 -110.4594 -1143.6357 33.0510 1898.0 5.22 0.15 321.03 1.91 124.2102 12.8183 24.6094 11.7984 0.0000 

nog_gr_pt47 ARCH OF WY_MEDICINE BOW MINE 41.7038 -106.9229 -818.3677 233.2067 2073.0 3.05 0.01 295.37 0.00 0.0000 0.0000 112.9164 60.6630 0.8917 

nog_gr_pt48 Main Campus 40.2469 -111.6469 -1231.0041 126.7215 2621.0 41.95 2.50 470.59 3.22 73.8389 99.7577 0.1983 0.5628 0.1230 

nog_gr_pt49 CLIMAX MOLYBDENUM AMAX HENDERSON MILL 39.8457 -106.0796 -769.5631 21.4135 3048.0 5.68 0.22 294.36 6.92 56.7028 46.9755 74.0013 0.0000 0.0000 

nog_gr_pt50 QUESTAR GAS MANAGEMENT COMPANY 40.9494 -108.3138 -942.8881 163.7744 2072.0 8.77 0.22 801.12 39.87 180.2587 0.0707 0.0932 0.0000 0.0000 

nog_gr_pt51 RADIOACTIVE MATERIAL DISPOSAL SITE 40.6881 -113.1137 -1344.4398 195.6078 1407.0 3.05 0.01 295.37 0.00 130.8095 13.0428 35.2800 13.7176 5.7625 

nog_gr_pt52 PacifiCorp Currant Creek Plant 39.8195 -111.8926 -1259.1812 83.4473 1537.0 50.29 5.12 369.26 15.56 127.0018 7.3000 59.3019 0.0000 0.0000 nog_gr_pt53 TWENTYMILE COAL CO.- FOIDEL CREEK 40.3458 -107.0750 -847.4831 85.2674 2316.0 3.05 0.01 295.37 0.00 0.0000 0.0000 193.9744 0.0000 0.0000 

nog_gr_pt54 El Cedro Gas Plant 36.7379 -107.6233 -939.9361 -305.7591 2072.0 7.83 1.45 731.98 26.88 195.3046 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt55 Gadsby Power Plant 40.7670 -111.9288 -1245.0777 187.3265 1377.0 70.44 3.11 434.21 23.79 173.9098 2.4996 17.5823 1.3201 0.0222 nog_gr_pt56 TRI-STATE GENERATION & TRANS.-RIFLE STAT 39.5184 -107.7191 -912.1862 0.6062 1752.0 15.94 3.23 358.85 21.54 189.5187 0.8442 8.5773 0.0000 0.0000 nog_gr_pt57 Main Base 41.1170 -111.9769 -1242.7007 226.1812 1507.0 13.23 0.70 414.21 8.85 143.1693 2.6422 36.2522 18.3977 1.1753 

nog_gr_pt58 OLDCASTLE SW GROUP DBA UNITED CO OF MESA 38.9307 -108.2699 -966.8621 -58.2059 2236.0 4.50 0.19 307.64 1.00 9.6743 10.2021 183.7948 0.0000 0.0000 nog_gr_pt59 AE STALEY MFG CO 37.5839 -106.0944 -795.8004 -227.3137 2311.0 6.70 0.36 305.98 18.98 36.1233 126.7156 47.8595 0.0000 0.0000 

nog_gr_pt60 UMETCO MINERALS CORP 38.6595 -108.6331 -1001.6820 -84.0209 2750.0 3.05 0.01 295.37 0.00 0.0000 0.0000 212.1614 0.0000 0.0000 

nog_gr_pt61 COLORADO INTERSTATE GAS_RAWLINS COMP 41.7542 -107.0551 -828.6104 239.9496 2011.0 9.56 0.72 655.62 33.44 215.8242 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt62 La Jara Compressor Station 36.7066 -107.9786 -971.6395 -305.4616 1707.0 6.91 0.75 691.02 49.31 218.3753 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt63 AMERICAN GYPSUM COMPANY 39.6506 -106.9357 -844.2010 7.5592 2092.0 13.94 0.72 501.50 12.04 148.4941 0.4082 69.9832 0.0000 0.0000 nog_gr_pt64 Grantsville Plant 40.7000 -112.5750 -1299.7178 189.0671 1281.0 16.74 1.35 439.44 5.36 87.1885 6.2775 98.3092 33.5972 0.3925 

nog_gr_pt65 Geneva Nitrogen Plant 40.3183 -111.7350 -1237.0690 135.7112 1496.0 21.13 2.23 420.07 13.60 173.6273 0.0115 27.2946 25.6603 0.0282 

nog_gr_pt66 Delta Mill 39.5000 -112.4160 -1308.9814 56.0045 1471.0 12.59 1.01 478.44 2.86 39.4967 166.1962 14.0231 9.3067 0.3552 nog_gr_pt67 SENECA COAL CO 40.3886 -107.1920 -856.7540 91.0686 2377.0 3.05 0.01 295.37 0.00 0.0000 0.0000 232.6156 0.0000 0.0000 

nog_gr_pt68 Riverbend Field 40.1008 -109.7070 -1071.3624 86.1717 1463.0 3.05 0.01 295.37 0.00 55.6264 0.2697 29.2635 148.0836 0.0000 nog_gr_pt69 Moab Compressor Station 38.3264 -109.4266 -1074.6154 -111.4665 2023.0 11.36 0.52 704.36 3.60 236.2033 0.0000 0.0186 0.0927 0.0000 nog_gr_pt70 Brick Manufacturing Plant 40.5943 -112.0298 -1256.5694 169.8730 1411.0 21.09 1.77 369.94 10.92 32.0769 79.0940 119.3620 9.7969 0.0308 

nog_gr_pt71 Desert Power Plant 40.9133 -112.7344 -1308.8222 214.6005 1280.0 12.19 3.73 779.26 7.92 240.3598 1.1588 0.0683 0.0864 0.0000 nog_gr_pt72 SENECA COAL CO SENECA II W 40.3841 -107.2425 -861.0372 91.0513 2432.0 3.05 0.01 295.37 0.00 0.0000 0.0000 251.0324 0.0000 0.0000 

nog_gr_pt73 Point of the Mountain Facility 40.5008 -111.9077 -1248.1422 157.9888 1447.0 9.48 0.74 412.17 7.53 74.6563 70.3699 81.4168 27.0485 0.1277 

nog_gr_pt74 BP AMERICA PRODUCTION CO. [MISC. ENGINES 37.0147 -107.8103 -952.7695 -273.3967 2161.0 10.94 0.68 294.26 15.11 270.0599 0.2161 0.1657 0.0000 0.0000 

nog_gr_pt75 Hazardous Waste Storage/Incineration 40.7344 -112.9680 -1331.5141 198.5045 1915.0 13.38 0.68 417.59 9.12 212.2137 63.8720 4.4096 1.9628 0.0637 

nog_gr_pt76 COLORADO LIME COMPANY DBA CALCO 38.5368 -105.9874 -776.0636 -123.3819 2635.0 8.58 1.27 435.34 9.79 91.6477 120.5529 83.2927 0.0000 0.0000 

nog_gr_pt77 WILLIAMS PROD. RMT CORP. - PARACHUTE 39.4856 -108.1088 -945.6292 0.9890 2255.0 3.20 0.03 306.03 0.67 293.4218 0.7647 2.5132 0.0000 0.0000 

nog_gr_pt78 EL PASO NATURAL GAS CO BONDAD COMP STA 37.0849 -107.8218 -952.8555 -265.5644 2237.0 10.00 1.46 693.40 3.52 299.8110 0.6911 0.7462 0.0000 0.0000 

nog_gr_pt79 Payson City Power 40.0439 -111.7377 -1242.1934 105.8006 1420.0 11.58 0.67 649.03 12.45 296.7873 5.1056 0.1731 2.8557 0.2482 

nog_gr_pt80 AMERICAN SODA LLP - PICEANCE FACILITY 39.9522 -108.2969 -955.1620 54.1589 1986.0 30.31 1.78 364.04 20.23 116.3083 1.8210 196.9203 0.0000 0.0000 

nog_gr_pt81 Milagro Gas Plant 36.7066 -107.9786 -971.6395 -305.4616 1707.0 21.47 2.61 451.69 20.02 303.2506 0.0000 1.5296 22.0032 0.0000 

nog_gr_pt82 Shale Processing 40.7558 -111.4027 -1201.7707 179.0210 2072.0 13.38 0.68 417.59 9.12 182.4562 121.8644 19.3572 14.1428 0.0786 

nog_gr_pt83 BOWIE RESOURCES, LLC - BOWIE NO 2 MINE 38.9316 -107.5474 -905.1544 -65.5488 2276.0 16.41 0.57 294.39 8.40 0.0000 0.0000 352.1651 0.0000 0.0000 

nog_gr_pt84 Salt Lake Valley Landfill & Transfer Sta 40.7403 -112.0319 -1254.0843 185.8307 1290.0 13.38 0.68 417.59 9.12 0.5483 0.0360 270.0287 89.4968 0.3348 

nog_gr_pt85 NORTHWEST PIPELINE CORP RANGELY STA 40.0489 -108.7731 -993.8228 69.8726 1828.0 4.33 0.59 672.04 11.15 405.9424 0.9500 0.0777 0.0000 0.0000 

nog_gr_pt86 Kastler/Marushack Compressor Station 40.9958 -109.2110 -1016.5390 178.5372 2256.0 13.93 0.62 672.36 34.78 484.6239 0.0000 0.0000 0.1678 0.0000 

nog_gr_pt87 County Landfill & Energy Recovery Facili 41.0824 -111.9812 -1243.6824 222.4639 1419.0 36.87 1.18 483.55 22.71 408.7430 45.0505 24.7416 11.6990 0.1300 

nog_gr_pt88 Flying J Refinery (Big West Oil Co.) 40.8647 -111.9066 -1241.4780 197.6849 1553.0 20.50 0.76 760.60 14.32 316.7364 261.4133 0.3288 4.0960 0.0226 

nog_gr_pt89 ChevronTexaco, Aneth Natural Gas Process 37.2577 -109.3273 -1082.0651 -229.7458 1402.0 3.05 0.01 295.37 0.00 324.4780 260.5001 0.0875 0.0000 0.0000 nog_gr_pt90 TRAPPER MINING INC 40.4215 -107.5823 -888.9948 98.4324 2316.0 3.05 0.01 295.37 0.00 0.0000 0.0000 597.7207 0.0000 0.0000 

nog_gr_pt91 BP AMERICA _ ANSCHUTZ RANCH EAST 41.0736 -111.0403 -1166.3659 209.0263 2240.0 15.31 3.32 552.93 18.41 654.1501 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt92 San Juan Refinery (Bloomfield) 36.6997 -107.9741 -971.3351 -306.2677 1723.0 29.33 1.23 648.29 6.23 233.5747 475.9683 0.1616 1.0607 0.0011 

nog_gr_pt93 UNION PAC_BRADY 41.3854 -108.7437 -972.3033 216.1567 2316.0 17.30 0.56 743.17 19.27 537.9226 181.1999 0.0000 0.0000 0.0000 nog_gr_pt94 ENCANA OIL & GAS (USA), INC-DRAGON TRAIL 39.8300 -108.8089 -999.9644 46.2628 1950.0 7.12 0.33 658.49 22.08 718.9993 0.4631 0.2854 0.0000 0.0000 

nog_gr_pt95 U.S. Army-Dugway Proving Ground 40.1769 -112.9377 -1339.7718 137.3471 1331.0 13.38 0.68 417.59 9.12 16.2163 27.6292 715.9273 114.2392 0.2220 
Table D-2 CALPUFF Model Inputs: 2018 Non-Project Point Sources Greater Than 100 TPY 

Source ID Plant Name Latitude Longitude LCC_X LCC_Y Base Elev (m) Stk Ht (m) Stk Dm (m) Stk Tmp (K) Stk Vel (m/s) NOX (TPY) SO2(TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) 

nog_gr_pt96 Chevron USA - Whitney Canyon/Carter Cree 41.2890 -110.5580 -1123.0606 226.5094 2266.0 3.05 0.01 295.37 0.00 0.0000 876.0000 0.0000 0.0000 0.0000 nog_gr_pt97 Phillips Refinery 40.8860 -111.9000 -1240.5487 199.9194 1516.0 24.48 1.10 671.68 20.06 304.2130 566.9973 2.0375 3.9107 0.0000 nog_gr_pt98 Valverde Gas Plant 36.7317 -107.9563 -969.3414 -302.9423 1767.0 18.56 1.09 643.11 6.53 835.8156 0.0000 49.2303 0.0000 0.0000 

nog_gr_pt99 Rowley Plant 40.9141 -112.7318 -1308.5929 214.6503 1280.0 44.66 1.85 341.82 11.64 540.5286 37.2827 364.0036 0.3470 0.0000 

nog_gr_pt100 Kutz Gas Plant 36.7066 -107.9786 -971.6395 -305.4616 1707.0 7.97 0.70 662.11 32.39 969.7685 0.0000 0.0000 0.0000 0.0000 

nog_gr_pt101 San Juan Plant Gas Plant 36.7314 -107.9596 -969.6359 -302.9401 1767.0 13.12 2.39 602.39 16.59 1005.4961 38.2566 0.2948 0.5452 0.0000 

nog_gr_pt102 San Juan River Gas Plant 36.7591 -108.3652 -1004.9546 -295.4914 1645.0 47.40 0.73 719.67 11.77 370.5377 734.7961 0.0000 0.0000 0.0000 nog_gr_pt103 WILLIAMS FIELD SERVICES IGNACIO B PLT 37.1422 -107.7851 -948.8888 -259.6539 2013.0 10.53 1.20 698.06 25.22 1172.8311 1.2958 1.9576 0.0000 0.0000 

nog_gr_pt104 Sunnyside Cogeneration Facility 39.5472 -110.3916 -1137.6634 33.9061 2452.0 73.89 2.52 421.89 27.06 442.4847 715.2940 31.0459 31.4343 0.9149 

nog_gr_pt105 COLOWYO COAL CO 40.2656 -107.8083 -909.9377 83.5467 2195.0 8.44 0.15 295.14 1.95 0.0000 0.0000 1288.3802 0.0000 0.0000 nog_gr_pt106 Salt Lake City Refinery 40.7915 -111.9028 -1242.4863 189.6443 1767.0 51.90 1.89 529.79 11.75 550.7843 717.7626 55.4321 10.1863 0.4632 

nog_gr_pt107 SOLVAY MINERALS, INC. 41.5093 -109.6086 -1041.5711 239.3285 2026.0 52.06 2.36 619.65 17.07 1110.7947 23.8234 229.9132 0.0000 0.0000 

nog_gr_pt108 Blanco Compressor Station - A,C,D Plants 36.7315 -107.9608 -969.7402 -302.9163 1767.0 12.83 1.48 536.74 26.63 1381.9612 1.4778 0.6970 0.0000 0.0000 

nog_gr_pt109 Future Coal EGU (NEVCO Energy Co.) 38.7590 -111.7870 -1269.3277 -33.7216 2474.0 3.05 0.01 295.37 0.00 1005.2100 226.1358 154.8038 0.0000 0.0000 

nog_gr_pt110 P4 PRODUCTION_ROCK SPRINGS FACILITY 41.5498 -109.2249 -1009.4678 239.4389 2073.0 37.60 0.95 1202.15 7.32 303.8370 1007.5460 81.8668 0.0000 0.0000 

nog_gr_pt111 Salt Lake Refinery 40.8434 -111.9184 -1242.8370 195.5216 1706.0 46.20 1.14 602.26 6.03 695.7515 1267.7080 70.8107 4.7976 0.6944 nog_gr_pt112 Devil's Slide Plant 41.0511 -111.5338 -1207.4146 213.0130 1951.0 76.62 2.93 508.39 8.69 1746.0140 83.0010 359.6855 60.9178 1.8438 

nog_gr_pt113 Smelter & Refinery 40.7172 -112.1996 -1268.3706 185.6382 1608.0 300.71 6.03 340.28 10.45 263.8168 1690.1071 73.1245 291.8308 0.8234 nog_gr_pt114 Lisbon Natural Gas Processing Plant 37.1500 -109.0500 -1059.4440 -244.8207 1494.0 57.99 1.64 728.35 0.60 269.3469 2118.6060 6.1720 0.8449 0.0000 nog_gr_pt115 Chaco Gas Plant 36.7066 -107.9786 -971.6395 -305.4616 1707.0 16.44 1.63 672.38 35.39 2505.4674 3.7563 0.1119 0.2456 0.0000 

nog_gr_pt116 Leamington Cement Plant 39.5625 -112.1972 -1289.4274 59.6894 1746.0 28.70 4.57 380.42 10.15 2345.5821 2.9287 29.9552 196.1980 1.6821 nog_gr_pt117 Simplot Phosphates 41.5378 -109.1282 -1001.7072 237.0528 2014.0 58.79 0.52 323.30 6.65 175.6384 2370.3865 78.9787 0.0000 0.0000 nog_gr_pt118 Cricket Mountain Plant 38.9439 -112.8252 -1354.0327 1.4187 1453.0 45.32 1.88 446.91 16.95 1880.9957 460.5816 124.1804 272.3829 3.6708 nog_gr_pt119 Mine & Copperton Concentrator 40.5333 -112.1500 -1267.6454 164.8882 2077.0 13.44 0.68 417.31 9.12 3.1004 5.0000 2498.2702 510.3927 1.2791 

nog_gr_pt120 TRI STATE GENERATION NUCLA 38.2418 -108.5088 -996.8702 -131.2010 1831.0 64.22 3.57 413.69 22.10 1759.8051 1359.8093 108.8756 0.0000 0.0000 

nog_gr_pt121 BLACK BUTTE COAL CO- BLACK BUTTE MINE 41.5730 -108.6950 -965.6293 236.2260 2073.0 15.85 1.52 370.93 37.49 0.0000 0.0000 2517.5510 1049.5575 15.4286 

nog_gr_pt122 Power Plt/ Lab/ Tailings Impoundment 40.7000 -112.1166 -1261.8237 182.6066 1329.0 44.73 3.62 419.60 5.43 2054.2367 1958.7973 147.6053 88.9765 0.9297 

nog_gr_pt123 Carbon Power Plant 39.7269 -110.8641 -1174.4778 59.5640 2499.0 52.34 3.80 435.55 23.43 3367.4171 6978.8154 134.5813 86.1894 0.8720 

nog_gr_pt124 PUBLIC SERVICE CO HAYDEN PLT 40.4880 -107.1996 -856.1589 102.0646 2012.0 140.37 5.55 419.53 20.51 7313.2421 2969.8540 309.8479 0.0000 0.0000 

nog_gr_pt125 BONANZA POWER PLANT 40.0908 -109.2902 -1036.5881 80.2422 1585.0 182.88 7.92 420.94 15.24 8407.6210 1649.5514 326.1056 562.7920 5.6352 

nog_gr_pt126 Huntington Power Plant 39.3802 -111.0767 -1198.2591 24.4563 2377.0 180.55 7.22 399.81 19.32 8574.1388 4048.6464 249.0823 405.2185 4.1196 

nog_gr_pt127 TRI STATE GENERATION CRAIG 40.4974 -107.6264 -891.7033 107.2019 1951.0 182.45 7.61 419.23 22.20 16821.1502 4036.7800 445.9507 0.0000 0.0000 

nog_gr_pt128 NAVAJO GENERATING STATION 36.9050 -111.3892 -1267.8017 -241.6894 1402.0 142.65 5.58 420.93 20.93 10610.6230 8565.9660 0.0000 2929.0155 29.2902 

nog_gr_pt129 Hunter Power Plant 39.1436 -111.0277 -1198.1434 -2.0382 1768.0 181.74 7.27 417.23 19.96 16503.4019 6493.4834 553.2928 495.5327 5.1323 

nog_gr_pt130 San Juan Generating Station 36.8318 -108.4608 -1012.3514 -286.4490 1655.0 120.47 7.53 418.19 28.75 19822.6464 11102.3522 326.1247 396.9375 3.9694 

nog_gr_pt131 Intermountain Generation Station 39.4391 -112.6557 -1330.2886 52.8496 1412.0 179.28 7.02 398.92 21.57 28210.8669 6923.8351 713.1262 205.9197 2.1957 

nog_gr_pt132 Four Corners Power Plant 36.7006 -108.4746 -1015.3921 -300.6979 1645.0 115.32 8.64 417.04 24.26 17513.1544 18386.4505 1689.6215 0.0000 0.0000 
Table D-3 CALPUFF Model Inputs: 2018 Non-Project Area Sources (State, Motor Vehicle and Nonroad Sources) 

Base Elevation Grid Cell Area 

name Grid Cell X1 (km) X2 (km) X3 (km) X4 (km) Y1 (km) Y2 (km) Y3 (km) Y4 (km) (m) (km2) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (TPY) 

nog-mg-n-area1 0 -1392.0 -1392.0 -1320.0 -1320.0 -312.0 -240.0 -240.0 -312.0 1592.0 5184.0 53.6912 3.1472 100.7607 16.7476 1.6561 3.2455 

nog-mg-n-area2 2 -1392.0 -1392.0 -1356.0 -1356.0 -240.0 -204.0 -204.0 -240.0 1451.0 1296.0 86.3398 16.4091 266.3005 61.6619 0.8325 1.0120 

nog-mg-n-area3 3 -1392.0 -1392.0 -1356.0 -1356.0 -204.0 -168.0 -168.0 -204.0 1867.0 1296.0 43.5360 13.4430 67.5546 10.5229 0.3161 0.3689 

nog-mg-n-area4 4 -1392.0 -1392.0 -1356.0 -1356.0 -168.0 -132.0 -132.0 -168.0 1963.0 1296.0 47.7887 41.9768 46.8299 9.5490 0.4474 0.6987 

nog-mg-n-area5 5 -1392.0 -1392.0 -1356.0 -1356.0 -132.0 -96.0 -96.0 -132.0 2998.0 1296.0 296.8084 59.1060 464.7435 90.4180 2.6019 2.6233 

nog-mg-n-area6 6 -1392.0 -1392.0 -1320.0 -1320.0 -96.0 -24.0 -24.0 -96.0 1948.0 5184.0 603.5845 171.8530 986.2444 202.9564 10.5910 16.5222 

nog-mg-n-area7 8 -1392.0 -1392.0 -1320.0 -1320.0 -24.0 48.0 48.0 -24.0 1828.0 5184.0 239.9586 66.4851 1360.2873 265.0579 3.1878 2.4572 

nog-mg-n-area8 10 -1392.0 -1392.0 -1320.0 -1320.0 48.0 120.0 120.0 48.0 1933.0 5184.0 40.3245 44.6220 355.2201 62.3078 0.6109 0.5473 

nog-mg-n-area9 12 -1392.0 -1392.0 -1320.0 -1320.0 120.0 192.0 192.0 120.0 1299.0 5184.0 25.3344 29.2512 81.9419 9.0906 0.1357 0.1951 

nog-mg-n-area10 14 -1392.0 -1392.0 -1320.0 -1320.0 192.0 240.0 240.0 192.0 1283.0 3456.0 322.8090 6.8658 112.9576 24.1154 2.8002 3.3889 

nog-mg-n-area11 18 -1356.0 -1356.0 -1320.0 -1320.0 -240.0 -204.0 -204.0 -240.0 1901.0 1296.0 38.8370 5.0936 55.6451 9.9641 0.4597 0.7006 

nog-mg-n-area12 19 -1356.0 -1356.0 -1320.0 -1320.0 -204.0 -168.0 -168.0 -204.0 1768.0 1296.0 8.2848 8.6842 41.1112 6.1417 0.1093 0.1313 

nog-mg-n-area13 20 -1356.0 -1356.0 -1320.0 -1320.0 -168.0 -132.0 -132.0 -168.0 2116.0 1296.0 62.5814 16.1269 49.6715 9.3407 1.0618 1.8239 

nog-mg-n-area14 21 -1356.0 -1356.0 -1320.0 -1320.0 -132.0 -96.0 -96.0 -132.0 2560.0 1296.0 86.2591 24.3525 129.6861 23.8216 1.3385 2.0387 

nog-mg-n-area15 32 -1320.0 -1320.0 -1248.0 -1248.0 -312.0 -240.0 -240.0 -312.0 1552.0 5184.0 269.4213 10.1921 729.2426 146.9919 3.5502 5.2224 

nog-mg-n-area16 34 -1320.0 -1320.0 -1284.0 -1284.0 -240.0 -204.0 -204.0 -240.0 1984.0 1296.0 31.7584 4.8288 39.6063 6.7189 0.3600 0.5570 nog-mg-n-area17 35 -1320.0 -1320.0 -1284.0 -1284.0 -204.0 -168.0 -168.0 -204.0 1673.0 1296.0 8.7926 6.9561 13.9760 1.5522 0.0894 0.1420 nog-mg-n-area18 36 -1320.0 -1320.0 -1284.0 -1284.0 -168.0 -132.0 -132.0 -168.0 1885.0 1296.0 17.4615 8.9591 56.0440 9.4360 0.9728 1.8857 

nog-mg-n-area19 37 -1320.0 -1320.0 -1284.0 -1284.0 -132.0 -96.0 -96.0 -132.0 2397.0 1296.0 22.3613 12.0793 69.2486 12.4657 1.5531 3.0725 

nog-mg-n-area20 38 -1320.0 -1320.0 -1284.0 -1284.0 -96.0 -60.0 -60.0 -96.0 2189.0 1296.0 173.9483 21.9406 182.6608 52.9537 18.1085 38.6951 

nog-mg-n-area21 39 -1320.0 -1320.0 -1284.0 -1284.0 -60.0 -24.0 -24.0 -60.0 2142.0 1296.0 322.0667 226.5219 661.7166 133.2579 4.3647 6.5292 

nog-mg-n-area22 40 -1320.0 -1320.0 -1248.0 -1248.0 -24.0 48.0 48.0 -24.0 2341.0 5184.0 682.9392 278.2939 1766.1389 353.1477 6.8655 7.0890 

nog-mg-n-area23 42 -1320.0 -1320.0 -1248.0 -1248.0 48.0 120.0 120.0 48.0 1464.0 5184.0 573.3788 157.9060 1713.5582 340.1046 5.2976 4.6892 

nog-mg-n-area24 44 -1320.0 -1320.0 -1248.0 -1248.0 120.0 192.0 192.0 120.0 1856.0 5184.0 5963.1564 277.7346 4367.1014 979.0101 127.6603 78.7171 

nog-mg-n-area25 46 -1320.0 -1320.0 -1248.0 -1248.0 192.0 240.0 240.0 192.0 1291.0 3456.0 424.4498 16.0463 1144.2150 228.8974 7.1625 9.4903 

nog-mg-n-area26 50 -1284.0 -1284.0 -1248.0 -1248.0 -240.0 -204.0 -204.0 -240.0 1341.0 1296.0 96.2462 10.3325 226.7514 57.3539 2.5949 5.7471 

nog-mg-n-area27 51 -1284.0 -1284.0 -1248.0 -1248.0 -204.0 -168.0 -168.0 -204.0 1524.0 1296.0 5.4644 6.5393 12.1527 1.1615 0.1329 0.2590 

nog-mg-n-area28 52 -1284.0 -1284.0 -1248.0 -1248.0 -168.0 -132.0 -132.0 -168.0 2194.0 1296.0 16.9056 5.5135 85.3649 14.9779 1.0827 2.0400 

nog-mg-n-area29 53 -1284.0 -1284.0 -1248.0 -1248.0 -132.0 -96.0 -96.0 -132.0 2316.0 1296.0 13.2409 8.7861 42.5357 8.6178 0.8027 1.5971 

nog-mg-n-area30 54 -1284.0 -1284.0 -1248.0 -1248.0 -96.0 -60.0 -60.0 -96.0 2723.0 1296.0 63.3063 43.2711 338.0005 65.7337 2.0124 3.4494 

nog-mg-n-area31 55 -1284.0 -1284.0 -1248.0 -1248.0 -60.0 -24.0 -24.0 -60.0 2131.0 1296.0 71.6371 19.0625 77.6766 15.0678 1.1843 1.9232 

nog-mg-n-area32 64 -1248.0 -1248.0 -1176.0 -1176.0 -312.0 -240.0 -240.0 -312.0 1764.0 5184.0 287.9578 4.6653 1455.3243 285.6240 2.6554 3.2783 

nog-mg-n-area33 66 -1248.0 -1248.0 -1212.0 -1212.0 -240.0 -204.0 -204.0 -240.0 1463.0 1296.0 7.9585 3.7915 17.2289 2.2236 0.2925 0.5654 

nog-mg-n-area34 67 -1248.0 -1248.0 -1212.0 -1212.0 -204.0 -168.0 -168.0 -204.0 1706.0 1296.0 6.5624 5.8140 16.2717 2.0180 0.2923 0.5845 

nog-mg-n-area35 68 -1248.0 -1248.0 -1212.0 -1212.0 -168.0 -132.0 -132.0 -168.0 1751.0 1296.0 8.6063 2.4222 11.3304 1.2155 0.8917 1.9054 

nog-mg-n-area36 69 -1248.0 -1248.0 -1212.0 -1212.0 -132.0 -96.0 -96.0 -132.0 2011.0 1296.0 17.6092 12.1933 73.8480 13.3021 0.7209 1.3457 

nog-mg-n-area37 70 -1248.0 -1248.0 -1212.0 -1212.0 -96.0 -60.0 -60.0 -96.0 2316.0 1296.0 26.7639 28.8225 67.0875 11.6896 0.2229 0.2590 

nog-mg-n-area38 71 -1248.0 -1248.0 -1212.0 -1212.0 -60.0 -24.0 -24.0 -60.0 2560.0 1296.0 131.4305 35.7106 116.1808 24.3100 1.2597 1.5776 

nog-mg-n-area39 72 -1248.0 -1248.0 -1176.0 -1176.0 -24.0 48.0 48.0 -24.0 2467.0 5184.0 444.5292 397.4797 1200.2119 230.7264 4.0440 4.2547 

nog-mg-n-area40 74 -1248.0 -1248.0 -1176.0 -1176.0 48.0 120.0 120.0 48.0 2207.0 5184.0 1314.3080 147.2378 2561.6641 519.9328 13.8789 17.4725 

nog-mg-n-area41 76 -1248.0 -1248.0 -1212.0 -1212.0 120.0 156.0 156.0 120.0 1367.0 1296.0 2224.4152 156.1927 3339.2244 646.2734 22.9468 26.2947 

nog-mg-n-area42 77 -1248.0 -1248.0 -1212.0 -1212.0 156.0 192.0 192.0 156.0 1804.0 1296.0 9215.9936 211.7524 3195.6298 876.8852 138.9689 93.9347 

nog-mg-n-area43 78 -1248.0 -1248.0 -1176.0 -1176.0 192.0 240.0 240.0 192.0 1323.0 3456.0 4396.5572 102.8561 3874.9262 844.4722 42.0532 53.1283 

nog-mg-n-area44 82 -1212.0 -1212.0 -1176.0 -1176.0 -240.0 -204.0 -204.0 -240.0 1920.0 1296.0 5.5966 2.5315 13.2108 0.6804 0.1557 0.2760 

nog-mg-n-area45 83 -1212.0 -1212.0 -1176.0 -1176.0 -204.0 -168.0 -168.0 -204.0 1463.0 1296.0 11.9117 4.0931 46.5921 9.3102 0.6204 1.2212 

nog-mg-n-area46 84 -1212.0 -1212.0 -1176.0 -1176.0 -168.0 -132.0 -132.0 -168.0 1584.0 1296.0 10.7975 2.4554 14.9425 1.9164 0.9140 1.9317 

nog-mg-n-area47 85 -1212.0 -1212.0 -1176.0 -1176.0 -132.0 -96.0 -96.0 -132.0 2024.0 1296.0 15.1917 14.2353 15.1487 2.0403 0.4971 1.0289 

nog-mg-n-area48 86 -1212.0 -1212.0 -1176.0 -1176.0 -96.0 -60.0 -60.0 -96.0 1785.0 1296.0 21.1797 20.9214 49.9800 8.6851 0.1523 0.1695 

nog-mg-n-area49 87 -1212.0 -1212.0 -1176.0 -1176.0 -60.0 -24.0 -24.0 -60.0 1950.0 1296.0 68.9913 12.7510 25.2619 4.3201 0.4593 0.4569 

nog-mg-n-area50 92 -1212.0 -1212.0 -1176.0 -1176.0 120.0 156.0 156.0 120.0 2316.0 1296.0 170.0898 8.2268 369.3683 73.3934 3.2209 5.0172 

nog-mg-n-area51 93 -1212.0 -1212.0 -1176.0 -1176.0 156.0 192.0 192.0 156.0 1767.0 1296.0 421.1255 12.6400 458.8524 91.9847 4.1918 4.5651 

nog-mg-n-area52 96 -1176.0 -1176.0 -1104.0 -1104.0 -312.0 -240.0 -240.0 -312.0 2255.0 5184.0 437.6795 11.4724 874.6312 189.6971 3.2692 3.8645 

nog-mg-n-area53 98 -1176.0 -1176.0 -1104.0 -1104.0 -240.0 -168.0 -168.0 -240.0 1645.0 5184.0 79.5918 15.4582 123.4878 18.4715 0.6598 0.7573 

nog-mg-n-area54 100 -1176.0 -1176.0 -1140.0 -1140.0 -168.0 -132.0 -132.0 -168.0 1448.0 1296.0 14.5274 3.1856 21.6579 2.9445 0.6187 1.2360 

nog-mg-n-area55 101 -1176.0 -1176.0 -1140.0 -1140.0 -132.0 -96.0 -96.0 -132.0 1512.0 1296.0 12.1815 17.7730 11.8032 1.3770 0.3453 0.7265 

nog-mg-n-area56 102 -1176.0 -1176.0 -1140.0 -1140.0 -96.0 -60.0 -60.0 -96.0 1465.0 1296.0 14.8436 17.6264 17.3020 2.0973 0.0723 0.0872 

nog-mg-n-area57 103 -1176.0 -1176.0 -1140.0 -1140.0 -60.0 -24.0 -24.0 -60.0 1638.0 1296.0 82.9654 11.7101 34.5490 6.3413 0.5482 0.5641 

nog-mg-n-area58 104 -1176.0 -1176.0 -1104.0 -1104.0 -24.0 48.0 48.0 -24.0 1828.0 5184.0 345.2742 161.0422 416.4887 78.8726 2.3475 2.6990 

nog-mg-n-area59 106 -1176.0 -1176.0 -1104.0 -1104.0 48.0 120.0 120.0 48.0 1829.0 5184.0 411.3845 101.0610 594.2503 113.8444 4.5803 6.1858 

nog-mg-n-area60 108 -1176.0 -1176.0 -1140.0 -1140.0 120.0 156.0 156.0 120.0 2316.0 1296.0 21.9457 3.0835 112.8686 20.5057 1.0236 1.7830 

nog-mg-n-area61 109 -1176.0 -1176.0 -1140.0 -1140.0 156.0 192.0 192.0 156.0 2696.0 1296.0 45.8941 1.2623 41.5250 9.1947 0.9113 1.5533 

nog-mg-n-area62 110 -1176.0 -1176.0 -1140.0 -1140.0 192.0 228.0 228.0 192.0 2377.0 1296.0 225.4663 38.0812 489.2602 128.4632 2.2303 2.8285 

nog-mg-n-area63 111 -1176.0 -1176.0 -1140.0 -1140.0 228.0 240.0 240.0 228.0 2126.0 432.0 259.7353 67.5818 411.3879 111.0613 2.3121 3.9213 

nog-mg-n-area64 116 -1140.0 -1140.0 -1104.0 -1104.0 -168.0 -132.0 -132.0 -168.0 2230.0 1296.0 3.6254 3.6605 9.9774 0.2112 0.0700 0.1275 

nog-mg-n-area65 117 -1140.0 -1140.0 -1104.0 -1104.0 -132.0 -96.0 -96.0 -132.0 1706.0 1296.0 9.9848 14.2785 11.4482 3.0465 0.1669 0.3251 

nog-mg-n-area66 118 -1140.0 -1140.0 -1104.0 -1104.0 -96.0 -60.0 -60.0 -96.0 1815.0 1296.0 7.2471 8.6449 12.6057 2.0630 0.1018 0.1691 

nog-mg-n-area67 119 -1140.0 -1140.0 -1104.0 -1104.0 -60.0 -24.0 -24.0 -60.0 1456.0 1296.0 102.8700 5.5271 61.3352 12.3430 0.8568 1.0279 

nog-mg-n-area68 124 -1140.0 -1140.0 -1104.0 -1104.0 120.0 156.0 156.0 120.0 2195.0 1296.0 31.1928 4.7219 362.8184 67.8666 1.1056 1.2298 

nog-mg-n-area69 125 -1140.0 -1140.0 -1104.0 -1104.0 156.0 192.0 192.0 156.0 3475.0 1296.0 10.1280 0.4573 29.3961 4.2968 0.6416 1.2048 

nog-mg-n-area70 126 -1140.0 -1140.0 -1104.0 -1104.0 192.0 228.0 228.0 192.0 3109.0 1296.0 153.9704 50.0138 295.9181 92.7949 1.4977 1.7116 

nog-mg-n-area71 127 -1140.0 -1140.0 -1104.0 -1104.0 228.0 240.0 240.0 228.0 2312.0 432.0 98.6874 7.3664 77.5961 21.7687 0.7602 1.1192 

nog-mg-n-area72 128 -1104.0 -1104.0 -1032.0 -1032.0 -312.0 -240.0 -240.0 -312.0 1704.0 5184.0 359.9281 10.6217 1058.6976 239.4090 3.2443 4.3767 

nog-mg-n-area73 130 -1104.0 -1104.0 -1032.0 -1032.0 -240.0 -168.0 -168.0 -240.0 1468.0 5184.0 169.5630 22.6167 704.2779 195.6282 3.1209 4.2141 

nog-mg-n-area74 132 -1104.0 -1104.0 -1068.0 -1068.0 -168.0 -132.0 -132.0 -168.0 2133.0 1296.0 43.3937 7.5364 203.1948 43.2517 0.5556 0.4917 nog-mg-n-area75 133 -1104.0 -1104.0 -1068.0 -1068.0 -132.0 -96.0 -96.0 -132.0 1828.0 1296.0 33.5935 7.8075 154.8993 33.3162 0.3876 0.2952 

nog-mg-n-area76 134 -1104.0 -1104.0 -1068.0 -1068.0 -96.0 -60.0 -60.0 -96.0 1524.0 1296.0 89.1143 5.6240 113.1917 21.6007 0.9625 1.3110 

nog-mg-n-area77 135 -1104.0 -1104.0 -1068.0 -1068.0 -60.0 -24.0 -24.0 -60.0 1463.0 1296.0 108.9186 1.8905 30.7047 7.0436 0.8388 0.9032 

Non-Project A
Table D-3 CALPUFF Model Inputs: 2018 Non-Project Area Sources (State, Motor Vehicle and Nonroad Sources) 

Base Elevation Grid Cell Area 

name Grid Cell X1 (km) X2 (km) X3 (km) X4 (km) Y1 (km) Y2 (km) Y3 (km) Y4 (km) (m) (km2) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (TPY) 

nog-mg-n-area78 136 -1104.0 -1104.0 -1068.0 -1068.0 -24.0 12.0 12.0 -24.0 2194.0 1296.0 2.7047 0.4963 11.6192 1.6070 0.1124 0.2108 

nog-mg-n-area79 137 -1104.0 -1104.0 -1068.0 -1068.0 12.0 48.0 48.0 12.0 2570.0 1296.0 4.6480 0.4988 10.4395 0.6319 0.2136 0.4220 

nog-mg-n-area80 138 -1104.0 -1104.0 -1068.0 -1068.0 48.0 84.0 84.0 48.0 1828.0 1296.0 12.8519 6.5239 31.0291 4.3146 0.3286 0.5806 

nog-mg-n-area81 139 -1104.0 -1104.0 -1068.0 -1068.0 84.0 120.0 120.0 84.0 1656.0 1296.0 139.1647 45.3123 722.1735 139.0166 1.9616 1.5427 

nog-mg-n-area82 140 -1104.0 -1104.0 -1068.0 -1068.0 120.0 156.0 156.0 120.0 1770.0 1296.0 45.3750 5.6272 429.3416 79.8529 1.0836 1.0236 

nog-mg-n-area83 141 -1104.0 -1104.0 -1068.0 -1068.0 156.0 192.0 192.0 156.0 3414.0 1296.0 15.7733 1.1177 69.2861 13.6738 0.5810 0.8519 

nog-mg-n-area84 142 -1104.0 -1104.0 -1068.0 -1068.0 192.0 228.0 228.0 192.0 2562.0 1296.0 63.6730 5.5019 265.1549 74.9483 0.9933 1.1417 

nog-mg-n-area85 143 -1104.0 -1104.0 -1068.0 -1068.0 228.0 240.0 240.0 228.0 2018.0 432.0 90.2239 4.3103 173.0270 48.9627 0.6677 0.7346 

nog-mg-n-area86 148 -1068.0 -1068.0 -1032.0 -1032.0 -168.0 -132.0 -132.0 -168.0 2072.0 1296.0 25.6010 5.5805 50.1210 18.0899 0.5181 0.8879 

nog-mg-n-area87 149 -1068.0 -1068.0 -1032.0 -1032.0 -132.0 -96.0 -96.0 -132.0 1844.0 1296.0 33.4172 6.1893 592.7892 135.6681 0.8884 0.3768 nog-mg-n-area88 150 -1068.0 -1068.0 -1032.0 -1032.0 -96.0 -60.0 -60.0 -96.0 2290.0 1296.0 16.4994 0.8712 71.0684 13.9209 0.2257 0.2857 

nog-mg-n-area89 151 -1068.0 -1068.0 -1032.0 -1032.0 -60.0 -24.0 -24.0 -60.0 1610.0 1296.0 70.1919 1.3977 36.6910 7.3840 0.5836 0.6700 

nog-mg-n-area90 152 -1068.0 -1068.0 -1032.0 -1032.0 -24.0 12.0 12.0 -24.0 1916.0 1296.0 22.6985 0.7719 19.2127 3.1925 0.2533 0.3443 

nog-mg-n-area91 153 -1068.0 -1068.0 -1032.0 -1032.0 12.0 48.0 48.0 12.0 2248.0 1296.0 5.0757 0.3711 10.6979 0.5536 0.2294 0.4532 

nog-mg-n-area92 154 -1068.0 -1068.0 -1032.0 -1032.0 48.0 84.0 84.0 48.0 1920.0 1296.0 6.2482 0.3842 16.0269 1.5632 0.2483 0.4704 

nog-mg-n-area93 155 -1068.0 -1068.0 -1032.0 -1032.0 84.0 120.0 120.0 84.0 1463.0 1296.0 102.3388 10.6071 368.7939 67.7618 1.2251 1.1592 

nog-mg-n-area94 156 -1068.0 -1068.0 -1032.0 -1032.0 120.0 156.0 156.0 120.0 1714.0 1296.0 193.0639 20.9513 321.5268 65.8020 1.8665 2.1419 

nog-mg-n-area95 157 -1068.0 -1068.0 -1032.0 -1032.0 156.0 192.0 192.0 156.0 3086.0 1296.0 37.7906 2.1058 134.4584 24.8683 0.5265 0.7006 

nog-mg-n-area96 158 -1068.0 -1068.0 -1032.0 -1032.0 192.0 228.0 228.0 192.0 2035.0 1296.0 14.3312 0.5268 149.9263 31.9828 0.1585 0.2003 

nog-mg-n-area97 159 -1068.0 -1068.0 -1032.0 -1032.0 228.0 240.0 240.0 228.0 1981.0 432.0 26.2281 9.4420 109.9917 22.3794 0.1197 0.1240 

nog-mg-n-area98 160 -1032.0 -1032.0 -996.0 -996.0 -312.0 -276.0 -276.0 -312.0 1615.0 1296.0 255.7874 19.6452 2189.4537 498.0949 2.0276 1.6334 

nog-mg-n-area99 161 -1032.0 -1032.0 -996.0 -996.0 -276.0 -240.0 -240.0 -276.0 1610.0 1296.0 41.6949 2.3093 63.3107 23.5168 0.4562 0.6636 

nog-mg-n-area100 162 -1032.0 -1032.0 -996.0 -996.0 -240.0 -204.0 -204.0 -240.0 1844.0 1296.0 304.8186 21.4446 646.5467 322.6316 3.0103 2.9754 

nog-mg-n-area101 163 -1032.0 -1032.0 -996.0 -996.0 -204.0 -168.0 -168.0 -204.0 2103.0 1296.0 60.7503 1.9170 537.1581 145.1848 2.9847 5.1074 

nog-mg-n-area102 164 -1032.0 -1032.0 -960.0 -960.0 -168.0 -96.0 -96.0 -168.0 2438.0 5184.0 108.4224 12.5343 556.7470 185.7261 2.6695 4.2161 

nog-mg-n-area103 166 -1032.0 -1032.0 -996.0 -996.0 -96.0 -60.0 -60.0 -96.0 1988.0 1296.0 17.2548 0.9016 96.3485 30.1847 0.1553 0.2288 

nog-mg-n-area104 167 -1032.0 -1032.0 -996.0 -996.0 -60.0 -24.0 -24.0 -60.0 2449.0 1296.0 171.1607 10.9206 1043.1170 251.4044 1.3807 1.3636 

nog-mg-n-area105 168 -1032.0 -1032.0 -996.0 -996.0 -24.0 12.0 12.0 -24.0 1645.0 1296.0 144.9689 11.3587 484.2404 155.3537 1.2878 1.2176 

nog-mg-n-area106 169 -1032.0 -1032.0 -996.0 -996.0 12.0 48.0 48.0 12.0 2499.0 1296.0 19.6166 1.6010 17.2903 4.4851 0.2949 0.5043 

nog-mg-n-area107 170 -1032.0 -1032.0 -996.0 -996.0 48.0 84.0 84.0 48.0 1946.0 1296.0 23.6600 1.6768 31.6660 10.9840 0.3714 0.5999 

nog-mg-n-area108 171 -1032.0 -1032.0 -996.0 -996.0 84.0 120.0 120.0 84.0 1646.0 1296.0 42.5072 1.6762 38.7134 7.7297 0.4454 0.6234 

nog-mg-n-area109 172 -1032.0 -1032.0 -996.0 -996.0 120.0 156.0 156.0 120.0 1900.0 1296.0 9.8062 1.8958 19.8690 3.4199 0.2296 0.3732 

nog-mg-n-area110 173 -1032.0 -1032.0 -996.0 -996.0 156.0 192.0 192.0 156.0 2488.0 1296.0 33.7552 1.1284 54.1542 9.5827 0.2859 0.3672 

nog-mg-n-area111 174 -1032.0 -1032.0 -996.0 -996.0 192.0 228.0 228.0 192.0 2316.0 1296.0 53.6938 0.6171 40.5228 8.0999 0.3359 0.4036 

nog-mg-n-area112 175 -1032.0 -1032.0 -996.0 -996.0 228.0 240.0 240.0 228.0 2138.0 432.0 392.1177 108.1583 967.2406 227.1339 1.0788 1.0591 

nog-mg-n-area113 176 -996.0 -996.0 -960.0 -960.0 -312.0 -276.0 -276.0 -312.0 1833.0 1296.0 1210.3068 220.8063 7246.6732 1802.8577 6.5442 6.5116 

nog-mg-n-area114 177 -996.0 -996.0 -960.0 -960.0 -276.0 -240.0 -240.0 -276.0 1950.0 1296.0 91.0559 9.8540 228.2103 91.0575 1.0180 0.9726 

nog-mg-n-area115 178 -996.0 -996.0 -960.0 -960.0 -240.0 -204.0 -204.0 -240.0 2234.0 1296.0 88.4458 6.7156 115.3081 62.1833 0.8988 1.0422 

nog-mg-n-area116 179 -996.0 -996.0 -960.0 -960.0 -204.0 -168.0 -168.0 -204.0 2582.0 1296.0 38.1031 2.8174 187.0703 64.2863 2.3966 4.7613 

nog-mg-n-area117 182 -996.0 -996.0 -960.0 -960.0 -96.0 -60.0 -60.0 -96.0 2743.0 1296.0 123.4740 7.3676 97.0078 36.9277 0.8858 1.0703 

nog-mg-n-area118 183 -996.0 -996.0 -960.0 -960.0 -60.0 -24.0 -24.0 -60.0 2331.0 1296.0 941.6403 147.2324 3970.9989 1051.2497 8.7182 10.9548 

nog-mg-n-area119 184 -996.0 -996.0 -924.0 -924.0 -24.0 48.0 48.0 -24.0 1493.0 5184.0 255.2699 17.1268 488.6448 204.2676 2.3839 2.8765 

nog-mg-n-area120 186 -996.0 -996.0 -960.0 -960.0 48.0 84.0 84.0 48.0 1907.0 1296.0 30.5140 2.3779 39.6327 22.6665 0.5637 1.1373 

nog-mg-n-area121 187 -996.0 -996.0 -960.0 -960.0 84.0 120.0 120.0 84.0 2007.0 1296.0 23.2896 0.6004 22.2751 5.8128 0.2563 0.3479 

nog-mg-n-area122 188 -996.0 -996.0 -960.0 -960.0 120.0 156.0 156.0 120.0 2194.0 1296.0 8.0494 0.2334 23.5435 5.5284 0.1280 0.2149 

nog-mg-n-area123 189 -996.0 -996.0 -960.0 -960.0 156.0 192.0 192.0 156.0 1871.0 1296.0 5.3889 0.1285 29.1254 5.7497 0.0984 0.1747 

nog-mg-n-area124 190 -996.0 -996.0 -924.0 -924.0 192.0 240.0 240.0 192.0 2499.0 3456.0 48.8214 4.6197 2826.7887 529.4087 0.3649 0.5418 

nog-mg-n-area125 192 -960.0 -960.0 -924.0 -924.0 -312.0 -276.0 -276.0 -312.0 1893.0 1296.0 150.9105 17.8236 629.7104 143.9250 1.6849 2.8512 

nog-mg-n-area126 193 -960.0 -960.0 -924.0 -924.0 -276.0 -240.0 -240.0 -276.0 2072.0 1296.0 378.2430 54.3051 568.1321 244.4516 5.2133 6.1965 

nog-mg-n-area127 194 -960.0 -960.0 -924.0 -924.0 -240.0 -204.0 -204.0 -240.0 2468.0 1296.0 138.3473 11.9028 203.0348 92.0431 1.8521 2.6750 

nog-mg-n-area128 195 -960.0 -960.0 -924.0 -924.0 -204.0 -168.0 -168.0 -204.0 3246.0 1296.0 207.8958 9.3323 254.5408 104.9976 10.8120 22.5741 

nog-mg-n-area129 196 -960.0 -960.0 -924.0 -924.0 -168.0 -132.0 -132.0 -168.0 2929.0 1296.0 108.2195 7.2809 168.9649 83.8660 3.0582 5.6491 

nog-mg-n-area130 197 -960.0 -960.0 -924.0 -924.0 -132.0 -96.0 -96.0 -132.0 2926.0 1296.0 310.6660 50.1233 1515.8701 460.6137 3.1782 3.3308 

nog-mg-n-area131 198 -960.0 -960.0 -924.0 -924.0 -96.0 -60.0 -60.0 -96.0 1754.0 1296.0 217.0726 26.5005 703.7216 359.0878 2.1657 2.0102 

nog-mg-n-area132 199 -960.0 -960.0 -924.0 -924.0 -60.0 -24.0 -24.0 -60.0 3086.0 1296.0 53.7589 9.2409 588.8935 193.6545 0.7503 0.6639 

nog-mg-n-area133 202 -960.0 -960.0 -924.0 -924.0 48.0 84.0 84.0 48.0 2011.0 1296.0 25.6319 1.7763 44.5904 18.0879 0.4622 0.5979 

nog-mg-n-area134 203 -960.0 -960.0 -924.0 -924.0 84.0 120.0 120.0 84.0 1889.0 1296.0 24.8369 0.4962 28.5295 7.6955 0.2637 0.3359 

nog-mg-n-area135 204 -960.0 -960.0 -924.0 -924.0 120.0 156.0 156.0 120.0 1889.0 1296.0 5.6187 0.2015 20.8972 5.4135 0.1109 0.1969 

nog-mg-n-area136 205 -960.0 -960.0 -924.0 -924.0 156.0 192.0 192.0 156.0 2458.0 1296.0 6.1664 1.5803 28.0579 5.4324 0.0822 0.1537 

nog-mg-n-area137 208 -924.0 -924.0 -888.0 -888.0 -312.0 -276.0 -276.0 -312.0 2042.0 1296.0 34.9248 1.4014 25.7185 7.7503 0.5238 0.8520 

nog-mg-n-area138 209 -924.0 -924.0 -888.0 -888.0 -276.0 -240.0 -240.0 -276.0 1903.0 1296.0 94.9361 4.9066 114.7405 78.6517 1.1650 1.7217 

nog-mg-n-area139 210 -924.0 -924.0 -888.0 -888.0 -240.0 -204.0 -204.0 -240.0 2685.0 1296.0 64.3217 2.7010 57.9382 37.7596 5.5264 11.7598 

nog-mg-n-area140 211 -924.0 -924.0 -888.0 -888.0 -204.0 -168.0 -168.0 -204.0 4084.0 1296.0 99.3007 2.1785 20.4698 18.5890 9.4133 20.3566 

nog-mg-n-area141 212 -924.0 -924.0 -888.0 -888.0 -168.0 -132.0 -132.0 -168.0 3962.0 1296.0 41.8708 1.6223 50.6394 24.1966 3.0764 6.5564 

nog-mg-n-area142 213 -924.0 -924.0 -888.0 -888.0 -132.0 -96.0 -96.0 -132.0 3471.0 1296.0 98.0392 5.7566 212.8566 65.5763 0.8337 0.9545 

nog-mg-n-area143 214 -924.0 -924.0 -888.0 -888.0 -96.0 -60.0 -60.0 -96.0 2327.0 1296.0 74.2860 16.8774 218.1168 141.0050 0.8574 0.8926 

nog-mg-n-area144 215 -924.0 -924.0 -888.0 -888.0 -60.0 -24.0 -24.0 -60.0 2608.0 1296.0 17.2653 8.2142 49.8051 38.9288 0.2420 0.3707 

nog-mg-n-area145 216 -924.0 -924.0 -888.0 -888.0 -24.0 12.0 12.0 -24.0 2438.0 1296.0 270.3672 13.0662 457.6057 322.8973 2.2891 2.5390 

nog-mg-n-area146 217 -924.0 -924.0 -888.0 -888.0 12.0 48.0 48.0 12.0 2111.0 1296.0 27.9440 5.6775 107.7491 85.0673 0.4417 0.6488 

nog-mg-n-area147 218 -924.0 -924.0 -888.0 -888.0 48.0 84.0 84.0 48.0 2560.0 1296.0 31.1826 1.8557 87.8019 30.3166 0.8529 1.1511 

nog-mg-n-area148 219 -924.0 -924.0 -888.0 -888.0 84.0 120.0 120.0 84.0 2378.0 1296.0 54.5846 5.8340 185.2055 75.6205 0.7139 0.5188 

nog-mg-n-area149 220 -924.0 -924.0 -852.0 -852.0 120.0 192.0 192.0 120.0 2051.0 5184.0 61.7326 16.8627 236.7850 65.2585 1.2923 1.6019 

nog-mg-n-area150 222 -924.0 -924.0 -852.0 -852.0 192.0 240.0 240.0 192.0 2073.0 3456.0 77.9924 22.8815 185.8735 37.0998 0.7439 1.1428 

nog-mg-n-area151 224 -888.0 -888.0 -852.0 -852.0 -312.0 -276.0 -276.0 -312.0 2316.0 1296.0 113.1318 3.6681 190.5490 69.3159 1.1182 1.2467 

nog-mg-n-area152 225 -888.0 -888.0 -852.0 -852.0 -276.0 -240.0 -240.0 -276.0 2207.0 1296.0 75.3943 4.7635 96.7465 71.0970 1.4124 2.5315 

nog-mg-n-area153 226 -888.0 -888.0 -852.0 -852.0 -240.0 -204.0 -204.0 -240.0 2722.0 1296.0 114.9693 1.8071 27.3669 18.6638 8.3456 17.8045 

nog-mg-n-area154 227 -888.0 -888.0 -852.0 -852.0 -204.0 -168.0 -168.0 -204.0 3543.0 1296.0 76.1719 1.2495 26.2566 15.6360 6.6886 14.3879 

Non-Project A
Table D-3 CALPUFF Model Inputs: 2018 Non-Project Area Sources (State, Motor Vehicle and Nonroad Sources) 

Base Elevation Grid Cell Area 

name Grid Cell X1 (km) X2 (km) X3 (km) X4 (km) Y1 (km) Y2 (km) Y3 (km) Y4 (km) (m) (km2) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (TPY) 

nog-mg-n-area155 228 -888.0 -888.0 -852.0 -852.0 -168.0 -132.0 -132.0 -168.0 3367.0 1296.0 24.8064 0.5507 26.4654 9.3885 1.5813 3.2536 

nog-mg-n-area156 229 -888.0 -888.0 -852.0 -852.0 -132.0 -96.0 -96.0 -132.0 2621.0 1296.0 101.0094 4.9405 237.3122 107.8748 1.8699 2.2229 

nog-mg-n-area157 230 -888.0 -888.0 -852.0 -852.0 -96.0 -60.0 -60.0 -96.0 2976.0 1296.0 37.0703 2.4558 190.6412 83.9727 0.5663 0.6153 

nog-mg-n-area158 231 -888.0 -888.0 -852.0 -852.0 -60.0 -24.0 -24.0 -60.0 2431.0 1296.0 100.8777 8.5937 86.3071 35.2026 1.3975 1.8043 

nog-mg-n-area159 232 -888.0 -888.0 -852.0 -852.0 -24.0 12.0 12.0 -24.0 2967.0 1296.0 398.2062 35.5162 952.9673 446.8761 3.9732 4.4131 

nog-mg-n-area160 233 -888.0 -888.0 -852.0 -852.0 12.0 48.0 48.0 12.0 3147.0 1296.0 18.3015 3.6547 76.2831 32.6487 0.3303 0.4831 

nog-mg-n-area161 234 -888.0 -888.0 -852.0 -852.0 48.0 84.0 84.0 48.0 2965.0 1296.0 10.7012 1.9633 40.6607 14.3545 0.2802 0.4638 

nog-mg-n-area162 235 -888.0 -888.0 -852.0 -852.0 84.0 120.0 120.0 84.0 2377.0 1296.0 166.5571 15.3940 605.9250 206.4502 2.4259 1.9886 

nog-mg-n-area163 240 -852.0 -852.0 -780.0 -780.0 -312.0 -240.0 -240.0 -312.0 2286.0 5184.0 296.8142 14.4310 1268.8132 417.0559 5.1606 5.0245 

nog-mg-n-area164 242 -852.0 -852.0 -816.0 -816.0 -240.0 -204.0 -204.0 -240.0 3718.0 1296.0 95.5454 4.0653 194.0400 106.5662 1.8453 2.9070 

nog-mg-n-area165 243 -852.0 -852.0 -816.0 -816.0 -204.0 -168.0 -168.0 -204.0 2900.0 1296.0 13.8703 1.1000 32.9378 15.4690 0.9445 1.9465 

nog-mg-n-area166 244 -852.0 -852.0 -816.0 -816.0 -168.0 -132.0 -132.0 -168.0 3230.0 1296.0 21.2922 0.5576 44.9877 11.1095 0.4459 0.7167 

nog-mg-n-area167 245 -852.0 -852.0 -816.0 -816.0 -132.0 -96.0 -96.0 -132.0 2826.0 1296.0 63.4139 2.7387 64.6892 40.3070 0.7282 0.7935 

nog-mg-n-area168 246 -852.0 -852.0 -816.0 -816.0 -96.0 -60.0 -60.0 -96.0 2745.0 1296.0 27.9705 6.2995 92.6419 46.0197 0.6391 0.8951 

nog-mg-n-area169 247 -852.0 -852.0 -816.0 -816.0 -60.0 -24.0 -24.0 -60.0 4084.0 1296.0 227.2889 34.0973 201.9275 84.6373 5.2551 6.1389 

nog-mg-n-area170 248 -852.0 -852.0 -816.0 -816.0 -24.0 12.0 12.0 -24.0 2743.0 1296.0 355.4428 21.0968 755.6553 329.9139 4.1329 4.7720 

nog-mg-n-area171 249 -852.0 -852.0 -816.0 -816.0 12.0 48.0 48.0 12.0 2499.0 1296.0 77.6993 7.9968 131.3160 63.6124 0.7886 0.9661 

nog-mg-n-area172 250 -852.0 -852.0 -816.0 -816.0 48.0 84.0 84.0 48.0 3632.0 1296.0 52.5188 7.2062 238.2614 80.1891 0.7750 0.8218 

nog-mg-n-area173 251 -852.0 -852.0 -816.0 -816.0 84.0 120.0 120.0 84.0 2256.0 1296.0 191.9253 22.7866 640.5166 206.7061 2.6901 2.6013 

nog-mg-n-area174 252 -852.0 -852.0 -816.0 -816.0 120.0 156.0 156.0 120.0 2621.0 1296.0 13.1048 5.1683 50.1706 19.9924 0.3990 0.6515 

nog-mg-n-area175 253 -852.0 -852.0 -816.0 -816.0 156.0 192.0 192.0 156.0 2363.0 1296.0 37.0716 14.5590 140.5635 38.1179 0.4422 0.5716 

nog-mg-n-area176 254 -852.0 -852.0 -780.0 -780.0 192.0 240.0 240.0 192.0 2462.0 3456.0 313.1013 99.5531 458.3147 123.5557 2.5376 2.5263 

nog-mg-n-area177 258 -816.0 -816.0 -780.0 -780.0 -240.0 -204.0 -204.0 -240.0 3352.0 1296.0 227.8378 13.5710 1691.1199 498.4379 4.3690 2.9098 

nog-mg-n-area178 259 -816.0 -816.0 -780.0 -780.0 -204.0 -168.0 -168.0 -204.0 2620.0 1296.0 63.4910 1.5314 426.8008 119.2031 1.4032 1.0901 

nog-mg-n-area179 260 -816.0 -816.0 -780.0 -780.0 -168.0 -132.0 -132.0 -168.0 2759.0 1296.0 27.9988 0.7001 55.5637 15.9989 0.5039 0.7759 

nog-mg-n-area180 261 -816.0 -816.0 -780.0 -780.0 -132.0 -96.0 -96.0 -132.0 2691.0 1296.0 145.2139 5.3534 203.3867 97.6370 1.4801 2.0237 

nog-mg-n-area181 262 -816.0 -816.0 -780.0 -780.0 -96.0 -60.0 -60.0 -96.0 3612.0 1296.0 91.1175 8.6870 250.0524 134.3373 1.2282 1.8270 

nog-mg-n-area182 263 -816.0 -816.0 -780.0 -780.0 -60.0 -24.0 -24.0 -60.0 3595.0 1296.0 125.1618 9.1935 249.6245 136.2633 2.2012 3.9948 

nog-mg-n-area183 264 -816.0 -816.0 -780.0 -780.0 -24.0 12.0 12.0 -24.0 3925.0 1296.0 450.5951 46.8444 1278.3956 354.9800 4.0233 4.1085 

nog-mg-n-area184 265 -816.0 -816.0 -780.0 -780.0 12.0 48.0 48.0 12.0 3227.0 1296.0 80.8856 10.6373 171.2389 86.9930 1.0487 1.3221 

nog-mg-n-area185 266 -816.0 -816.0 -780.0 -780.0 48.0 84.0 84.0 48.0 2806.0 1296.0 64.8571 3.0848 35.6458 34.2457 0.9325 1.2872 

nog-mg-n-area186 267 -816.0 -816.0 -780.0 -780.0 84.0 120.0 120.0 84.0 3004.0 1296.0 71.3073 4.3146 92.8764 32.3368 2.2793 3.4614 

nog-mg-n-area187 268 -816.0 -816.0 -780.0 -780.0 120.0 156.0 156.0 120.0 3444.0 1296.0 28.5947 3.0446 23.3582 13.2754 1.5774 2.8267 

nog-mg-n-area188 269 -816.0 -816.0 -780.0 -780.0 156.0 192.0 192.0 156.0 2756.0 1296.0 57.1809 15.4552 113.0207 38.3999 1.1332 0.7690 

nog-mg-n-area189 272 -780.0 -780.0 -720.0 -720.0 -312.0 -240.0 -240.0 -312.0 2352.0 4320.0 324.2217 20.2463 780.0171 253.9994 5.5248 8.3263 

nog-mg-n-area190 274 -780.0 -780.0 -744.0 -744.0 -240.0 -204.0 -204.0 -240.0 2285.0 1296.0 47.0385 2.0037 400.2123 107.3450 1.0706 1.1956 

nog-mg-n-area191 275 -780.0 -780.0 -744.0 -744.0 -204.0 -168.0 -168.0 -204.0 2293.0 1296.0 22.9259 1.0013 155.9506 55.4102 0.8166 1.2745 

nog-mg-n-area192 276 -780.0 -780.0 -720.0 -720.0 -168.0 -96.0 -96.0 -168.0 2350.0 4320.0 275.1644 13.3308 501.3112 197.2874 3.4079 4.9583 

nog-mg-n-area193 278 -780.0 -780.0 -720.0 -720.0 -96.0 -24.0 -24.0 -96.0 2926.0 4320.0 260.6035 12.7843 483.6947 233.0341 2.9024 4.0950 

nog-mg-n-area194 280 -780.0 -780.0 -744.0 -744.0 -24.0 12.0 12.0 -24.0 4155.0 1296.0 652.8784 48.2660 1160.9031 477.6275 5.0588 5.2246 

nog-mg-n-area195 281 -780.0 -780.0 -744.0 -744.0 12.0 48.0 48.0 12.0 2926.0 1296.0 114.5677 8.9664 228.1029 94.9410 1.3116 1.6664 

nog-mg-n-area196 282 -780.0 -780.0 -744.0 -744.0 48.0 84.0 84.0 48.0 2409.0 1296.0 88.1010 6.9452 130.4241 66.1180 1.1505 1.7708 

nog-mg-n-area197 283 -780.0 -780.0 -744.0 -744.0 84.0 120.0 120.0 84.0 2981.0 1296.0 39.1985 1.0149 30.4918 13.1750 2.0652 3.1911 

nog-mg-n-area198 284 -780.0 -780.0 -744.0 -744.0 120.0 156.0 156.0 120.0 2469.0 1296.0 34.4357 4.0354 94.8968 34.8204 1.1742 1.8529 

nog-mg-n-area199 285 -780.0 -780.0 -744.0 -744.0 156.0 192.0 192.0 156.0 2682.0 1296.0 32.8164 15.1410 49.5466 26.8156 0.4547 0.5422 

nog-mg-n-area200 286 -780.0 -780.0 -720.0 -720.0 192.0 240.0 240.0 192.0 3220.0 2880.0 238.9908 50.2756 153.1635 45.6112 1.8664 1.9622 

nog-mg-n-area201 290 -744.0 -744.0 -720.0 -720.0 -240.0 -204.0 -204.0 -240.0 2773.0 864.0 33.7755 1.1149 26.1045 21.4004 0.6383 1.0815 

nog-mg-n-area202 291 -744.0 -744.0 -720.0 -720.0 -204.0 -168.0 -168.0 -204.0 3794.0 864.0 38.2290 1.6779 130.3198 50.3018 1.8005 3.3765 

nog-mg-n-area203 296 -744.0 -744.0 -720.0 -720.0 -24.0 12.0 12.0 -24.0 3057.0 864.0 246.7371 10.5346 255.3179 149.8489 2.4140 3.3080 

nog-mg-n-area204 297 -744.0 -744.0 -720.0 -720.0 12.0 48.0 48.0 12.0 3779.0 864.0 92.8655 12.5348 187.2973 120.0085 2.2818 3.9858 

nog-mg-n-area205 298 -744.0 -744.0 -720.0 -720.0 48.0 84.0 84.0 48.0 3045.0 864.0 142.1577 13.8704 205.9670 73.5857 1.2643 1.6428 

nog-mg-n-area206 299 -744.0 -744.0 -720.0 -720.0 84.0 120.0 120.0 84.0 3465.0 864.0 45.2913 7.3110 108.2288 33.0344 0.4795 0.7016 

nog-mg-n-area207 300 -744.0 -744.0 -720.0 -720.0 120.0 156.0 156.0 120.0 2826.0 864.0 9.1128 3.4178 112.9730 34.7038 0.2584 0.3081 

nog-mg-n-area208 301 -744.0 -744.0 -720.0 -720.0 156.0 192.0 192.0 156.0 2318.0 864.0 124.3926 89.8413 221.0003 66.9968 1.5123 1.2350 

Non-Project A
Table D-4 CALPUFF Model Inputs: 2018 Non-Project Area Sources (Uinta Basin Oil and Gas Sources) 

Base Elevation Grid Cell Area 

name Grid Cell X1 (km) X2 (km) X3 (km) X4 (km) Y1 (km) Y2 (km) Y3 (km) Y4 (km) (m) (km2) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (TPY) PN

unita-og-area1 72 -1248.0 -1248.0 -1176.0 -1176.0 -24.0 48.0 48.0 -24.0 2467.0 5184.0 965.0450 2.1086 0.0000 51.3677 0.0000 2.1575 

unita-og-area2 74 -1248.0 -1248.0 -1176.0 -1176.0 48.0 120.0 120.0 48.0 2207.0 5184.0 75.9741 0.2534 0.0000 4.3549 0.0000 0.1829 

unita-og-area3 104 -1176.0 -1176.0 -1104.0 -1104.0 -24.0 48.0 48.0 -24.0 1828.0 5184.0 243.4241 0.9284 0.0000 16.1389 0.0000 0.6778 

unita-og-area4 106 -1176.0 -1176.0 -1104.0 -1104.0 48.0 120.0 120.0 48.0 1829.0 5184.0 2805.2885 9.4687 0.0000 196.3510 0.0000 8.2468 

unita-og-area5 118 -1140.0 -1140.0 -1104.0 -1104.0 -96.0 -60.0 -60.0 -96.0 1815.0 1296.0 2.9799 0.0020 0.0000 0.1240 0.0000 0.0052 unita-og-area6 119 -1140.0 -1140.0 -1104.0 -1104.0 -60.0 -24.0 -24.0 -60.0 1456.0 1296.0 7.5061 0.0332 0.0000 0.1709 0.0000 0.0072 

unita-og-area7 124 -1140.0 -1140.0 -1104.0 -1104.0 120.0 156.0 156.0 120.0 2195.0 1296.0 73.1067 0.0770 0.0000 6.1882 0.0000 0.2599 unita-og-area8 134 -1104.0 -1104.0 -1068.0 -1068.0 -96.0 -60.0 -60.0 -96.0 1524.0 1296.0 18.6994 0.0121 0.0000 0.7799 0.0000 0.0328 unita-og-area9 135 -1104.0 -1104.0 -1068.0 -1068.0 -60.0 -24.0 -24.0 -60.0 1463.0 1296.0 20.7270 0.0977 0.0000 0.7572 0.0000 0.0318 unita-og-area10 136 -1104.0 -1104.0 -1068.0 -1068.0 -24.0 12.0 12.0 -24.0 2194.0 1296.0 3.4230 0.0116 0.0000 0.1306 0.0000 0.0055 unita-og-area11 137 -1104.0 -1104.0 -1068.0 -1068.0 12.0 48.0 48.0 12.0 2570.0 1296.0 155.1693 0.3881 0.0000 6.8622 0.0000 0.2882 unita-og-area12 138 -1104.0 -1104.0 -1068.0 -1068.0 48.0 84.0 84.0 48.0 1828.0 1296.0 1366.0236 4.8147 0.0000 72.2440 0.0000 3.0343 unita-og-area13 139 -1104.0 -1104.0 -1068.0 -1068.0 84.0 120.0 120.0 84.0 1656.0 1296.0 723.1322 1.2577 0.0000 44.5957 0.0000 1.8730 unita-og-area14 140 -1104.0 -1104.0 -1068.0 -1068.0 120.0 156.0 156.0 120.0 1770.0 1296.0 386.3598 0.9887 0.0000 29.9764 0.0000 1.2590 

unita-og-area15 150 -1068.0 -1068.0 -1032.0 -1032.0 -96.0 -60.0 -60.0 -96.0 2290.0 1296.0 1.6850 0.0101 0.0000 0.0248 0.0000 0.0010 unita-og-area16 151 -1068.0 -1068.0 -1032.0 -1032.0 -60.0 -24.0 -24.0 -60.0 1610.0 1296.0 31.1359 0.1713 0.0000 0.9179 0.0000 0.0386 

unita-og-area17 152 -1068.0 -1068.0 -1032.0 -1032.0 -24.0 12.0 12.0 -24.0 1916.0 1296.0 85.3554 0.3540 0.0000 3.1836 0.0000 0.1337 

unita-og-area18 153 -1068.0 -1068.0 -1032.0 -1032.0 12.0 48.0 48.0 12.0 2248.0 1296.0 64.3397 0.3300 0.0000 3.0314 0.0000 0.1273 unita-og-area19 154 -1068.0 -1068.0 -1032.0 -1032.0 48.0 84.0 84.0 48.0 1920.0 1296.0 3309.2287 12.7069 0.0000 156.2433 0.0000 6.5623 unita-og-area20 155 -1068.0 -1068.0 -1032.0 -1032.0 84.0 120.0 120.0 84.0 1463.0 1296.0 709.4476 2.0786 0.0000 39.4412 0.0000 1.6565 unita-og-area21 168 -1032.0 -1032.0 -996.0 -996.0 -24.0 12.0 12.0 -24.0 1645.0 1296.0 42.2451 0.1571 0.0000 1.4288 0.0000 0.0600 

unita-og-area22 169 -1032.0 -1032.0 -996.0 -996.0 12.0 48.0 48.0 12.0 2499.0 1296.0 5.8896 0.0296 0.0000 0.2920 0.0000 0.0123 unita-og-area23 170 -1032.0 -1032.0 -996.0 -996.0 48.0 84.0 84.0 48.0 1946.0 1296.0 39.7029 0.1976 0.0000 1.6797 0.0000 0.0705 unita-og-area24 171 -1032.0 -1032.0 -996.0 -996.0 84.0 120.0 120.0 84.0 1646.0 1296.0 31.1659 0.0886 0.0000 1.6768 0.0000 0.0704 

No
Table D-5 CALPUFF Model Inputs: 2018 Non-Project Area Sources (Piceance Basin Oil and Gas Sources) 

Base Elevation Grid Cell Area 

name Grid Cell X1 (km) X2 (km) X3 (km) X4 (km) Y1 (km) Y2 (km) Y3 (km) Y4 (km) (m) (km2) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (TPY) 

piceance-og-area1 168 -1032.0 -1032.0 -996.0 -996.0 -24.0 12.0 12.0 -24.0 1645.0 1296.0 50.9261 0.2366 0.0000 3.2411 0.0000 0.1361 

piceance-og-area2 169 -1032.0 -1032.0 -996.0 -996.0 12.0 48.0 48.0 12.0 2499.0 1296.0 118.1598 0.5294 0.0000 8.5180 0.0000 0.3578 

piceance-og-area3 170 -1032.0 -1032.0 -996.0 -996.0 48.0 84.0 84.0 48.0 1946.0 1296.0 207.3610 0.7633 0.0000 13.6868 0.0000 0.5748 

piceance-og-area4 171 -1032.0 -1032.0 -996.0 -996.0 84.0 120.0 120.0 84.0 1646.0 1296.0 0.0763 0.0000 0.0000 0.0009 0.0000 0.0000 

piceance-og-area5 183 -996.0 -996.0 -960.0 -960.0 -60.0 -24.0 -24.0 -60.0 2331.0 1296.0 2.2151 0.0108 0.0000 0.1409 0.0000 0.0059 

piceance-og-area6 184 -996.0 -996.0 -924.0 -924.0 -24.0 48.0 48.0 -24.0 1493.0 5184.0 1936.7687 5.6018 0.0000 140.4199 0.0000 5.8977 

piceance-og-area7 186 -996.0 -996.0 -960.0 -960.0 48.0 84.0 84.0 48.0 1907.0 1296.0 55.1343 0.1897 0.0000 3.9148 0.0000 0.1644 

piceance-og-area8 187 -996.0 -996.0 -960.0 -960.0 84.0 120.0 120.0 84.0 2007.0 1296.0 0.9206 0.0034 0.0000 0.0465 0.0000 0.0020 

piceance-og-area9 189 -996.0 -996.0 -960.0 -960.0 156.0 192.0 192.0 156.0 1871.0 1296.0 62.2051 0.2193 0.0000 4.3960 0.0000 0.1846 

piceance-og-area10 199 -960.0 -960.0 -924.0 -924.0 -60.0 -24.0 -24.0 -60.0 3086.0 1296.0 163.1865 0.3328 0.0000 9.9240 0.0000 0.4168 

piceance-og-area11 202 -960.0 -960.0 -924.0 -924.0 48.0 84.0 84.0 48.0 2011.0 1296.0 76.8506 0.2418 0.0000 5.5075 0.0000 0.2313 

piceance-og-area12 203 -960.0 -960.0 -924.0 -924.0 84.0 120.0 120.0 84.0 1889.0 1296.0 0.8387 0.0000 0.0000 0.0092 0.0000 0.0004 

piceance-og-area13 204 -960.0 -960.0 -924.0 -924.0 120.0 156.0 156.0 120.0 1889.0 1296.0 2.1079 0.0011 0.0000 0.1964 0.0000 0.0083 

piceance-og-area14 205 -960.0 -960.0 -924.0 -924.0 156.0 192.0 192.0 156.0 2458.0 1296.0 35.7211 0.1230 0.0000 2.0590 0.0000 0.0865 piceance-og-area15 215 -924.0 -924.0 -888.0 -888.0 -60.0 -24.0 -24.0 -60.0 2608.0 1296.0 68.3730 0.1074 0.0000 5.1009 0.0000 0.2142 piceance-og-area16 216 -924.0 -924.0 -888.0 -888.0 -24.0 12.0 12.0 -24.0 2438.0 1296.0 884.8818 2.7346 0.0000 50.5297 0.0000 2.1222 

piceance-og-area17 218 -924.0 -924.0 -888.0 -888.0 48.0 84.0 84.0 48.0 2560.0 1296.0 1.8538 0.0038 0.0000 0.0590 0.0000 0.0025 

piceance-og-area18 219 -924.0 -924.0 -888.0 -888.0 84.0 120.0 120.0 84.0 2378.0 1296.0 14.8010 0.0133 0.0000 1.2757 0.0000 0.0536 

piceance-og-area19 220 -924.0 -924.0 -852.0 -852.0 120.0 192.0 192.0 120.0 2051.0 5184.0 51.4987 0.1838 0.0000 3.6616 0.0000 0.1538 

piceance-og-area20 234 -888.0 -888.0 -852.0 -852.0 48.0 84.0 84.0 48.0 2965.0 1296.0 0.1145 0.0000 0.0000 0.0014 0.0000 0.0001 piceance-og-area21 235 -888.0 -888.0 -852.0 -852.0 84.0 120.0 120.0 84.0 2377.0 1296.0 8.0234 0.0361 0.0000 0.4740 0.0000 0.0199 

piceance-og-area22 251 -852.0 -852.0 -816.0 -816.0 84.0 120.0 120.0 84.0 2256.0 1296.0 2.5006 0.0140 0.0000 0.1836 0.0000 0.0077 

Non-Pr
Table D-6 CALPUFF Model Inputs: 2018 Non-Project Area Sources (Other State Non-Project Oil and Gas Sources) 

Base Elevation Grid Cell Area 

name Grid Cell X1 (km) X2 (km) X3 (km) X4 (km) Y1 (km) Y2 (km) Y3 (km) Y4 (km) (m) (km2) NOX (TPY) SO2 (TPY) PMC (TPY) PM2_5 (TPY) PEC (TPY) POA (TPY) 

other-og-area1 36 -1320.0 -1320.0 -1284.0 -1284.0 -168.0 -132.0 -132.0 -168.0 1885.0 1296.0 0.4300 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area2 78 -1248.0 -1248.0 -1176.0 -1176.0 192.0 240.0 240.0 192.0 1323.0 3456.0 11.9516 0.0002 0.0000 0.0000 0.0000 0.0000 

other-og-area3 93 -1212.0 -1212.0 -1176.0 -1176.0 156.0 192.0 192.0 156.0 1767.0 1296.0 0.2730 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area4 98 -1176.0 -1176.0 -1104.0 -1104.0 -240.0 -168.0 -168.0 -240.0 1645.0 5184.0 0.1170 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area5 110 -1176.0 -1176.0 -1140.0 -1140.0 192.0 228.0 228.0 192.0 2377.0 1296.0 100.3257 0.0793 0.0000 0.0000 0.0000 0.0000 

other-og-area6 111 -1176.0 -1176.0 -1140.0 -1140.0 228.0 240.0 240.0 228.0 2126.0 432.0 268.3407 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area7 125 -1140.0 -1140.0 -1104.0 -1104.0 156.0 192.0 192.0 156.0 3475.0 1296.0 3.0834 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area8 126 -1140.0 -1140.0 -1104.0 -1104.0 192.0 228.0 228.0 192.0 3109.0 1296.0 34.8651 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area9 127 -1140.0 -1140.0 -1104.0 -1104.0 228.0 240.0 240.0 228.0 2312.0 432.0 169.3783 0.1196 0.0000 0.0000 0.0000 0.0000 

other-og-area10 128 -1104.0 -1104.0 -1032.0 -1032.0 -312.0 -240.0 -240.0 -312.0 1704.0 5184.0 56.0053 0.0094 0.0000 0.0000 0.0000 0.0000 other-og-area11 130 -1104.0 -1104.0 -1032.0 -1032.0 -240.0 -168.0 -168.0 -240.0 1468.0 5184.0 98.9291 0.7614 0.0000 0.0000 0.0000 0.0000 other-og-area12 133 -1104.0 -1104.0 -1068.0 -1068.0 -132.0 -96.0 -96.0 -132.0 1828.0 1296.0 0.0310 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area13 142 -1104.0 -1104.0 -1068.0 -1068.0 192.0 228.0 228.0 192.0 2562.0 1296.0 12.8771 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area14 143 -1104.0 -1104.0 -1068.0 -1068.0 228.0 240.0 240.0 228.0 2018.0 432.0 14.4904 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area15 148 -1068.0 -1068.0 -1032.0 -1032.0 -168.0 -132.0 -132.0 -168.0 2072.0 1296.0 9.2192 0.3150 0.0000 0.0000 0.0000 0.0000 

other-og-area16 149 -1068.0 -1068.0 -1032.0 -1032.0 -132.0 -96.0 -96.0 -132.0 1844.0 1296.0 5.9600 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area17 158 -1068.0 -1068.0 -1032.0 -1032.0 192.0 228.0 228.0 192.0 2035.0 1296.0 10.6927 0.0025 0.0000 0.0000 0.0000 0.0000 

other-og-area18 159 -1068.0 -1068.0 -1032.0 -1032.0 228.0 240.0 240.0 228.0 1981.0 432.0 10.6927 0.0025 0.0000 0.0000 0.0000 0.0000 

other-og-area19 160 -1032.0 -1032.0 -996.0 -996.0 -312.0 -276.0 -276.0 -312.0 1615.0 1296.0 2095.4506 0.4429 0.0000 0.0000 0.0000 0.0000 

other-og-area20 161 -1032.0 -1032.0 -996.0 -996.0 -276.0 -240.0 -240.0 -276.0 1610.0 1296.0 961.0450 0.1261 0.0000 0.0000 0.0000 0.0000 

other-og-area21 162 -1032.0 -1032.0 -996.0 -996.0 -240.0 -204.0 -204.0 -240.0 1844.0 1296.0 0.4528 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area22 164 -1032.0 -1032.0 -960.0 -960.0 -168.0 -96.0 -96.0 -168.0 2438.0 5184.0 61.7106 2.2050 0.0000 0.0000 0.0000 0.0000 

other-og-area23 173 -1032.0 -1032.0 -996.0 -996.0 156.0 192.0 192.0 156.0 2488.0 1296.0 17.3949 0.0015 0.0000 0.0000 0.0000 0.0000 

other-og-area24 174 -1032.0 -1032.0 -996.0 -996.0 192.0 228.0 228.0 192.0 2316.0 1296.0 0.0388 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area25 175 -1032.0 -1032.0 -996.0 -996.0 228.0 240.0 240.0 228.0 2138.0 432.0 0.0375 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area26 176 -996.0 -996.0 -960.0 -960.0 -312.0 -276.0 -276.0 -312.0 1833.0 1296.0 7956.9124 1.6301 0.0000 0.0000 0.0000 0.0000 

other-og-area27 177 -996.0 -996.0 -960.0 -960.0 -276.0 -240.0 -240.0 -276.0 1950.0 1296.0 7228.2454 0.5240 0.0000 0.0000 0.0000 0.0000 

other-og-area28 189 -996.0 -996.0 -960.0 -960.0 156.0 192.0 192.0 156.0 1871.0 1296.0 23.0573 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area29 190 -996.0 -996.0 -924.0 -924.0 192.0 240.0 240.0 192.0 2499.0 3456.0 904.6063 0.0987 0.0000 0.0000 0.0000 0.0000 

other-og-area30 192 -960.0 -960.0 -924.0 -924.0 -312.0 -276.0 -276.0 -312.0 1893.0 1296.0 9808.7691 2.1141 0.0000 0.0000 0.0000 0.0000 

other-og-area31 193 -960.0 -960.0 -924.0 -924.0 -276.0 -240.0 -240.0 -276.0 2072.0 1296.0 607.0235 2.2041 0.0000 0.0000 0.0000 0.0000 

other-og-area32 205 -960.0 -960.0 -924.0 -924.0 156.0 192.0 192.0 156.0 2458.0 1296.0 21.9461 0.0049 0.0000 0.0000 0.0000 0.0000 

other-og-area33 208 -924.0 -924.0 -888.0 -888.0 -312.0 -276.0 -276.0 -312.0 2042.0 1296.0 314.2251 0.1453 0.0000 0.0000 0.0000 0.0000 

other-og-area34 209 -924.0 -924.0 -888.0 -888.0 -276.0 -240.0 -240.0 -276.0 1903.0 1296.0 2.3299 0.0234 0.0000 0.0000 0.0000 0.0000 

other-og-area35 215 -924.0 -924.0 -888.0 -888.0 -60.0 -24.0 -24.0 -60.0 2608.0 1296.0 2.6127 0.0062 0.0000 0.0000 0.0000 0.0000 

other-og-area36 220 -924.0 -924.0 -852.0 -852.0 120.0 192.0 192.0 120.0 2051.0 5184.0 233.3897 0.0283 0.0000 0.0000 0.0000 0.0000 

other-og-area37 222 -924.0 -924.0 -852.0 -852.0 192.0 240.0 240.0 192.0 2073.0 3456.0 3141.1988 0.3893 0.0000 0.0000 0.0000 0.0000 

other-og-area38 224 -888.0 -888.0 -852.0 -852.0 -312.0 -276.0 -276.0 -312.0 2316.0 1296.0 93.5897 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area39 254 -852.0 -852.0 -780.0 -780.0 192.0 240.0 240.0 192.0 2462.0 3456.0 1.1613 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area40 267 -816.0 -816.0 -780.0 -780.0 84.0 120.0 120.0 84.0 3004.0 1296.0 0.0135 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area41 268 -816.0 -816.0 -780.0 -780.0 120.0 156.0 156.0 120.0 3444.0 1296.0 0.1216 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area42 283 -780.0 -780.0 -744.0 -744.0 84.0 120.0 120.0 84.0 2981.0 1296.0 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area43 284 -780.0 -780.0 -744.0 -744.0 120.0 156.0 156.0 120.0 2469.0 1296.0 1.7589 0.0431 0.0000 0.0000 0.0000 0.0000 

other-og-area44 285 -780.0 -780.0 -744.0 -744.0 156.0 192.0 192.0 156.0 2682.0 1296.0 1.3134 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area45 286 -780.0 -780.0 -720.0 -720.0 192.0 240.0 240.0 192.0 3220.0 2880.0 111.3240 0.0000 0.0000 0.0000 0.0000 0.0000 

other-og-area46 301 -744.0 -744.0 -720.0 -720.0 156.0 192.0 192.0 156.0 2318.0 864.0 0.0828 0.0000 0.0000 0.0000 0.0000 0.0000 

No
March 2012

Appendix E

Project Alternatives Compression Inventories
Table E-1 Summary of Compression Emissions (Proposed Action) 

Station Location Elevation 

Additional Engines Proposed Actio

Proposed Action (t

1340 hp 2370 hp 1265 hp NOx CO S

Antelope Flats 39-59-44.53 N / 109-28-05.92 W 5022' 3 58.2 6.6 

Archie Bench 39-57-22.16 N / 109-24-41.48 W 5174' 4 77.6 8.8 

Bitter Creek 39-56-03.49 N / 109-29-07.13 W 5271' 1 19.4 2.2 

Blue Feather 40-02-16.65 N / 109-31-1.97 W 2 38.8 4.4 

Bonanza Central 39-58-37.60 N / 109-20-42.88 W 5274' Bonanza East 39-58-12.69 N / 109-17-20.56 W 5453' 2 38.8 4.4 

Bonanza West 39-57-57.73 N / 109-22-14.71 W 5298' 3 58.2 6.6 

Bridge 40-02-24.78 N / 109-27-22.37 W 4743' 2 38.8 4.4 

Cottonwood/West 3 40-00-33.77 N / 109-32-35.24 W 4952' 1 1 35.4 6.1 

Diablo 39-58-19.40 N / 109-17-33.25 W 4 64.1 16.0 East 39-58-10.59 N / 109-23-34.13 W 5123' 1 19.4 2.2 

East Bench 39-54-27.42 N / 109-27-58.21 W 5511' 

East Jr. 39-59-26.27 N / 109-23-06.69 W 4963' L16 40-01-29.14 N / 109-39-15.26 W 4871' Love 39-54-0.61 N/109-34-49.05 W 2 38.8 4.4 

Morgan State 39-59-46.13 N / 109-30-17.69 W 5004' North 40-02-08.01 N / 109-39-9.81 W 4816' Northeast 40-03-06.44 N / 109-32-28.69 W 4716' 

North Ouray 40-03-54.59 N/109-30-0.63 W 2 38.8 4.4 

Ouray 40-04-15.34 N /109-29-30.54 W 4704' 3 1 74.2 10.5 

Rimer Canyon 39-55-11.44 N /109-24-25.6 W 6 116.5 13.2 

Sage Grouse 39-54-13.57 N / 109-28-14.81 W 5493' 2 38.8 4.4 

Sand Wash 39-59-45.97 N / 10927-56.05 W 4986' 1 19.4 2.2 

South 39-56-56.77 N / 109-33-11.00 W 5176' 1 18.3 2.1 

South Central 39-59-44.53 N / 109-28-05.92 W 5022' 

Southeast 39-58-23.86 N / 109-26-39.72 W 5161' 

White River 39-58-12.27 N / 109-23-08.43 W 5160' 3 2 90.3 14.3 

Willow Creek 39-59-57.41 N / 109-34-38.90 W 4963' 3 5 74.2 10.5 

Total 958.3 127.3 

Proposed A
Antelope 

Proposed Action Over Baseline 

Operating Time Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion 

Brake Specific Fuel Consumption 

Proposed Number of Engines Rated Engine Capacity Maximum Design Heat Input 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)

(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 

7,000 

3 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 13.29 58.23 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.50 6.58 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.09 0.41 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.28 1.23 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 2.48 10.87 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
Archie Bench 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 4 Rated Engine Capacity 1340 (bhp)Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 17.73 77.64 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.00 8.77 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.13 0.55 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.37 1.64 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 3.31 14.49 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)

4 AP-42 Chapter 3.2 

Pro
Bitter Creek 

Proposed Action Over Baseline 

Operating Time Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion 

Brake Specific Fuel Consumption 

Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)

(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 

7,000 

1 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 4.43 19.41 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 0.50 2.19 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.03 0.14 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.09 0.41 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 0.83 3.62 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Pr
Blue Feather 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 2 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 8.86 38.82 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.00 4.38 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.06 0.27 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.19 0.82 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 1.65 7.25 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Pro
Bonanza East 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 2 Rated Engine Capacity 1340 (bhp)Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 8.86 38.82 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.00 4.38 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.06 0.27 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.19 0.82 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 1.65 7.25 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Prop
Bonanza West 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 3 Rated Engine Capacity 1340 (bhp)Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 13.29 58.23 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.50 6.58 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.09 0.41 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.28 1.23 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 2.48 10.87 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Propo
Bridge 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 2 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 8.86 38.82 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.00 4.38 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.06 0.27 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.19 0.82 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 1.65 7.25 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
Cottonwood-West Complex 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year) Fuel Sulfur Content 0.012 (gr/scf) Natural Gas Heating Value 950 (Btu/scf) Conversion 454 (g/lb) Conversion 7,000 (gr/lb) Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

1 @ 1340 (bhp) 9.38 (MMBtu/hr) Proposed Number of Engines 1 @ 2370 (bhp) 16.59 (MMBtu/hr) 

Pollutant Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) 

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 4.43 19.41 0.70 g/hp-hr 3.66 16.02 3.66 16.02 

CO 2.42 g/hp-hr 93% 0.50 2.19 0.50 2.19 2.50 g/hp-hr 0.89 3.88 0.89 3.88 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.03 0.14 2.34E-05 lb/hp-hr 0.06 0.24 0.06 0.24 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.09 0.41 9.99E-03 lb/MMBtu 0.17 0.73 0.17 0.73 NMHC 0.56 g/hp-hr 50% 0.83 3.62 0.83 3.62 0.83 g/hp-hr 1.46 6.41 1.46 6.41 

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H

4 AP-42 Chapter 3.2 

Proposed Action - 
Diablo 

Proposed Action Over Baseline 

Operating Time Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion 

Brake Specific Fuel Consumption 

Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)

(Btu/bhp-hr)

(bhp)(MMBtu/hr) 

0.012 

950 454 

7,000 

7,000 

4 

2370 

16.59 

Control Emission Rate 

Pollutant Emission Factor Eff Notes

(%) 

(per engine) (per station) 

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 0.70 g/hp-hr 3.66 16.02 14.63 64.08 1 

CO 2.50 g/hp-hr 93% 0.91 4.00 3.66 16.02 1, 2 

SO2 2.34E-05 lb/hp-hr 0.06 0.24 0.22 0.97 3 

PM10 9.99E-03 lb/MMBtu 0.17 0.73 0.66 2.90 4 

NMHC 0.83 g/hp-hr 50% 2.17 9.50 8.67 37.99 1,2 

1 Manufacturer Specification, CAT G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 
East 

Proposed Action Over Baseline 

Operating Time Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion 

Brake Specific Fuel Consumption 

Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)

(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 

7,000 

1 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 4.43 19.41 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 0.50 2.19 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.03 0.14 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.09 0.41 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 0.83 3.62 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
Love 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 2 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 8.86 38.82 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.00 4.38 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.06 0.27 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.19 0.82 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 1.65 7.25 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
North Ouray 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 2 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 8.86 38.82 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.00 4.38 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.06 0.27 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.19 0.82 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 1.65 7.25 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Pro
Ouray 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year) Fuel Sulfur Content 0.012 (gr/scf) Natural Gas Heating Value 950 (Btu/scf) Conversion 454 (g/lb) Conversion 7,000 (gr/lb) Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

3 @ Proposed Number of Engines 1 @ 1340 (bhp) 2370 (bhp) 9.38 (MMBtu/hr) 16.59 (MMBtu/hr) 

Pollutant Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) 

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 13.29 58.23 0.70 g/hp-hr 3.66 16.02 3.66 16.02 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.50 6.58 2.50 g/hp-hr 0.89 3.88 0.89 3.88 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.09 0.41 2.34E-05 lb/hp-hr 0.06 0.24 0.06 0.24 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.28 1.23 9.99E-03 lb/MMBtu 0.17 0.73 0.17 0.73 NMHC 0.56 g/hp-hr 50% 0.83 3.62 2.48 10.87 0.83 g/hp-hr 1.46 6.41 1.46 6.41 

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H

4 AP-42 Chapter 3.2 
Rimer Canyon 

Proposed Action Over Baseline 

Operating Time Fuel Sulfur Content Natural Gas Heating Value Conversion Conversion Brake Specific Fuel Consumption Proposed Number of Engines Rated Engine Capacity Maximum Design Heat Input 

8760 (hrs/year)

(gr/scf)(Btu/scf)(g/lb)(gr/lb)(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 7,000 

6 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 26.59 116.45 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 3.00 13.15 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.19 0.82 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.56 2.46 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.96 21.74 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Prop
Sage Grouse 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 2 Rated Engine Capacity 1340 (bhp)Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 8.86 38.82 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.00 4.38 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.06 0.27 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.19 0.82 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 1.65 7.25 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Pro
Sand Wash 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 1 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

(lb/hr) (tpy) (lb/hr) (tpy) 

(per engine) 

Emission Rate 

(per station) Notes 

NOx 1.50 g/hp-hr 4.43 19.41 4.43 19.41 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 0.50 2.19 1, 2 SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.03 0.14 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.09 0.41 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 0.83 3.62 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Pr
South 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year)Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 1 Rated Engine Capacity 1265 (bhp)

Fuel Usage 8.855 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

(lb/hr) (tpy) (lb/hr) (tpy) 

(per engine) 

Emission Rate 

(per station) Notes 

NOx 1.50 g/hp-hr 4.18 18.32 4.18 18.32 1 

CO 2.42 g/hp-hr 93% 0.47 2.07 0.47 2.07 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.13 0.03 0.13 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.39 0.09 0.39 4 NMHC 0.56 g/hp-hr 50% 0.78 3.42 0.78 3.42 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)

4 AP-42 Chapter 3.2 
White River 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year) Fuel Sulfur Content 0.012 (gr/scf) Natural Gas Heating Value 950 (Btu/scf) Conversion 454 (g/lb) Conversion 7,000 (gr/lb) Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

3 @ Proposed Number of Engines 2 @ 1340 (bhp) 2370 (bhp) 9.38 (MMBtu/hr) 16.59 (MMBtu/hr) 

Pollutant Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) 

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 13.29 58.23 0.70 g/hp-hr 3.66 16.02 7.31 32.04 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.50 6.58 2.50 g/hp-hr 0.89 3.88 1.77 7.75 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.09 0.41 2.34E-05 lb/hp-hr 0.06 0.24 0.11 0.49 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.28 1.23 9.99E-03 lb/MMBtu 0.17 0.73 0.33 1.45 NMHC 0.56 g/hp-hr 50% 0.83 3.62 2.48 10.87 0.83 g/hp-hr 1.46 6.41 2.93 12.82 

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H

4 AP-42 Chapter 3.2 

Pr
Willow Creek 

Proposed Action Over Baseline 

Operating Time 8760 (hrs/year) Fuel Sulfur Content 0.012 (gr/scf) Natural Gas Heating Value 950 (Btu/scf) Conversion 454 (g/lb) Conversion 7,000 (gr/lb) Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

3 @ Proposed Number of Engines 1 @ 1340 (bhp) 2370 (bhp) 9.38 (MMBtu/hr) 16.59 (MMBtu/hr)

Pollutant Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) 

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 13.29 58.23 0.70 g/hp-hr 3.66 16.02 3.66 16.02 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.50 6.58 2.50 g/hp-hr 0.89 3.88 0.89 3.88 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.09 0.41 2.34E-05 lb/hp-hr 0.06 0.24 0.06 0.24 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.28 1.23 9.99E-03 lb/MMBtu 0.17 0.73 0.17 0.73 NMHC 0.56 g/hp-hr 50% 0.83 3.62 2.48 10.87 0.83 g/hp-hr 1.46 6.41 1.46 6.41 

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H

4 AP-42 Chapter 3.2 

Pro
Table E-2 Summary of Compression Emissions (Optimal Recovery) 

Station Location Elevation 

Additional Engines Optimal Recove

Optimal Recovery (t

1340 hp 2370 hp 1265 hp NOx CO S

Antelope Flats 39-59-44.53 N / 109-28-05.92 W 5022' 5 97.0 11.0 

Archie Bench 39-57-22.16 N / 109-24-41.48 W 5174' 5 97.0 11.0 

Bitter Creek 39-56-03.49 N / 109-29-07.13 W 5271' 5 97.0 11.0 

Blue Feather 40-02-16.65 N / 109-31-1.97 W 5 97.0 11.0 

Bonanza Central 39-58-37.60 N / 109-20-42.88 W 5274' Bonanza East 39-58-12.69 N / 109-17-20.56 W 5453' 5 97.0 11.0 

Bonanza West 39-57-57.73 N / 109-22-14.71 W 5298' 5 97.0 11.0 

Bridge 40-02-24.78 N / 109-27-22.37 W 4743' 5 97.0 11.0 

Cottonwood/West 3 40-00-33.77 N / 109-32-35.24 W 4952' 2 5 118.9 23.8 

Diablo 39-58-19.40 N / 109-17-33.25 W 8 128.2 32.0 

East 39-58-10.59 N / 109-23-34.13 W 5123' 5 97.0 11.0 

East Bench 39-54-27.42 N / 109-27-58.21 W 5511' East Jr. 39-59-26.27 N / 109-23-06.69 W 4963' L16 40-01-29.14 N / 109-39-15.26 W 4871' Love 39-54-0.61 N/109-34-49.05 W 5 97.0 11.0 

Morgan State 39-59-46.13 N / 109-30-17.69 W 5004' North 40-02-08.01 N / 109-39-9.81 W 4816' Northeast 40-03-06.44 N / 109-32-28.69 W 4716' 

North Ouray 40-03-54.59 N/109-30-0.63 W 5 97.0 11.0 

Ouray 40-04-15.34 N /109-29-30.54 W 4704' 4 5 157.7 28.2 

Rimer Canyon 39-55-11.44 N /109-24-25.6 W 6 116.5 13.2 

Sage Grouse 39-54-13.57 N / 109-28-14.81 W 5493' 5 97.0 11.0 

Sand Wash 39-59-45.97 N / 10927-56.05 W 4986' 5 97.0 11.0 

South 39-56-56.77 N / 109-33-11.00 W 5176' 2 36.6 4.1 

South Central 39-59-44.53 N / 109-28-05.92 W 5022' 

Southeast 39-58-23.86 N / 109-26-39.72 W 5161' 

White River 39-58-12.27 N / 109-23-08.43 W 5160' 3 6 154.3 29.8 

Willow Creek 39-59-57.41 N / 109-34-38.90 W 4963' 3 5 138.3 26.0 

Total 2015.1 288.6 

Optimal Rec
Antelope 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)

Conversion 454 (g/lb)

Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 5 Rated Engine Capacity 1340 (bhp)

Maximum Design Heat Input 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10/PM2.5 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2

4 AP-42 Chapter 3.2 

O
Archie Bench 

Optimal Recovery Over Baseline 

Operating Time Fuel Sulfur Content Natural Gas Heating Value Conversion Conversion Brake Specific Fuel Consumption Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)(Btu/scf)(g/lb)(gr/lb)(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 7,000 

5 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Optim
Bitter Creek 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 5 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Opt
Blue Feather 

Optimal Recovery Over Baseline 

Operating Time Fuel Sulfur Content Natural Gas Heating Value Conversion Conversion Brake Specific Fuel Consumption Proposed Number of Engines Rated Engine Capacity 

Fuel Usage 

8760 (hrs/year)

(gr/scf)(Btu/scf)(g/lb)(gr/lb)(Btu/bhp-hr)(bhp)(MMBtu/hr) 

0.012 

950 454 

7,000 7,000 

5 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Optim
Bonanza East 

Optimal Recovery Over Baseline 

Operating Time 

Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion Brake Specific Fuel Consumption Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 7,000 

5 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Optim
Bonanza West 

Optimal Recovery Over Baseline 

Operating Time 

Fuel Sulfur Content Natural Gas Heating Value Conversion Conversion Brake Specific Fuel Consumption Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)(Btu/scf)(g/lb)(gr/lb)(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 7,000 

5 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Optima
Bridge 

Optimal Recovery Over Baseline 

Operating Time Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion 

Brake Specific Fuel Consumption 

Proposed Number of Engines Rated Engine Capacity 

Fuel Usage 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)

(Btu/bhp-hr)

(bhp)(MMBtu/hr) 

0.012 

950 454 

7,000 

7,000 

5 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
Cottonwood-West Complex 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year) 

Fuel Sulfur Content 0.012 (gr/scf) 

Natural Gas Heating Value 950 (Btu/scf) Conversion 454 (g/lb) Conversion 7,000 (gr/lb) 

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

2 @ Proposed Number of Engines 5 @ 1340 (bhp) 2370 (bhp) 9.38 (MMBtu/hr) 16.59 (MMBtu/hr)

Pollutant Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) 

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 8.86 38.82 0.70 g/hp-hr 3.66 16.02 18.29 80.10 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.00 4.38 2.50 g/hp-hr 0.89 3.88 4.43 19.38 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.06 0.27 2.34E-05 lb/hp-hr 0.06 0.24 0.28 1.22 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.19 0.82 9.99E-03 lb/MMBtu 0.17 0.73 0.83 3.63 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 1.65 7.25 0.83 g/hp-hr 1.46 6.41 7.31 32.04 

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H2

4 AP-42 Chapter 3.2 

Optimal Recovery - 
Diablo 

Optimal Recovery Over Baseline 

Operating Time Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion 

Brake Specific Fuel Consumption 

Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)

(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 

7,000 

8 

2370 

16.59 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 0.70 g/hp-hr 3.66 16.02 29.26 128.16 1 

CO 2.50 g/hp-hr 93% 0.91 4.00 7.31 32.04 1, 2 

SO2 2.34E-05 lb/hp-hr 0.06 0.24 0.44 1.94 3 

PM10 9.99E-03 lb/MMBtu 0.17 0.73 1.33 5.81 4 NMHC 0.83 g/hp-hr 50% 2.17 9.50 17.35 75.98 1,2 

1 Manufacturer Specification, CAT G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/M

4 AP-42 Chapter 3.2 
East 

Optimal Recovery Over Baseline 

Operating Time 

Fuel Sulfur Content Natural Gas Heating Value Conversion Conversion Brake Specific Fuel Consumption Proposed Number of Engines Rated Engine Capacity 

Fuel Usage 

8760 (hrs/year)

(gr/scf)(Btu/scf)(g/lb)(gr/lb)(Btu/bhp-hr)(bhp)(MMBtu/hr) 

0.012 

950 454 

7,000 7,000 

5 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
Love 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year)

Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 5 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
North Ouray 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year)Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 5 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Opti
Ouray 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year) 

Fuel Sulfur Content 0.012 (gr/scf) 

Natural Gas Heating Value 950 (Btu/scf) Conversion 454 (g/lb) Conversion 7,000 (gr/lb) 

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

4 @ Proposed Number of Engines 5 @ 1340 (bhp) 2370 (bhp) 9.38 (MMBtu/hr) 16.59 (MMBtu/hr) 

Pollutant Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) (l

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 17.73 77.64 0.70 g/hp-hr 3.66 16.02 18.29 80.10 3

CO 2.42 g/hp-hr 93% 0.50 2.19 2.00 8.77 2.50 g/hp-hr 0.89 3.88 4.43 19.38 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.13 0.55 2.34E-05 lb/hp-hr 0.06 0.24 0.28 1.22 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.37 1.64 9.99E-03 lb/MMB 0.17 0.73 0.83 3.63 NMHC 0.56 g/hp-hr 50% 0.83 3.62 3.31 14.49 0.83 g/hp-hr 1.46 6.41 7.31 32.04 1

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H

4 AP-42 Chapter 3.2 
Rimer Canyon 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year)Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 6 Rated Engine Capacity 1340 (bhp)

Maximum Design Heat Input 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 26.59 116.45 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 3.00 13.15 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.19 0.82 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.56 2.46 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.96 21.74 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Optim
Sage Grouse 

Optimal Recovery Over Baseline 

Operating Time Fuel Sulfur Content 

Natural Gas Heating Value Conversion Conversion 

Brake Specific Fuel Consumption 

Proposed Number of Engines Rated Engine Capacity Fuel Usage 

8760 (hrs/year)

(gr/scf)

(Btu/scf)(g/lb)(gr/lb)

(Btu/bhp-hr)

(bhp)

(MMBtu/hr) 

0.012 

950 454 

7,000 

7,000 

5 

1340 

9.38 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/

4 AP-42 Chapter 3.2 

Optim
Sand Wash 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year)Fuel Sulfur Content 0.012 (gr/scf)

Natural Gas Heating Value 950 (Btu/scf)Conversion 454 (g/lb)Conversion 7,000 (gr/lb)

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr)

Proposed Number of Engines 5 Rated Engine Capacity 1340 (bhp)

Fuel Usage 9.38 (MMBtu/hr) 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 22.16 97.05 1 

CO 2.42 g/hp-hr 93% 0.50 2.19 2.50 10.96 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.16 0.69 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.47 2.05 4 NMHC 0.56 g/hp-hr 50% 0.83 3.62 4.14 18.12 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 

Opt
South 

Optimal Recovery Over Baseline 

Operating Time 

Fuel Sulfur Content Natural Gas Heating Value Conversion Conversion Brake Specific Fuel Consumption Proposed Number of Engines Rated Engine Capacity 

Fuel Usage 

8760 (hrs/year)

(gr/scf)(Btu/scf)(g/lb)(gr/lb)(Btu/bhp-hr)(bhp)(MMBtu/hr) 

0.012 

950 454 

7,000 7,000 

2 

1265 

8.855 

Pollutant Emission Factor 

(%) 

Control 

Eff 

Emission Rate 

(per engine) (per station) Notes

(lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.18 18.32 8.37 36.65 1 

CO 2.42 g/hp-hr 93% 0.47 2.07 0.94 4.14 1, 2 

SO2 2.34E-05 lb/hp-hr 0.03 0.13 0.06 0.26 3 

PM10 9.99E-03 lb/MMBtu 0.09 0.39 0.18 0.77 4 NMHC 0.56 g/hp-hr 50% 0.78 3.42 1.56 6.84 1,2 

1 Manufacturer Specification, CAT G3516 LE Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 

4 AP-42 Chapter 3.2 
White River 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year) 

Fuel Sulfur Content 0.012 (gr/scf) 

Natural Gas Heating Value 950 (Btu/scf) Conversion 454 (g/lb) Conversion 7,000 (gr/lb) 

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

3 @ Proposed Number of Engines 6 @ 1340 (bhp) 2370 (bhp) 9.38 (MMBtu/hr) 16.59 (MMBtu/hr) 

Pollutant Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) 

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 13.29 58.23 0.70 g/hp-hr 3.66 16.02 21.94 96.12 

CO 2.42 g/hp-hr 93% 0.50 2.19 1.50 6.58 2.50 g/hp-hr 0.89 3.88 5.31 23.26 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.09 0.41 2.34E-05 lb/hp-hr 0.06 0.24 0.33 1.46 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.28 1.23 9.99E-03 lb/MMBtu 0.17 0.73 0.99 4.35 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 2.48 10.87 0.83 g/hp-hr 1.46 6.41 8.78 38.45 

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H2S

4 AP-42 Chapter 3.2 

Opt
Willow Creek 

Optimal Recovery Over Baseline 

Operating Time 8760 (hrs/year) Fuel Sulfur Content 0.012 (gr/scf) 

Natural Gas Heating Value 950 (Btu/scf) 

Conversion 454 (g/lb) 

Conversion 7,000 (gr/lb) 

Brake Specific Fuel Consumption 7,000 (Btu/bhp-hr) 

3 @ 1340 (bhp) 9.38 (MMBtu/hr) Proposed Number of Engines 5 @ 2370 (bhp) 16.59 (MMBtu/hr) 

Pollutan Emission Factor 

Control 

Eff 

3516 Engine 3608 Engine 

Emission Rate Emission Factor Emission Rate (per engine) (per station) (per engine) (per station) (l

(%) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) 

NOx 1.50 g/hp-hr 4.43 19.41 13.29 58.23 0.70 g/hp-hr 3.66 16.02 18.29 80.10 3

CO 2.42 g/hp-hr 93% 0.50 2.19 1.50 6.58 2.50 g/hp-hr 0.89 3.88 4.43 19.38 

SO2 2.34E-05 lb/hp-hr 0.03 0.14 0.09 0.41 2.34E-05 lb/hp-hr 0.06 0.24 0.28 1.22 

PM10 9.99E-03 lb/MMBtu 0.09 0.41 0.28 1.23 9.99E-03 lb/MMBtu 0.17 0.73 0.83 3.63 

NMHC 0.56 g/hp-hr 50% 0.83 3.62 2.48 10.87 0.83 g/hp-hr 1.46 6.41 7.31 32.04 

1 Manufacturer Specification, CAT G3516 LE and G3608 Engine 2 93% CO Control Efficiency for oxidation catalyst; 50% VOC control efficiency 3

 EF (lb/hp-hr) = BSFC (Btu/bhp-hr) / Heating Value (Btu/scf) x Fuel Sulfur Content (gr/scf) / 7000 (gr/lb) x MW (SO 2)/MW (H

4 AP-42 Chapter 3.2 

Optim
March 2012

Appendix F

SANGEA Output for Analysis of Greenhouse Gases
SANGEA (TM) Energy Emissions Estimating System

Primary Production & Performance Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun 

Total Emissions tonne 1,761,016 435,608 437,269 442,549 445,590 150,090 136,048 149,470 144,210 148,850 144,210 

Total BOE bbl 33,766,667 8,326,027 8,418,539 8,511,050 8,511,050 2,867,854 2,590,320 2,867,854 2,775,342 2,867,854 2,775,342 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emissions for E&P tonne 304,583 76,461 74,153 75,464 78,505 26,405 24,271 25,785 24,494 25,165 24,494 

BOE for E&P bbl 16,883,333 4,163,014 4,209,269 4,255,525 4,255,525 1,433,927 1,295,160 1,433,927 1,387,671 1,433,927 1,387,671 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission for E&P tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission for E&P tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy for E&P 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy for E&P 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emissions for Midstream tonne 1,456,433 359,147 363,116 367,085 367,085 123,685 111,778 123,685 119,716 123,685 119,716 

BOE for Midstream bbl 16,883,333 4,163,014 4,209,269 4,255,525 4,255,525 1,433,927 1,295,160 1,433,927 1,387,671 1,433,927 1,387,671 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission for Midstream tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission for Midstream tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy for Midstream 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy for Midstream 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Secondary Production Measures Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun Forecast Emissions Units 2008 2009 2010 2011 2012

BOE bbl 33,766,667

Forecast Emissions (Excl Flaring) tonne 1,760,770

Flaring Emissions tonne 246

Total Forecast Emissions tonne 1,761,016 0000

Report by Location CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) Total CO2e Energy (10^3 Btu (LHV))

E&P 209,440 4,351 12.2 91,374 3,769 304,583 3,106,833,911

Midstream 1,351,304 4,672 22.6 98,121 7,007 1,456,433 16,299,920,120

Total (tonne): 1,560,744 9,024 34.8 189,496 10,777 1,761,016 19,406,754,031

Report by Module CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) CO2e Energy (10^3 Btu (LHV))

Combustion 569,774 24 19.0 508 5,884 576,166 9,141,718,895

Flare 239 0 0.0 5 1 246 n/a

Flashing 0 1,463 0.0 30,730 0 30,730 n/a

Fugitive n/a 6,056 n/a 127,182 n/a 127,182 n/a

Indirect Emission 990,719 7 15.8 144 4,891 995,754 10,265,035,136

Miscellaneous 0 0 0.0 0 0 0 n/a

Venting 12 1,473 n/a 30,926 n/a 30,938 n/a

Total (tonne): 1,560,744 9,024 34.8 189,496 10,777 1,761,016 19,406,754,031

Key Input Data Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun 

Diesel / Distillate (No. 2) 10^3 gal 10,087 2,609 2,338 2,421 2,719 915 841 854 772 793 772 

Gasoline 10^3 gal 467 115 117 118 118 40 36 40 38 40 38 

Unitah Fuel Gas 10^6 Btu (HHV) 1,992,900 491,400 496,860 502,320 502,320 169,260 152,880 169,260 163,800 169,260 163,800 

GNB Fuel Gas 10^6 Btu (HHV) 6,643,365 1,638,090 1,656,291 1,674,492 1,674,492 564,231 509,628 564,231 546,030 564,231 546,030 

Electricity GWh 1,039 256 259 262 262 88 80 88 85 88 85 

CO2 (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 209,427 0 0 n/a 0 0 12 209,440

Midstream 360,346 239 0 n/a 990,719 0 0 1,351,304

Total (tonne): 569,774 239 0 0 990,719 0 12 1,560,744

CH4 (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 17 0 129 2,732 0 0 1,473 4,351

Midstream 7 0 1,334 3,324 7 0 0 4,672

Total (tonne): 24 0 1,463 6,056 7 0 1,473 9,024

N2O (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 12.2 0.0 0.0 n/a 0.0 0.0 n/a 12.2

Midstream 6.8 0.0 0.0 n/a 15.8 0.0 n/a 22.6

Total (tonne): 19.0 0.0 0.0 0.0 15.8 0.0 0.0 34.8

CO2e (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 213,554 n/a 2,719 57,372 n/a n/a 30,938 304,583

Midstream 362,612 246 28,012 69,809 995,754 n/a n/a 1,456,433

Total (tonne): 576,166 246 30,730 127,182 995,754 0 30,938 1,761,016

File: 1 - SANGEA Greater Natural Buttes ENSR No Action - Summary 
SANGEA (TM) Energy Emissions Estimating System

Primary Production & Performance Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun 

Total Emissions tonne 2,754,167 681,544 683,544 691,880 697,200 234,829 212,971 233,744 225,443 232,658 225,443 

Total BOE bbl 106,300,000 26,210,959 26,502,192 26,793,425 26,793,425 9,028,219 8,154,521 9,028,219 8,736,986 9,028,219 8,736,986 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emissions for E&P tonne 856,895 213,688 210,518 213,684 219,005 73,707 67,359 72,622 69,491 71,537 69,491 

BOE for E&P bbl 53,150,000 13,105,479 13,251,096 13,396,712 13,396,712 4,514,110 4,077,260 4,514,110 4,368,493 4,514,110 4,368,493 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission for E&P tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission for E&P tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy for E&P 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy for E&P 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emissions for Midstream tonne 1,897,272 467,856 473,026 478,195 478,195 161,122 145,613 161,122 155,952 161,122 155,952 

BOE for Midstream bbl 53,150,000 13,105,479 13,251,096 13,396,712 13,396,712 4,514,110 4,077,260 4,514,110 4,368,493 4,514,110 4,368,493 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission for Midstream tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission for Midstream tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy for Midstream 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy for Midstream 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Secondary Production Measures Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun Forecast Emissions Units 2008 2009 2010 2011 2012

BOE bbl 106,300,000

Forecast Emissions (Excl Flaring) tonne 2,753,393

Flaring Emissions tonne 775

Total Forecast Emissions tonne 2,754,167 0000

Report by Location CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) Total CO2e Energy (10^3 Btu (LHV))

E&P 601,845 11,767 25.6 247,112 7,938 856,895 9,376,469,385

Midstream 1,629,608 12,334 27.9 259,022 8,642 1,897,272 19,722,093,151

Total (tonne): 2,231,452 24,102 53.5 506,135 16,580 2,754,167 29,098,562,536

Report by Module CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) CO2e Energy (10^3 Btu (LHV))

Combustion 1,053,067 44 34.7 925 10,762 1,064,753 16,897,101,138

Flare 753 1 0.0 17 5 775 n/a

Flashing 0 4,245 0.0 89,142 0 89,142 n/a

Fugitive n/a 17,142 n/a 359,973 n/a 359,973 n/a

Indirect Emission 1,177,611 8 18.8 171 5,814 1,183,596 12,201,461,398

Miscellaneous 0 0 0.0 0 0 0 n/a

Venting 21 2,662 n/a 55,907 n/a 55,928 n/a

Total (tonne): 2,231,452 24,102 53.5 506,135 16,580 2,754,167 29,098,562,536

Key Input Data Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun 

Diesel / Distillate (No. 2) 10^3 gal 18,144 4,688 4,213 4,361 4,883 1,642 1,510 1,536 1,392 1,429 1,392 

Gasoline 10^3 gal 1,417 350 353 357 357 120 109 120 117 120 117 

Unitah Fuel Gas 10^6 Btu (HHV) 7,830,564 1,930,824 1,952,278 1,973,731 1,973,731 665,062 600,701 665,062 643,608 665,062 643,608 

GNB Fuel Gas 10^6 Btu (HHV) 8,128,535 2,004,296 2,026,566 2,048,836 2,048,836 690,369 623,559 690,369 668,099 690,369 668,099 

Electricity GWh 1,235 305 308 311 311 105 95 105 102 105 102 

CO2 (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 601,824 0 0 n/a 0 0 21 601,845

Midstream 451,244 753 0 n/a 1,177,611 0 0 1,629,608

Total (tonne): 1,053,067 753 0 0 1,177,611 0 21 2,231,452

CH4 (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 34 0 408 8,663 0 0 2,662 11,767

Midstream 10 1 3,837 8,478 8 0 0 12,334

Total (tonne): 44 1 4,245 17,142 8 0 2,662 24,102

N2O (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 25.6 0.0 0.0 n/a 0.0 0.0 n/a 25.6

Midstream 9.1 0.0 0.0 n/a 18.8 0.0 n/a 27.9

Total (tonne): 34.7 0.0 0.0 0.0 18.8 0.0 0.0 53.5

CO2e (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 610,482 n/a 8,559 181,926 n/a n/a 55,928 856,895

Midstream 454,272 775 80,583 178,047 1,183,596 n/a n/a 1,897,272

Total (tonne): 1,064,753 775 89,142 359,973 1,183,596 0 55,928 2,754,167

File: 2 - SANGEA Greater Natural Buttes ENSR Proposed Action - Summary 
SANGEA (TM) Energy Emissions Estimating System

Primary Production & Performance Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun 

Total Emissions tonne 5,484,666 1,357,206 1,361,178 1,377,820 1,388,462 467,668 424,041 465,498 448,925 463,327 448,925 

Total BOE bbl 205,566,667 50,687,671 51,250,868 51,814,064 51,814,064 17,459,087 15,769,498 17,459,087 16,895,890 17,459,087 16,895,890 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emissions for E&P tonne 2,406,281 598,117 593,683 601,920 612,561 206,233 187,822 204,062 195,895 201,892 195,895 

BOE for E&P bbl 102,783,333 25,343,836 25,625,434 25,907,032 25,907,032 8,729,543 7,884,749 8,729,543 8,447,945 8,729,543 8,447,945 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission for E&P tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission for E&P tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy for E&P 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy for E&P 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emissions for Midstream tonne 3,078,385 759,089 767,495 775,900 775,900 261,435 236,218 261,435 253,030 261,435 253,030 

BOE for Midstream bbl 102,783,333 25,343,836 25,625,434 25,907,032 25,907,032 8,729,543 7,884,749 8,729,543 8,447,945 8,729,543 8,447,945 

CO 2 e / BOE tonne/bbl 0 0 0 0 0 0 0 0 0 0 0 

Actual Emission for Midstream tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Emission for Midstream tonne/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Emission Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Actual Energy for Midstream 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Standard Energy for Midstream 10^6 Btu/Day n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Energy Index Index n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Secondary Production Measures Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun Forecast Emissions Units 2008 2009 2010 2011 2012

BOE bbl 205,566,667

Forecast Emissions (Excl Flaring) tonne 5,483,168

Flaring Emissions tonne 1,498

Total Forecast Emissions tonne 5,484,666 0000

Report by Location CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) Total CO2e Energy (10^3 Btu (LHV))

E&P 1,905,882 22,884 64.0 480,557 19,842 2,406,281 30,552,083,573

Midstream 2,613,769 21,433 46.9 450,090 14,526 3,078,385 32,123,458,098

Total (tonne): 4,519,651 44,317 110.9 930,647 34,368 5,484,666 62,675,541,671

Report by Module CO2 CH4 N2O CH4 (CO2e) N2O (CO2e) CO2e Energy (10^3 Btu (LHV))

Combustion 2,725,513 102 82.3 2,138 25,509 2,753,160 44,101,657,114

Flare 1,456 2 0.0 33 9 1,498 n/a

Flashing 0 13,709 0.0 287,883 0 287,883 n/a

Fugitive n/a 24,870 n/a 522,260 n/a 522,260 n/a

Indirect Emission 1,792,639 12 28.5 261 8,850 1,801,750 18,573,884,557

Miscellaneous 0 0 0.0 0 0 0 n/a

Venting 43 5,622 n/a 118,072 n/a 118,115 n/a

Total (tonne): 4,519,651 44,317 110.9 930,647 34,368 5,484,666 62,675,541,671

Key Input Data Units YTD Qtr1 Qtr2 Qtr3 Qtr4 Jan Feb Mar Apr May Jun 

Diesel / Distillate (No. 2) 10^3 gal 36,800 9,501 8,554 8,850 9,894 3,328 3,059 3,115 2,826 2,902 2,826 

Gasoline 10^3 gal 4,926 1,215 1,228 1,242 1,242 418 378 418 405 418 405 

Unitah Fuel Gas 10^6 Btu (HHV) 28,826,094 7,107,804 7,186,780 7,265,755 7,265,755 2,448,244 2,211,317 2,448,244 2,369,268 2,448,244 2,369,268 

GNB Fuel Gas 10^6 Btu (HHV) 14,183,885 3,497,396 3,536,256 3,575,116 3,575,116 1,204,659 1,088,079 1,204,659 1,165,799 1,204,659 1,165,799 

Electricity GWh 1,880 464 469 474 474 160 144 160 155 160 155 

CO2 (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 1,905,839 0 0 n/a 0 0 43 1,905,882

Midstream 819,674 1,456 0 n/a 1,792,639 0 0 2,613,769

Total (tonne): 2,725,513 1,456 0 0 1,792,639 0 43 4,519,651

CH4 (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 82 0 788 16,391 0 0 5,622 22,884

Midstream 20 2 12,921 8,478 12 0 0 21,433

Total (tonne): 102 2 13,709 24,870 12 0 5,622 44,317

N2O (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 64.0 0.0 0.0 n/a 0.0 0.0 n/a 64.0

Midstream 18.3 0.0 0.0 n/a 28.5 0.0 n/a 46.9

Total (tonne): 82.3 0.0 0.0 0.0 28.5 0.0 0.0 110.9

CO2e (by Location & Module) Combustion Flare Flashing Fugitive Indirect Emissi Miscellaneous Venting Total (tonne):

E&P 1,927,403 n/a 16,551 344,213 n/a n/a 118,115 2,406,281

Midstream 825,758 1,498 271,332 178,047 1,801,750 n/a n/a 3,078,385

Total (tonne): 2,753,160 1,498 287,883 522,260 1,801,750 0 118,115 5,484,666

File: 3 - SANGEA Greater Natural Buttes ENSR Optimal Recovery - Summary