International Corporation Air Sciences

Final Report

OIL AND GAS EMISSION INVENTORIES 

FOR THE WESTERN STATES 

Prepared for 

Western Governors’ Association 

1515 Cleveland Place, Suite 200 

Denver, CO 80202 

Prepared by 

James Russell 

Alison Pollack 

ENVIRON International Corporation 

101 Rowland Way, Suite 220 

Novato, CA 94945 

December 27, 2005 

 101 Rowland Way, Suite 220, Novato, CA 94945 415.899.0700 
December 2005 

i 

TABLE OF CONTENTS 

Page 

PREFACE ................................................................................................................................ iv 

1. INTRODUCTION................................................................................................................ 1-1 

2. 2002 BASE YEAR EMISSION INVENTORY ................................................................. 2-1 

Introduction............................................................................................................................ 2-1 

Major NOx Source Inventory ................................................................................................ 2-3 

VOC and Minor NOx Source Inventory.............................................................................. 2-26 

3. SPATIAL ALLOCATION SURROGATES FOR MODELING .................................... 3-1 

4. 2018 BASE CASE PROJECTIONS................................................................................... 4-1 

 Introduction............................................................................................................................ 4-1 

 Area Source Oil and Gas Growth Factors.............................................................................. 4-3 

5. REFERENCES..................................................................................................................... 5-1 

APPENDICES 

Appendix A: Wyoming Emission Factor Documentation 

Appendix B: Sample Calculations for the VOC and Minor NOx Processes 

Appendix C: Nonroad Diesel Fuel Sulfur Levels 

Appendix D: 2002 to 2018 Oil and Gas Growth Factors 

TABLES 

Table 2-1a. 2002 State total NOx emissions (tons) from oil and gas sources ........................ 2-2 

Table 2-1b. 2002 State total VOC emissions (tons) from oil and gas area sources ................ 2-2 

Table 2-2. Change in oil and gas emissions in the 2002 inventory 

 as a result of this inventory effort ........................................................................ 2-3 

Table 2-3. Source of drill permit data ................................................................................... 2-4 

Table 2-4. Situations where formation-specific emission factors could not be created........ 2-7 

Table 2-5. State total drill rig emissions................................................................................ 2-9 

Table 2-6. 2002 gas production in the San Juan Basin – New Mexico............................... 2-12 

Table 2-7. Summarized results of review of compressor engine studies ............................ 2-14 

Table 2-8. State controls on compressor engines and controlled emission factors............. 2-15 
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ii 

Table 2-9. State total NOx emissions from gas compressor engines .................................. 2-16 

Table 2-10. State point source inventory thresholds ............................................................. 2-17 

Table 2-11. Oil and gas SIC .................................................................................................. 2-18 

Table 2-12. Emissions for New Mexico natural gas facilities with a 

 PTE between 25 and 100 tpy ............................................................................. 2-19 

Table 2-13. Area source emissions estimate for facilities with a 

 PTE between 25 and 100 tpy ............................................................................. 2-19 

Table 2-14. Assumptions used in developing the CBM generator emissions estimate ........ 2-21 

Table 2-15. State total NOx emissions from coalbed methane engines................................ 2-26 

Table 2-16. Emissions sources estimated in the VOC and minor NOx source inventory .... 2-26 

Table 2-17. Wyoming DEQ emission factors ....................................................................... 2-27 

Table 2-18. Well-specific data obtained from the oil and gas commissions......................... 2-27 

Table 2-19. Sources of well-specific production data........................................................... 2-28 

Table 2-20. Coalbed methane producing formations in New Mexico .................................. 2-29 

Table 2-21. Controls on sources considered in the VOC and minor 

 NOx source inventory........................................................................................ 2-31 

Table 2-22. Summary of control-adjusted gas well emission factors for 

 VOC and minor NOx sources............................................................................ 2-33 

Table 2-23. State total emissions for VOC and minor NOx sources .................................... 2-34 

Table 3-1. Emission sources and surrogate categories.......................................................... 3-1 

Table 3-2. SMOKE gridding surrogate cross-reference (AGREF) file................................. 3-3 

Table 4-1a. 2018 State total NOx emissions (tons) from oil and gas sources. ....................... 4-2 

Table 4-1b. 2018 State total VOC emissions (tons) from oil and gas sources........................ 4-2 

Table 4-2. Change in oil and gas NOx emissions from 2002 to 2018 .................................. 4-3 

Table 4-3. BLM Resource Management Plans considered for use in projections ................ 4-4 

Table 4-4. 2002 to 2018 oil and gas growth factors based on EIA forecasts........................ 4-6 

Table 4-5. Projection growth factors..................................................................................... 4-8 

Table 4-6. Growth factor used for each source in areas where local plans were used.......... 4-9 

Table 4-7. Growth factor used for each source in areas where EIA data were used............. 4-9 

Table 4-8. State NOx emission factors used to estimate 2018 emissions ........................... 4-11 

Table 4-9. 2018 emissions estimates for counties with no 2002 emissions........................ 4-12 

Table 4-10. Projection information provided by State DEQ................................................. 4-12 

FIGURES 

Figure 2-1. Distribution of well preparation activities within a single formation.................. 2-5 

Figure 2-2. Wells drilled in 2002 in the WRAP states ......................................................... 2-10 

Figure 2-3. Wellhead compressor engine ............................................................................. 2-11 

Figure 2-4. County-level 2002 gas compressor engine emissions ....................................... 2-16 

Figure 2-5. Western U.S. Coal bed methane fields (EIA, 2004).......................................... 2-20 

Figure 2-6. Diagram of assumed CBM well......................................................................... 2-22 

Figure 2-7. Distribution of Colorado wells based on the ratio of gas 

 production to oil production............................................................................... 2-29 

Figure 2-8. Coal bed methane fields in New Mexico........................................................... 2-30 

Figure 3-1. Locations of wells and drill rigs........................................................................... 3-2 

Figure 3-2. Oil production surrogates for the 36 km domain................................................. 3-4 

Figure 3-3. Gas production surrogates for the 36 km domain................................................ 3-5 

Figure 3-4. CBM well water production surrogates for the 36 km domain ........................... 3-6 
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iii 

Figure 3-5. Drill rig surrogates for the 36 km domain ........................................................... 3-7 

Figure 3-6. Oil production surrogates for the 12 km domain................................................. 3-8 

Figure 3-7. Gas production surrogates for the 12 km domain................................................ 3-9 

Figure 3-8. CBM well water production surrogates for the 12 km domain ......................... 3-10 

Figure 3-9. Drill rig surrogates for the 12 km domain ......................................................... 3-11 

Figure 3-10. Example daily spatial emissions plot of the 2002 oil and gas 

 emissions as processed through SMOKE .......................................................... 3-12 

Figure 4-1. Coverage of resource management plans ultimately 

 used to create growth factors ............................................................................... 4-5 

Figure 4-2. EIA production forecasting regions..................................................................... 4-6 

Figure 4-3. Sample application of growth factors derived from 

 RMP and from EIA sources............................................................................... 4-10 

Figure 4-4. Growth factors developed to represent growth in gas 

 production in WRAP region .............................................................................. 4-10 
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PREFACE 

Regulatory Framework for Tribal Visibility Implementation Plans 

The Regional Haze Rule explicitly recognizes the authority of tribes to implement the provisions 

of the Rule, in accordance with principles of Federal Indian law, and as provided by the Clean 

Air Act (CAA) §301(d) and the Tribal Authority Rule (TAR) (40 CFR §§49.1– .11). Those 

provisions create the following framework: 

1. Absent special circumstances, reservation lands are not subject to state jurisdiction. 

2. Federally recognized tribes may apply for and receive delegation of federal authority to 

implement CAA programs, including visibility regulation, or "reasonably severable" elements of 

such programs (40 CFR §§49.3, 49.7). The mechanism for this delegation is a Tribal 

Implementation Plan (TIP). A reasonably severable element is one that is not integrally related 

to program elements that are not included in the plan submittal, and is consistent with applicable 

statutory and regulatory requirements. 

3. The Regional Haze Rule expressly provides that tribal visibility programs are “not dependent 

on the strategies selected by the state or states in which the tribe is located” (64. Fed. Reg. 

35756), and that the authority to implement §309 TIPs extends to all tribes within the GCVTC 

region (40 CFR §51.309(d)(12). 

4. The EPA has indicated that under the TAR tribes are not required to submit §309 TIPs by the 

end of 2003; rather they may choose to opt-in to §309 programs at a later date (67 Fed. Reg. 

30439). 

5. Where a tribe does not seek delegation through a TIP, EPA, as necessary and appropriate, will 

promulgate a Federal Implementation Plan (FIP) within reasonable timeframes to protect air 

quality in Indian country (40 CFR §49.11). EPA is committed to consulting with tribes on a 

government to government basis in developing tribe-specific or generally applicable TIPs where 

necessary (See, e.g., 63 Fed. Reg.7263-64). 

 

The amount of modification necessary will vary considerably from tribe to tribe. The authors 

have striven to ensure that all references to tribes in the document are consistent with principles 

of tribal sovereignty and autonomy as reflected in the above framework. Any inconsistency with 

this framework is strictly inadvertent and not an attempt to impose requirements on tribes which 

are not present under existing law. 
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Tribal Participation in the WRAP 

Tribes, along with states and federal agencies, are full partners in the WRAP, having equal 

representation on the WRAP Board as states. Whether Board members or not, it must be 

remembered that all tribes are governments, as distinguished from the “stakeholders” (private 

interest) which participate on Forums and Committees but are not eligible for the Board. 

 

Despite this equality of representation on the Board, tribes are very differently situated than 

states. There are over four hundred federally recognized tribes in the WRAP region, including 

Alaska. The sheer number of tribes makes full participation impossible. Moreover, many tribes 

are faced with pressing environmental, economic, and social issues, and do not have the 

resources to participate in an effort such as the WRAP, however important its goals may be. 

These factors necessarily limit the level of tribal input into and endorsement of WRAP products. 

The tribal participants in the WRAP, including Board members Forum and Committee members 

and co-chairs, make their best effort to ensure that WRAP products are in the best interest of the 

tribes, the environment, and the public. One interest is to ensure that WRAP policies, as 

implemented by states and tribes, will not constrain the future options of tribes who are not 

involved in the WRAP. With these considerations and limitations in mind, the tribal participants 

have joined the state, federal, and private stakeholder interests in approving this report as a 

consensus document. 

An adjunct study of oil and gas emissions point and area source emissions was conducted by 

ENVIRON and ERG. Oil and gas emissions for four tribes were inventoried: Wind River 

Reservation, Ute Mountain Ute Tribe, Navajo Nation, and Jicarilla Apache Nation. Emissions 

sources for the Jicarilla Apache Nation were inventoried, but they elected to not formally 

participate in the project. The final project report, Point Source and Oil and Gas Area Source 

Emission Inventories on Native American Reservations and Tribal Lands (ERG/ENVIRON, 

2005), does not include Jicarilla Apache data. 
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1. INTRODUCTION 

The oil and gas production industry considered in this study includes a large number of processes 

and equipment types that stretch from the wellhead to fuel distribution networks. Many of these 

processes emit significant quantities of nitrous oxides (NOx), volatile organic compounds (VOC) 

and other pollutants. Past emission inventories have estimated emissions from specific pieces of 

equipment, for limited geographic areas and for other segments of the industry. The largest oil 

and gas production facilities, gas plants and major compressor stations, have been previously 

inventoried as stationary sources. All states in the western region had previously compiled 

emission inventories for the year 2002 that included the major “point” emission sources in the oil 

and gas production industry. However, what was included in these emission inventories varied 

from state to state, depending on the permitting and/or reporting thresholds. 

Oil and gas production facilities that are geographically distributed and have lesser emissions 

than the point source threshold are considered area sources. Prior to this study, there had not 

been a comprehensive emission inventory of oil and gas production operations in the western 

region that covered both point and area sources. Nor had there been a methodology developed to 

produce an inventory of this scope. The objective of the present study has thus been to develop 

and implement a uniform procedure for estimating area source emissions from oil and gas 

production operations across the western region. The emphasis of this study was placed on 

estimating emissions of pollutants with the potential to impair visibility near Class I areas in the 

west, in particular NOx emissions. 

As this was the first effort to develop a regionally consistent emission inventory for oil and gas 

area sources, and resources were limited, this inventory is neither comprehensive nor as accurate 

as it might be with more resources. The focus was on the larger sources of NOx emissions; NOx 

and VOC emissions from minor wellhead processes for which emission factors were available 

were also estimated. This inventory and the methodology used should be considered as a first 

step toward a better understanding of oil and gas emissions, and the basis for further work to 

improve the estimates. 

In developing the emission estimation methodology, considerable resources were devoted to 

incorporating the insights and guidance of a variety of stakeholders, as well as integrating the 

point source emissions estimates developed in previous inventory efforts. The work plans that 

guided this project were developed with substantial feedback from members of the WRAP 

Stationary Sources Joint Forum (SSJF) Oil and Gas Work Group. 

The 2002 oil and gas point source emissions have been adopted from the state inventories (ERG, 

2005a). The level of coverage in those inventories was evaluated and the point source emissions 

have been reconciled with emissions estimated using the newly developed area source inventory 

methodology. 

Oil and gas point source emission inventories include location parameters. For the oil and gas 

area source emissions estimated in this project, a new spatial allocation scheme was developed to 

facilitate the integration of these emissions sources into the WRAP regional haze modeling. 

New spatial surrogates were developed for each of the non-point oil and gas emission sources 

addressed by this inventory. These surrogates, which are based on the geographic locations of 
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oil and gas production, will enable the appropriate spatial distribution of emissions from oil and 

gas production operations in the air quality modeling. 

 

The final task of this project was to formulate and implement a procedure to project the 

emissions from oil and gas production operations in 2018. For the WRAP 2018 base case 

modeling, only those emission control strategies that have already been adopted are considered. 

Once again, the work plan that guided the development of the projection method was developed 

in collaboration with the stakeholders represented in the SSJF Oil And Gas Work Group. 

Ultimately, oil and gas production forecasts were drawn from several sources and combined with 

the emissions estimates produced for the 2002 inventory and information on future controls to 

arrive at the 2018 inventory. Oil and gas point source projections are described in a separate 

report (ERG, 2005b). 

This report describes the procedures developed in each task of this project and the results that 

have been obtained. Section 2 presents the methodology developed to create a comprehensive 

oil and gas emissions inventory for the western region and summarizes the emission inventory 

that was prepared for the year 2002. Section 3 then details the process used to create the spatial 

allocation surrogates that will appropriately assign oil and gas emissions to the locations where 

they occur. Section 4 describes the data sources and methods that have been used to project 

emissions in the year 2018, and provides the resulting emissions estimates. 
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2. 2002 BASE YEAR EMISSION INVENTORY 

INTRODUCTION 

This section describes the base year 2002 emission inventory of oil and gas area sources for the 

Western States. The focus of this inventory effort was to estimate emissions of nitrous oxides 

(NOx) from oil and gas production operations. In the early stages of this project, major NOx 

sources were identified and methodologies were defined for estimating emissions from those 

sources. The major NOx sources addressed by this inventory are: drill rigs, gas compressor 

engines, and coalbed methane pump engines. Emissions from minor NOx and VOC wellhead 

processes for which emission factors were available were also estimated. 

Emissions for oil and gas point sources are also being provided by ENVIRON, but they are not 

addressed in this document beyond what is necessary to describe measures used to eliminate 

double counting. Also, the emissions summaries presented in this document do not include 

emissions classified as falling under tribal jurisdiction. ENVIRON has prepared separate 

emissions estimates of tribal oil and gas emissions for four tribes. Those emissions estimates are 

reconciled with the emissions reported here, and separate documentation of tribal emissions has 

been prepared (ERG/ENVIRON, 2005). 

Apart from those western states that have no oil or gas production, such as Idaho and 

Washington, the only state for which area source emissions are not estimated is the State of 

California. The California Air Resources Board (CARB) has provided area source oil and gas 

emissions estimates directly to WRAP. Those estimates have been adopted into this inventory 

and are considered to be complete. 

Table 2-1a presents a summary of NOx emissions from oil and gas area sources in the WRAP 

States. Table 2-1b presents a similar summary of VOC emissions. The area source emissions 

are distinguished by source category, except in California where only the total NOx emission 

from the ARB inventory is given. The point source emissions included in Tables 2-1a and 2-1b 

include several types of oil and gas facilities that are listed under SIC codes 13**, 492* or 4612 

(ERG, 2005a). In most states, the major contributors of point source oil and gas emissions are 

natural gas transmission stations and natural gas processing plants. Crude oil pump stations and 

large storage sites also make a significant contribution in some states. Notably, the point source 

inventory methods in the State of Colorado and the State of Alaska are such that the majority of 

oil and gas emissions sources are included in the point source inventory. 
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Table 2-1a. 2002 State total NOx emissions (tons) from oil and gas sources. 

Alaska 877 9 886 45,822 46,708 

Arizona 2,735 2,735 

California 16,707 8,070 24,777 

Colorado 5,734 15,924 1,489 23,147 25,955 49,102 

Idaho 2,590 2,590 

Montana 2,027 1,044 4,721 7,792 4,275 12,067 

Nevada 33 24 5 62 83 145 

New Mexico 40,095 6,645 13,482 225 60,446 57,173 117,619 

North Dakota 2,920 1,536 176 4,631 4,739 9,369 

Oregon 73 - 12 85 1,182 1,267 

South Dakota 284 36 47 367 323 690 

Utah 2,371 676 2,143 5,190 3,311 8,500 

Washington 1,281 1,281 

Wyoming 7,025 4,964 6,283 1,428 19,699 15,015 34,715 

 21,536 54,828 42,800 3,141 130,376 181,191 311,566 

Point Source 

State Wellhead Total TOTAL

CBM Pump 

Engines

Area Source 

Total

Total

Compressor 

Engines Drill Rigs

Note: Entries with a “-“ indicate emissions were estimated to be zero. Entries that are blank indicate that emissions 

for the state/source combination are not estimated in this area source portion of the inventory.

Table 2-1b. 2002 State total VOC emissions (tons) from oil and gas area sources. 

Alaska 430 430 2,310 2,740 

Arizona 233 233 

California 7,101 18,712 25,813 

Colorado 785 137 3,388 21,075 25,386 63,960 89,346 

Idaho 78 78 

Montana 3,721 357 912 448 - 1 5,439 687 6,126 

Nevada 121 7 1 0 - - - 129 23 152 

New Mexico 10,671 1,484 2,893 40,509 33,884 77,333 - 166,773 11,527 178,300 

North Dakota 6,572 329 22 601 172 - 43 7,740 187 7,926 

Oregon - - 3 32 - - - 34 40 74 

South Dakota 246 12 10 19 - - - 288 26 314 

Utah 1,689 128 384 5,753 21,758 5,045 - 34,757 852 35,609 

Washington 64 64 

Wyoming 9,320 969 1,236 44,721 37,410 21,036 334 115,027 6,283 121,311 

 3,424 33,127 8,849 91,636 115,176 103,414 378 374,715 93,371 468,087 

Condensate 

Tanks - 

Uncontrolled

Condensate 

Tanks - 

Controlled

Total

Point 

Source 

State Total TOTAL

Area 

Source 

Total

Oil Well, 

Tanks 

Oil Well, 

Pneumatic 

Devices

Gas Well, 

Pneumatic 

Devices

Gas Well, 

Dehydrators

Gas Well, 

Completion - 

Flaring and 

Venting

Note: Entries with a “-“ indicate emissions were estimated to be zero. Entries that are blank indicate that emissions 

for the state/source combination are not estimated in this area source portion of the inventory.

Table 2-2 compares the results of the present oil and gas inventory effort with the oil and gas 

emissions in the state inventories previously submitted to WRAP EDMS. Total NOx emissions 

estimated by this inventory of oil and gas emissions represent a 59 percent increase in 

inventoried oil and gas emissions. The increases in some of the main oil and gas producing 

states are even more dramatic. Emissions in Montana, North Dakota and Utah have increased by 

182, 98 and 157 percent as a result of this effort. Oil and gas NOx emissions estimated for the 

State of New Mexico have increased by over 60,000 tons. 
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Table 2-2. Change in oil and gas NOx emissions in the 2002 inventory as a result of this 

inventory effort.

*Area source emissions in WRAP Oil and Gas Inventory adopted from data submitted by the California ARB. 

MAJOR NOx SOURCE INVENTORY 

Drilling Emission 

The proposed approach for estimating emissions from drill rig engines was to use drill permit 

data from oil and gas commissions (OGCs) as a base measure of activity and to supplement that 

with more sophisticated data from drilling companies. This approach was then revised to replace 

the data from drilling companies with data from a survey of drilling in Southwest Wyoming. 

The final emission estimate uses several activity indicators from the drill permit data and 

combines that with emission factors derived from the Wyoming survey to make the most locally 

appropriate emission estimate. 

In concordance with the proposed approach, we contacted large drilling companies to obtain data 

on the types of engines used for drilling, the normal operational schedule of the engines, regional 

variation of drilling rates and the relative activity of rotary versus workover rigs. The response 

to this survey was a mixture of refusal to participate and avoidance. Ultimately, none of the 

drilling companies contacted provided data to ENVIRON for this inventory effort. 

Concurrent to the survey of drilling companies, we contacted State OGCs to obtain, amid other 

information, the activity data afforded by drill permits. The OGCs, in general, readily made the 

requested information available. The exception was the New Mexico Oil and Gas Conservation 

Commission, which declined to provide information. However, with considerable assistance 

from the New Mexico Air Quality Department, the necessary information was obtained for New 

Mexico as well. The drilling information obtained for each State is as follows: 

• Spud date - the date that drilling commenced 

State/Tribe Area Point Total Area Point Total Total Percent

Alaska 886 45,822 46,708 45,822 45,822 886 2%

Arizona 2,735 2,735 2,735 2,735 - 0%

California* 8,070 16,707 24,777 8,070 16,707 24,777 - 0%

Colorado 23,147 25,955 49,102 25,955 25,955 23,147 89%

Idaho 2,590 2,590 2,590 2,590 - 0%

Montana 7,792 4,275 12,067 4,275 4,275 7,792 182%

Nevada 62 83 145 83 83 62 75%

New Mexico 60,446 57,173 117,619 57,173 57,173 60,446 106%

North Dakota 4,631 4,739 9,369 4,739 4,739 4,631 98%

Oregon 85 1,182 1,267 1,182 1,182 85 7%

South Dakota 367 323 690 323 323 367 114%

Utah 5,190 3,311 8,500 3,311 3,311 5,190 157%

Washington 1,281 1,281 1,281 1,281 - 0%

Wyoming 19,699 15,015 34,715 6,409 15,015 21,424 13,290 62%

Total 130,376 181,191 311,566 14,479 181,191 195,670 115,897 59%

WRAP Oil and Gas Inventory Oil and Gas in Previous Inventory

Change in Oil and Gas 

Emissions
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• Well depth - the depth of the well; total vertical, measured or target depending on 

availability 

• Completion date - the date well preparation is finalized; occurring with some delay after 

drilling ceases 

• Well formation - the geologic structure that the well was drilled to 

• Well field - the legal designation for the area where the well was drilled 

• Well county - the county where the well was drilled; for allocation purposes 

The completeness of this information varied considerably from State to State. While each State 

maintained a database containing these fields, every field was not completed for every well. The 

absence of this information required that some assumptions be made about the depth of some 

wells drilled and the duration of drilling. Those assumptions are documented later in this 

section. The references for the drill permit data are provided in Table 2-3. 

Table 2-3. Source of drill permit data. 

States with Drilling 

Activity in 2002 Source of Drill Permit Data 

Alaska Alaska Oil and Gas Conservation Commission (AK 

OGCC), 2005 

Colorado Colorado Oil and Gas Conservation Commission (CO 

OGCC), 2005 

Montana Montana Board of Oil and Gas Conservation (MT 

BOGC), 2005 

North Dakota North Dakota Industrial Commission, Oil and Gas 

Division (ND OGD), 2005 

New Mexico New Mexico Environmental Department (NM ED), 

2005 and New Mexico Oil Conservation Division (NM 

OCD), 2004 

Nevada Nevada Division of Minerals (NV DM), 2005 

South Dakota South Dakota Department of Environment & Natural 

Resources, Minerals and Mining Program (SD MMP), 

2005 

Utah Utah Division of Oil, Gas and Mining (UT DOGM), 

2005 

Wyoming Wyoming Oil and Gas Conservation Commission (WY 

OGCC), 2005 

The databases maintained by State OGCs provided the base level of activity to characterize the 

number of wells being drilled in an area, the depth of those wells and the amount of time 

required to construct the wells. What was still needed was the more detailed information about 

the drill rigs that the drilling companies did not provide. That information was necessary to tie 

this information about the characteristics of the well being drilled to emissions from drill rig 

engines. Fortunately, the Wyoming Department of Environmental Quality (DEQ) was able to 

provide results from a recent survey of drilling in the Jonah-Pinedale area of Southwest 

Wyoming. 

The Jonah-Pinedale area has seen particularly intense drilling activity in recent years and the 

information provided represents the synthesis of emissions estimates made by ten different 

drilling companies for a total of 218 wells drilled. The emission factors derived from the 
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WYDEQ (2005) survey are 13.5 tons NOx per well and 3.3 tons SO2 per well. The Colorado 

Department of Public Health and Environment (CDPHE) was also able to offer an emission 

factor. That factor was provided by only one company and without information available as to 

the area for which such a factor would be appropriate. Due to the larger survey size and the 

greater information available it was therefore the Jonah-Pinedale information that we used. 

The emissions from the prime mover on a drill rig for drilling a well are dependent upon the 

depth of the well, the composition of substrate and the characteristics of the engine. For 

example, a small rig drilling a relatively shallow well in the Powder River Basin would have 

different emissions than a large rig drilling a deep well in the Jonah-Pinedale area. Because of 

this variation in drilling operations, it would not be appropriate to use the same Jonah-Pinedale 

emission factor for all wells drilled in the WRAP States without making some adjustments. To 

reflect this fact, we developed a methodology that uses information about the characteristics of 

wells in a specific area to scale the Jonah-Pinedale emission factor for drilling operations in that 

area. 

The most specific unit for which well characteristics were commonly available was the 

formation. Creating formation-specific emission factors offers a good degree of accuracy 

because the well depths and substrate encountered when drilling the same formation should be 

consistent. To determine if the data supported that anticipated consistency, we did a simple 

statistical analysis of the drilling operations at several formations. This analysis showed that 

while there was variation of the elapsed time between spud date and completion date within one 

formation, the majority of wells drilled clustered near the average time for the formation. Figure 

2-1 shows the distribution for the Blanco-Mesaverde formation in New Mexico. It shows that 

the large majority of wells drilled in that formation were drilled in a period that clustered around 

approximately 65 days. This consistency within a single formation would be irrelevant if it 

weren’t for the absence of data for some wells. By the methodology developed, the emissions 

from the drilling of all wells in one formation are estimated using the average duration of well 

preparation activities and average well depth within the formation. This is based on the 

assumption that wells with no information for depth or duration will, on average, be well 

represented by all those wells in the formation for which depth and duration were available. 
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Blanco-Mesaverde Distribution of Drilling Durations

0

2

4

6

8

10

12

14

16

18

102030405060708090

100110120130

140150160170

180190200

Duration

Wells Drilled

Figure 2-1. Distribution of well preparation activities within a single formation. 

In addition to the assumption that the depth and duration of drilling activities for wells in a single 

formation are approximated by the average for the formation, two other important assumptions 

were made. First, it was necessary to assume that the difference between the completion date 

and the date that drilling ceased is, on average, constant relative to the total duration of 

preparation activities. This assumption was needed because the actual date that drilling ceased 

was not available. What this assumption means is that if on average wells with 100 days 

between spud date and completion actually had a duration of drilling of only 80 days, then on 

average wells with 50 days between spud date and completion would have 40 days of actual 

drilling. Though this is certainly not true on a well by well basis, it’s assumed to be true for the 

formation averages used in this analysis. 

It was also necessary to assume that the capacity of the equipment used to drill a well is 

dependent upon the depth of the well. This assumption was made because the data clearly 

indicated that substantially different rigs were employed in different drilling applications. Some 

wells in the Powder River Basin had the same approximate drilling duration as wells in JonahPinedale. It was therefore assumed that the capacity of the prime mover would grow 

proportional to the depth of the well. With those two assumptions, it is then possible to scale the 

emission factor from the Jonah-Pinedale area to other formations based on the average well 

depth and drilling duration and in doing so to correct for variations due to well depth, 

composition of substrate, and engine capacity. 

The first step in scaling the Jonah-Pinedale emission factor was to determine the appropriate 

average well depth and duration for the Jonah-Pinedale emission factor. The vast majority of 

wells drilled in Jonah-Pinedale were drilled to the Lance or Lance-Mesaverde formation. The 

average well depth and drilling duration for those formations - based on drill permit data 

obtained from the Wyoming OGC for 2002 and 2004 - was 11,896 ft and 80.6 days (WY OGCC 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec2_2002emissions.doc 2-7

2005). The same type of average well depth and drilling duration was then calculated for the 

other formations drilled in 2002 in the WRAP States. A formation-specific emission factor was 

then created for each formation using Calculation 1. 

 Calculation 1: 

In some cases, lack of data did not permit the creation of a formation-specific emission factor. 

The situations where that occurred and the method used to surmount those obstacles are 

presented in Table 2-4. 

Table 2-4. Situations where formation-specific emission factors could not be created. 

Area Problem Solution 

Wyoming Some drilling records did not 

report the formation 

Blank formation records were 

assigned to the most 

commonly drilled formation in 

the same field 

South Dakota, 

Nevada 

Not enough wells were drilled 

to justify a formation average 

The state average depth and/or 

duration were used 

New Mexico, North 

Dakota 

No depths and/or durations 

were recorded for some 

formations 

The state average depth and/or 

duration was used as a default 

Montana Formation was not available Field averages were used 

Additional adjustments were considered beyond those for well depths and durations. State DEQs 

were surveyed to determine if there were any control requirements for drill rigs. All State DEQs 

responded that controls were not required on drill rig engines. Based on that information, no 

adjustment for controls was necessary. It was, however, necessary to account for the varying 

fuel sulfur levels between different States and counties. This adjustment was actually made to 

the county-allocated SO2 emissions rather than to the emission factor. This was accomplished 

by multiplying the county SO2 emission by the ratio of that county’s nonroad diesel sulfur level 

to the Wyoming nonroad diesel sulfur level. Fuel sulfur levels used in this adjustment are 

provided in Appendix C; these are the same fuel sulfur level developed for the WRAP 2002 

nonroad diesel equipment emission inventory. 

EFA = EFJ x ( DA / DJ) x ( TA / TJ )

where: 

EFA = The emission factor for another formation 

 EFJ = The Jonah-Pinedale emission factor 

 DA = The average depth of wells drilled in another area 

 Dj = The average depth of wells drilled in Jonah-Pinedale 

 TA = The duration of drilling in another area 

 Tj = The duration of drilling in Jonah-Pinedale 
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Emissions for a single formation were calculated using Calculation 2. The emissions for that 

formation were then allocated to the counties that intersected the formation based on the fraction 

of the total wells drilled that were drilled in each county’s portion of the formation, as shown in 

Calculation 3. 

 Calculation 2: 

 Calculation 3: 

The state total drill rig NOx and SO2 emissions that resulted from this procedure are shown in 

Table 2-5. The adjustments made to the emission factors are apparent in these results. While 

significantly more wells were drilled in the State of Wyoming than in New Mexico, the 

emissions in New Mexico are higher than in Wyoming. This occurs because many of the 

Wyoming wells were drilled quickly and to a shallow depth, as commonly occurs for the Powder 

River Basin CBM wells. In contrast, the wells in New Mexico were, on average, drilled deeper 

and took longer to drill. Where average drill depths and durations were more comparable, such 

as in Colorado and New Mexico, the emissions per well are relatively close. One piece of 

information requested from drilling companies that was not possible to obtain from other sources 

was the relative activity of rotary versus workover rigs. Some of the wells drilled represented 

here may be permits that were granted for a workover rig. Because workover rigs do not have 

the same constant, heavily loaded activity profile of rotary rigs, it is estimated that this represents 

a slightly conservative estimate. 

E = EF x W

where: 

 E = The 2002 emission for a given formation 

 EF = The formation specific emission factor 

 W = The number of wells drilled in the formation in 2002. 

CE = E x CW / TW 

where: 

CE = The 2002 emissions for a given county intersected by the 

formation 

CW = The total number of wells drilled in the county’s portion of the 

formation 

TW = The total number of wells drilled in the formation 
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Table 2-5. State total drill rig emissions. 

State Wells Drilled NOx (tons) SO2 (tons)

Alaska 205 877 48 

Arizona 

Colorado 1,244 5,734 260 

Idaho 

Montana 463 1,044 227 

Nevada 6 24 1 

New Mexico 932 6,645 1,444 

North Dakota 157 1,536 358 

Oregon 

South Dakota 7 36 8 

Utah 126 676 147 

Washington 

Wyoming 2,948 4,964 1,213 

Total 6,088 21,536 3,706 

Figure 2-2 presents a map of the 2002 drilling locations. Though not every well drilled is 

represented here because not all records included geographic coordinates, this map clearly 

displays the areas where well drilling activities were focused in 2002. This map also includes 

those wells that were drilled on tribal lands. The State emission totals presented in Table 2-4 

should be considered accurate for the geographic area defined by the State boundaries, but not 

necessarily to the States’ jurisdiction; a small amount of those emissions in the State inventory 

fall under tribal jurisdiction. 
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Figure 2-2. Wells drilled in 2002 in the WRAP states. 

Non-Point Natural Gas Compressor Engine Emissions 

For the purposes of this study, natural gas compressor engines have been grouped into three 

categories. The largest facilities, in terms of potential emissions, are the large natural gas 

compressor stations on natural gas transmission lines. These are typically Title V facilities and 

they are dealt with as point sources. The second tier of facilities is the gas gathering compressor 

station. In most States, these too have been included in a point source emission inventory. Some 

exceptions, where these medium sized facilities are not in the point source inventory and have 

thus been included in this area source inventory are discussed in section 2.3. The final category 

of compressor engines, which is the primary focus of this area source compressor engine 

emission estimate, is the group of relatively small, dispersed wellhead compressor engines. 

Figure 2-3 presents an example of such an engine. In all but two of the natural gas producing 

States, these engines have not been included in previous emission inventories and their inclusion 

here represents a significant advance in understanding this important component of the oil and 

gas production industry. The development of a methodology to address this emissions source, 

the application of that methodology and a summary of results are presented in this subsection. 
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Figure 2-3. Wellhead compressor engine. 

The preferred approach for estimating emissions from wellhead compressors that was described 

in the work plan focused on obtaining data from compressor operators. As was proposed, we 

contacted a large number of compressor operators, including exploration and production 

companies, gas gathering companies and compressor rental companies. This survey of operators 

was expected to produce, at a minimum, the number of wellhead compressors operated by each 

company. Also requested was information on compressor engine size, emissions data and 

operational schedule. Unfortunately, none of the companies contacted was willing to provide 

even a count of compressor engines. Repeated attempts were made to obtain data from the 

compressor operators, but ultimately it proved necessary to use an alternative methodology that 

did not rely on using data from operators. 

The alternative methodology was to develop a production-based emission factor from local 

studies of compressor engine emissions. This emission factor was then combined with gas 

production data collected from the State OCGs to estimate emissions. Several local studies were 

analyzed to determine which offered the most appropriate data from which to derive the emission 

factor. The strengths and weaknesses of each of those studies and the ultimate selection of an 

industry-compiled inventory of wellhead compressor engines in the New Mexico portion of the 

San Juan Basin is discussed below. 

2002 Colorado Point Source Emission Inventory

The Colorado Department of Public Health and Environment compiled a point source emission 

inventory for the year 2002 that includes sources with actual emissions down to 2 tons per year 

in attainment areas and 1 ton per year in non-attainment areas (CDPHE, 2005b). Given these 

exceptionally low inventory thresholds, all wellhead compressors are expected to have been 

included in the inventory. Gas production data was also obtained from the Colorado Oil and Gas 

Conservation Commission, making it appear possible to create a production-based emission 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec2_2002emissions.doc 2-12

factor by comparing emissions from the compressor engines in the Colorado point source 

inventory with gas production reported by the CO OGCC. 

The extraction of only those engines used to power wellhead compressors from the point source 

inventory proved a more difficult task than expected. The coding of engines was such that it was 

difficult to distinguish between engines used for compression and engines used for other 

purposes such as pumping or generator sets. Nor was it possible to determine with confidence 

the subset of engines that represented only small wellhead compressor engines that would not be 

included in other States’ point source inventories. This second problem represented an obstacle, 

because if medium-sized facilities were inadvertently included in the development of the 

emission factor then the resulting area source emission estimate for other States would be 

double-counting the emissions from medium-sized gas gathering facilities. Despite the fact that 

the CDPHE generously provided additional information from their records beyond what was 

provided in the point source inventory, it was not ultimately possible to develop an emission 

factor based on the Colorado point source inventory. 

2002 New Mexico Oil and Gas Association’s Inventory of Unpermitted Sources in the San Juan 

Basin

The New Mexico Oil and Gas Association (NMOGA) cooperated in the preparation of the 

Denver Early Action Compact by compiling an inventory for year 2002 of the unpermitted 

emissions sources operated by the oil and gas production industry in the New Mexico portion of 

the San Juan Basin. In the State of New Mexico, the threshold for permitting reported by the 

New Mexico Environmental Department was a potential to emit 25 tons per year (NM ED, 

2005b). Thus, the inventory of unpermitted sources included those sources with a potential to 

emit less than 25 tons per year. The small wellhead compressor engines fall into this category. 

The NMOGA inventory provided emissions for wellhead compressor engines, which could be 

compared to production statistics for the San Juan Basin to derive an emission factor with units 

of tons NOx per MCF of gas produced. 

The NMOGA inventory was based on a survey of exploration and production companies. The 

survey obtained responses representing activity at 10,582 of 17,108 wells. Emissions for 

wellhead compressor engines submitted by the responding companies totaled 14,892 tons NOx 

(NMOGA, 2003). To estimate the emissions at all wells, this emission was divided by the 

fraction of wells represented in the responses. This produced an estimate of 24,076 tons of NOx 

emitted by wellhead compression in the New Mexico portion of the San Juan Basin. 

This emission estimate corresponds to gas production in three New Mexico counties: Rio 

Arriba, San Juan and Sandoval. Total 2002 gas production for those three counties was obtained 

from the on-line production database maintained by the New Mexico Institute of Mining and 

Technology. Production figures are summarized in Table 2-6. 

Table 2-6. 2002 gas production in the San Juan Basin – New Mexico. 

County 2002 Gas Production (MCF) 

Rio Arriba 391,007,587 

San Juan 638,024,961 

Sandoval 1,420,527 

San Juan Basin Total 1,030,453,075 

(NMT, 2005) 
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With these estimates of total gas production and total emissions for wellhead compression, it was 

possible to calculate a production based emission factor as the quotient of total emissions divided 

by total gas production. The result is an emission factor of 2.3x10-5 tons NOx per MCF gas 

produced. 

Bureau of Land Management Environmental Impact Statements

Several Bureau of Land Management (BLM) environmental impact statements (EIS) were 

examined for information they might provide on the relationship of gas compression and gas 

production. The Powder River Basin EIS included the most complete information on the 

anticipated compression needs for the future development of gas wells. That information, in the 

form of expected installed wellhead compression capacity, was combined with an EPA emission 

factor for natural gas fired engines, to estimate the expected emissions from natural gas fired 

engines. This estimate was then compared to the estimated gas production to develop a 

production-based emission factor. 

The Powder River Basin EIS estimated that 380 horsepower of installed compression capacity 

would be required for every 250 MCF-day of new gas production (BLM, 2002). Assuming 

8,760 hours per year of gas production and hence compressor operation, this equates to 

3,328,800 horsepower-hours per year for 91,250 MCF of gas production. Applying the 12 grams 

NOx/hp-hr emission factor for Light Commercial Gas Compressors (SCC2268006020) from the 

EPA’s NONROAD2004 emissions model, this compressor activity would result in 44 tons of 

NOx. Dividing this result by the associated production, 91,250 MCF, results in a productionbased emission factor of 4.8x10-4 tons NOx per MCF. 

The emission factor derived from the BLM EIS is based on the fundamental assumption that 380 

horsepower of compression will be added for every 250 MCF-day of gas production. Supporting 

evidence for this assumption is not provided in the Powder River Basin EIS. The EIS is a 

forecast of production and equipment that may be installed, not a study of existing operations. 

Although it provides sufficient information to calculate the necessary production-based emission 

factor, these limitations would not allow us to place a high degree of confidence in the estimates 

produced by that emission factor. 

East Texas 2002 Emission Inventory

The emission inventory prepared for the Tyler/Longview/Marshal Flexible Attainment Region of 

East Texas included an estimate of the emissions for area source compressor engines. The 

method used by the contractor, Pollution Solutions (2005), to estimate gas compressor emissions 

was to develop a relationship between compressor engine activity and gas production from a 

survey of compressor operators. That relationship was then used with gas production statistics 

and EPA emission factors to estimate engine emissions. 

The survey of operators yielded a relationship of 191 horsepower of compression per MMSCFday of gas production. Assuming 8760 hours per year of operation, as was done in the East 

Texas Inventory, this results in 1,673,160 hp-hr/year per MMSCF-day. Converting that figure to 

an activity factor based on annual gas production gives 4,584 hp-hr per MMSCF or 4.58 hp-hr 

per MSCF. Combining that with the 11 g NOx/hp-hr emission factor used by Pollution Solutions 

results in a production-based emission factor of 5.6x10-5 tons NOx per MCF. 
December 2005 

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The emission factor derived from the results of the East Texas survey seemed a good candidate 

for use in the present study. It was derived from actual operations and falls between the factors 

derived from the NMOGA inventory and the BLM EIS. However, Pollution Solutions was 

unwilling to provide the details of the survey that resulted in the emission factor used in the East 

Texas work. Without supporting documentation and technical basis we could not use the 

resulting emission factor. 

Compressor Engine Emission Estimate 

The results of the review of compressor engine studies are summarized in Table 2-7. The 

attempt to derive an emission factor from the Colorado 2002 Point Source Inventory was 

unsuccessful. The use of BLM EIS was ruled out due to the speculative nature of the 

production-compression relationship used in that study. Nor did it seem possible to use the 

emission factor derived from the East Texas Inventory in the absence of supporting evidence. 

We therefore decided to use the emission factor derived from the New Mexico Oil and Gas 

Association’s Inventory of Unpermitted Sources in the San Juan Basin. This study has several 

advantages over the other studies. It is a study of existing operations in an important production 

area of the WRAP States and the survey of compressor operators attained a very high response 

rate. With a production-based emission factor of 2.3x10-5 tons NOx per MCF of gas production, 

it was then possible to estimate emissions based on gas production statistics obtained from the oil 

and gas commissions. 

Table 2-7. Summarized results of review of compressor engine studies. 

Source 

Emission Factor 

(tons NOx / MCF) Advantages Disadvantages 

CO Inventory Inconclusive 

NMOGA Inventory 2.3x10-5 • Very good 

coverage/response 

• Important WRAP 

production area 

BLM Powder River 

EIS 

4.4x10-4 • Important area of 

growth 

• Projected, not 

actual equipment 

and production 

East Texas EI 5.6x10-5 • Based on survey data 

• Resulting EF falls 

between NMOGA and 

BLM factors 

• Lack of 

supporting 

evidence 

We had previously requested from the OGCs well-specific oil and gas production statistics. 

These were obtained, either submitted by the OGC or downloaded from the on-line production 

statistics maintained by some States OGCs, for all oil and gas producing States. For the 

compressor engine emissions estimate, total 2002 natural gas production was summed for each 

county and county level emissions were estimated as the product of natural gas production 

(MCF) and the production-based emission factor. 

The only States that reported requiring controls on compressor engines were Utah and Wyoming. 

In both of those States, the emissions are controlled to a rate of 1-2 grams NOx /hp-hr (WY 

DEQ, 2005c; UT DEQ, 2005). This represents a substantial reduction from the average emission 

rate of 11.4 grams NOx/hp-hr that was found by the NMOGA Inventory. The production-based 
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emission factors for Utah and Wyoming have been adjusted downward to account for this 

difference. In both States, the controlled emission factor was calculated as the product of the 

uncontrolled emission factor, 2.3x10-5 ton NOx/MCF, and the ratio of controlled hourly 

emissions to uncontrolled hourly emissions, 2 grams NOx/hp-hr to 11.4 grams NOx/hp-hr. A 

summary of compressor engine controls reported by State agencies and the control-adjusted 

emission factors are presented in Table 2-8. 

Table 2-8. State controls on compressor engines and controlled emission factors. 

State Reference 

Control Requirement Emission Factor 

(ton NOx/MCF) 

Alaska AK DEC, 2005b NA1 

Colorado CDPHE, 2005b NA1 

Montana MT DEQ, 2005 None 2.3x10-5

New Mexico NM ED, 2005b None 2.3x10-5

Nevada NV DEP, 2005 None 2.3x10-5

North Dakota ND DH, 2005 None 2.3x10-5

South Dakota NV DENR, 2005 None 2.3x10-5

Oregon OR DEQ, 2005 None 2.3x10-5

Utah UT DEQ, 2005 Controlled to 1-2 g 

NOx/hp-hr 

4.1x10-6

Wyoming WY DEQ, 2005c Controlled to 1-2 g 

NOx/hp-hr 

4.1x10-6

1 Any controls required on compressor engines are included in the point source inventory.

The State total NOx emissions that resulted from the application of these emission factors are 

presented in Table 2-9. As is shown in Table 2-9, and graphically displayed in Figure 2-4, 

emissions resulting from this procedure are directly related to production. Though at the level of 

individual wells it may be true that compressor activity is actually higher at less productive 

wells, when county level production is considered, as in this study, this positive correlation of 

compressor engine emissions to gas production is supported by all of the studies considered in 

the development of this methodology. 

There are two exceptions to this wellhead compressor engine emissions estimate. Those are the 

State of Alaska and the State of Colorado. As was mentioned in the preceding discussion of the 

compressor engine emission factors, the State of Colorado included in its point source inventory 

all sources with actual 2002 emissions greater than 2 tons. This is expected to include all 

compressor engines. An area source emissions estimate for compressor engines was therefore 

not made for the State of Colorado. 

In the State of Alaska, oil and gas production facilities differ dramatically from those found in 

the other WRAP States. In Alaska, both personnel in the State’s environmental department and 

the oil and gas conservation commission indicated that facilities are arranged in a ‘wagon 

wheel’. At the hub of the facility is the large processing plant, and each spoke reaches out to the 

production wells. Along the spokes and at the wellhead, there is emissions-producing 

equipment. However, this equipment is permitted along with the processing plant (AK OGCC, 

2005b; AK DEC, 2005b). Wellhead compressor engines would therefore be included along with 

the equipment in the processing plant as a point source in the 2002 Alaska point source 

emissions inventory. For that reason, area source compressor engine emissions are not made for 

the State of Alaska. 
December 2005 

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Table 2-9. State total NOx emissions from gas compressor engines. 

State 

Total Gas 

Produced 

(MCF) 

Emission 

Factor (tons 

NOx/MCF) 

Total 2002 

NOx Emission 

(tons) 

Alaska 3,496,429,130 NA 

Arizona - 

Colorado 1,241,311,742 NA 

Idaho - 

Montana 86,761,832 2.30E-05 2,027 

Nevada 6,433 2.30E-05 0 

New Mexico 1,716,107,712 2.30E-05 40,095 

North Dakota 59,979,925 2.30E-05 1,401 

Oregon 837,067 2.30E-05 20 

South Dakota 10,955,008 2.30E-05 256 

Utah 283,408,406 4.10E-06 1,182 

Washington - 

Wyoming 1,708,567,844 4.10E-06 7,024 

Total 8,604,365,099 54,827 

*Colorado wellhead compressor emissions are in the point source inventory 

**California ARB has provided separate estimates of area source oil and gas emissions

Figure 2-4. County-level 2002 gas compressor engine emissions. 
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Medium-Sized Facilities 

The emission factor developed for the wellhead compression estimate was directed at estimating 

emissions from sources with a potential to emit less than 25 tons per year. This was the type of 

source considered by the NMOGA inventory. This proved convenient, as in many States, 

sources with a potential to emit greater than 25 tons per year were reported by the State DEQ to 

be included in the point source emission inventory. However, this was not the case in all States. 

A summary of the State inventory thresholds is presented in Table 2-10. 

Table 2-10. State point source inventory thresholds. 

State 

Point Source 

Inventory 

Threshold Reconciliation Source 

Alaska PTE 100 TPY Smaller wellhead equipment 

reported to be grouped under 

these large facilities 

AK DEC, 2005b 

Arizona PTE 40 TPY Determined that all medium 

sized facilities exceeded PTE 

40 TPY 

AZ DEQ, 2005 

Colorado 2 TPY actual 

emissions 

Removed compressor, 

condensate tank and glycol 

dehydrator emissions from area 

source inventory 

CDPHE, 2005b 

Montana PTE 25 TPY MT DEQ, 2005 

New Mexico PTE 25 TPY NM ED, 2005b 

North Dakota PTE 100 TPY Used State’s internal inventory 

of compressor stations to 

include sources with a PTE 

between 25 and 100 TPY 

ND DH, 2005 

Nevada PTE 5 TPY No wellhead compressor 

engines included in State’s 

inventory. No reconciliation 

required 

NV DEP, 2005 

Oregon PTE 100 TPY Obtained inventory of 

compressor stations with PTE 

less than 100 TPY from State 

OR DEQ, 2005 

South Dakota PTE 100 TPY Created scaling factor based on 

NM point inventory and gas 

production 

SD DENR, 2005 

Utah PTE 100 TPY Created scaling factor based on 

NM point inventory and gas 

production 

UT DEQ, 2005 

Wyoming PTE 25 TPY WY DEQ, 2005c 

As shown in Table 2-10, Montana, New Mexico and Wyoming all included sources with a 

potential to emit 25 tons per year or greater in their point source inventories. The State of Alaska 

and the State of Colorado have different inventory thresholds, but this did not require any 

reconciliation of the area source compression emission estimate as in those States wellhead 

compression is included entirely in the point source emission inventory. 
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In Arizona, Nevada, Oregon and North Dakota, Utah and South Dakota, the fact that the States’ 

inventory thresholds differed from the New Mexico PTE 25 tpy threshold required special 

treatment. Discussion with staff at the Arizona and Nevada DEQ revealed that despite the 

different thresholds, no further action was necessary. In Arizona, there were no compressor 

facilities with a potential to emit between 25 tpy and 40 tpy (AZ DEQ, 2005). In Nevada, 

despite the relatively low inventory threshold, no wellhead compressor engines had been 

included in the point source inventory (NV DEP, 2005). 

In Oregon and North Dakota, State DEQ personnel indicated that there were oil and gas facilities 

that fell below the State point source inventory threshold, but were larger facilities that would not 

be accounted for in the area source wellhead compression estimate. Despite their exclusion from 

the point source inventory, both Oregon and North Dakota did have internal emissions estimates 

for these medium-sized facilities. Those emissions data were obtained from the State and have 

been included in the area source emission inventory (see Table 2-13). 

In Utah and South Dakota, there existed the same gap between the wellhead compression 

emissions and the state point source inventory as in Oregon and North Dakota. However, in 

Utah and South Dakota it was not possible to obtain emissions data from the State agencies. It 

was therefore necessary to estimate emissions for this group of facilities based on the gas 

production in those States. This was done by selecting the subset of point source facilities from 

the New Mexico point source inventory that had a potential to emit between 25 and 100 tons per 

year, relating those facilities to New Mexico gas production and then scaling the emissions from 

those facilities to gas production in Utah and South Dakota. 

The facilities in New Mexico with a potential to emit between 25 and 100 tons per year were 

identified by first extracting only facilities coded with an oil and gas SIC; the SIC used are listed 

in Table 2-11. The next step was to calculate the potential to emit for each emission unit 

included in those oil and gas facilities. This was accomplished by scaling the emissions reported 

for the unit up to what they would be if the unit had been operated 8760 hours per year. For 

example, if a unit in the inventory had emissions of 10 tons NOx, but had only operated 4000 

hours, then the potential to emit for that unit was calculated as the product of 10 tons NOx and 

8760/4000. In this case the potential to emit would then be 21.9 tons NOx. Though we 

acknowledge that factors other than the total hours of operation may be used in the determination 

of potential to emit, the detailed determination of potential to emit for each emission unit was not 

possible given the available resources. After estimating the potential to emit as described for 

each emission unit, the facility total PTE was then calculated by summing the PTE of all units in 

that facility. Those facilities with a total PTE under 100 tpy were extracted. 

Table 2-11. Oil and gas SIC. 

SIC Description 

1311 Crude Petroleum and Natural Gas 

1321 Natural Gas Liquids 

1382 Oil and Gas Field Exploration Services 

1389 Oil and Gas Field Exploration Services, NEC 

4612 Crude Petroleum Pipelines 

4922 Natural Gas Transmission 

4923 Natural Gas Transmission and Distribution 

4925 Mixed, Manufactured or Liquefied Petroleum Gas Production 
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Using the information in the New Mexico inventory, it was possible to separate the facilities with 

a PTE between 25 tons per year and 100 tons per year into two categories: gas compression and 

gas processing. The total emissions in each of these categories were then summed to determine 

the State total emissions. By dividing those totals by the State total gas production we arrived at 

the production-based emission factors shown in Table 2-12. 

Table 2-12. Emissions for New Mexico natural gas facilities with a PTE between 25 and 100 

tpy. 

Type of Facility Gas Processing Gas Transmission 

Total Emissions (tons NOx) 2,715 4,195 

Total Gas Production (MCF) 1,624,225,738 

Emission Factor (ton NOx/MCF) 1.67x10-6 2.58x10-6

Combining the emission factors in Table 2-12 with the county gas production in Utah and South 

Dakota, we estimated emissions for the medium-sized gas processing and transmission facilities 

in those states. Using these emissions estimates and the emissions provided by State agencies for 

Oregon and North Dakota, we have supplemented the area source emissions estimates for those 

States to include the facilities with a potential to emit between 25 and 100 tons per year. Also 

included in this supplement is a compression facility in Clark County, Nevada. Although no 

action was required to reconcile the inventory prepared by the State of Nevada, Clark County 

submitted its own inventory in which it grouped a compressor facility in with other sources of 

natural gas combustion. We obtained emissions for this source and have included it in the oil 

and gas area source emission inventory. The State total emissions for these facilities are shown 

in Table 2-13. 

Table 2-13. Area source emissions estimate for facilities with a PTE between 25 and 100 tpy. 

State 

Medium Facility Emissions 

(tons NOx) Source 

Oregon 53.8 OR DEQ, 2005 

North Dakota 1,518.4 ND DH, 2005 

Utah 1,222.6 Estimated 

South Dakota 28.3 Estimated 

Nevada 33 CC DAQM, 2005 

Coal Bed Methane Generators 

The methodology described in the work plan for estimating emissions from coal bed methane 

generators relied on obtaining information on generator specifications and usage from State 

environmental departments. Based on the map of CBM production obtained from the Energy 

Information Administration (Figure 2-5), environmental departments were contacted for this 

information in five States: Colorado, Montana, New Mexico, Utah and Wyoming. Of those, 

only Wyoming was able to provide information on the generators associated with CBM wells 

(WYDEQ, 2004; WYDEQ, 2005b). Contacts in Montana and Utah indicated that the CBM 

fields in their states are electrified and pumps are expected to be operated on line power 

(Richmond, 2005; Daniels, 2005). Therefore it remained to determine generator usage in only 

Colorado and New Mexico. 
December 2005 

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Figure 2-5. Western U.S. Coal bed methane fields (EIA, 2004). 

While contacting the State environmental departments to obtain data on generators, we also 

requested production data from OGCs in each of the WRAP States. In the States with CBM 

production, that data included the water production at CBM wells. In addition, the depth of 

wells was obtained for some sampling of the wells in each State; depth information was not 

available for every well. Based on the data available, the first emission estimate that we 

produced was the result of scaling the generator activity obtained for the State of Wyoming to 

the other CBM producing states based on the average depth of wells and the water produced at 

CBM wells. This scaling was made based on the understanding that the work performed by 

generators is correlated to the mass of water lifted by pumps and the distance over which it must 

be lifted. 

The emissions produced by this first methodology did not appear sufficient to represent the 

activity at the large number of CBM wells in Colorado, New Mexico and Wyoming. The 

emissions determined by this method, on a per well basis, for these three States were 0.080, 

0.010 and 0.067 tons NOx respectively. One possible explanation for the surprisingly low 

results determined by this method is that the generator information obtained from the State of 

Wyoming excluded some of the engines, possibly those that are directly coupled to CBM pumps. 

Also, actual hours of operation were only available for a subset of the generators. Activity of the 

remaining generators in Wyoming was extrapolated from the activity of that subset. It’s possible 
December 2005 

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that the activity of the subset was not representative of the entire population of generators. In 

summary, engineering calculations showed that a great deal more work would be performed in 

dewatering CBM wells than was suggested by this emissions estimate based on the WYDEQ 

emissions factors. 

Operating under the assumption that the database of generators obtained from the Wyoming 

DEQ may not include all the engines associated with dewatering, it was necessary to develop an 

emissions estimation methodology where activity could be determined based only on the well 

production data obtained from the State OGC. Information on the design and operation of CBM 

wells in combination with engineering calculations provided a way to estimate engine activity 

(horsepower-hours) based on water production. Once horsepower-hours were estimated, it was 

then possible to derive an emission estimate using an emission factor from EPA’s 

NONROAD2004 emissions model. 

Estimating Engine Activity

Engine activity was determined for each well by first determining the water power developed by 

the dewatering pump. Using an assumption of the pump’s efficiency it was then possible to 

determine the power that must be supplied to the pump. Assuming that losses in the electrical 

delivery system are negligible, the power supplied to the pump is the same as the power 

produced by the generator. Then, by estimating the efficiency of the generator system at 

converting the power at the engine flywheel to electrical power it was possible to estimate the 

horsepower-hours of the engine. This was then combined with an emission factor to determine 

emissions resulting from the dewatering of each well. The complete list of assumptions used for 

this calculation are presented in Table 2-14. 

Table 2-14. Assumptions used in developing the CBM generator emissions estimate. 

Assumption Reason 

Pumping in NM and CO is done by natural gas fired 

engines. Pumping in WY is done with a mix of 

natural gas and diesel engines. 

The Wyoming generator data shows that the 

majority of the generator horsepower is natural gas 

fired (WY OGCC, 2005b). Also, industry 

representatives indicate that use of electric power 

from the grid is minimal (Gantner, 2005). 

Pump efficiency = 0.6 Industry provided estimate (Olson, 2004). 

Generator efficiency = 0.85 Estimate based on small size of engines. 

Downhole pressure contribution is negligible Simplification necessary due to lack of data. This 

leads to a slightly conservative estimate. 

Power delivered the pump is exactly equal to the 

power required to lift water over the depth of the 

well and overcome frictional losses. Minor losses 

(joints, flanges, etc...) and exit velocity are 

assumed to be negligible 

The power in lifting the water is undoubtedly much 

greater than any of the other components. No data 

available on minor losses and exit velocity. 

Diameter of pipe that conducts water to surface is 

0.2 ft 

Wyoming OGC provided estimate (Strong, 2005) 

Pipe roughness of drawn/plastic tubing (5x10-6 ft) Industry contact stated majority of piping is 

fiberglass (Weatherford, 2005) 

8760 hours of engine operation and 4380 hours of 

pumping per year 

Industry representative indicated that much of the 

time the engine is operating, but no water is being 

pumped (Gantner, 2005). 
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Information from State OGC and industry contacts enabled us to define the relevant portions of 

the design of the average coal bed methane well. The most common pipe size reported to be 

used by a pumping system supplier, 2 and 3/8 inch, coincided with what the Wyoming OGC 

reported to be a common pipe size on permit applications (Weatherford, 2005; Strong, 2005). A 

representative of one production company operating in Wyoming reported that the vast majority 

of the pumps it used (over 90 percent) are electric submersible pumps (ESP) with an 

approximate efficiency of 60 percent (Olson, 2005). Though producers in other areas, such as 

the San Juan Basin and the Raton Basin, have reported predominantly using other types of 

pumps, including plunger lifts, progressing cavity pumps and rod lift systems, the 60 percent 

efficiency estimate has been used for all areas. Manufacturer information indicates that the ESP 

is the least efficient type of pump and therefore this results in a conservative estimate 

(Weatherford, 2005b). A simple diagram of the assumed pumping system that results from this 

information is provided in Figure 2-6. 

Figure 2-6. Diagram of assumed CBM well. 

With the assumption that minor losses from joints in the pipe or other inconsistencies in the 

system are negligible and that the exit velocity at the top of the pipe is near zero, then the power 

imparted to the water by the pump is equal to the power required to overcome the elevation 

difference and the “frictional losses” (the energy lost to heat and turbulence at the pipe-water 

interface). This system can be described using a form of the Bernoulli equation, where the 
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energy at the exit of the pipe (labeled “2” in Figure 2-6) is equal to the sum of the energy at the 

inlet to the pump (labeled “1” in Figure 2-6) plus the energy supplied by the pump and the 

frictional losses as shown in Calculation 4. 

Calculation 4. Modified Bernoulli equation 

g

P

H H z

g

P

z P L 2 2

2

2 2

2

2

1 1

1

ν

γ

ν

γ

+ + + − = + +

 where: 

 z = Elevation 

 P = Pressure 

 γ = Specific weight of water, 62.4 lb/ft2

ν = Velocity 

Hp = The head imparted by the pump (feet) 

HL = The head lost to friction (feet) 

If the exit velocity is excluded and the downhole pressure assumed to be negligible, then the 

above equation reduces to: 

1 2 z H H z + P + L =

rearranging and substituting the depth (d) for z2 - z1 shows that the energy imparted by the pump, 

Hp, is given by: 

P HL H = d +

HL is somewhat difficult to calculate due to the dependence of the calculation method on the 

flowrate. For the same pipe under a certain threshold flowrate, the flow is laminar and it is a 

simple matter to determine the frictional loss using the Darcy-Weisbach equation. However, 

above that threshold flowrate for the same pipe, the flow becomes turbulent and there are several 

possible methods of estimating the frictional loss. In this study, we have used the HazenWilliams equation to estimate frictional losses for flowrates that imply a Reynolds Number 

above 3000 (see Calculation 5). 

The flowrate itself is not a trivial matter to estimate. The information obtained from the State 

OCD is total annual water production. One option was to assume that flow is constant for 8760 

hours per year. However, based on information generously provided by Bruce Gantner (2005) of 

the New Mexico Oil and Gas Association, it was clear that pumps are frequently operating 

without pumping any fluid apart from gases. This would occur when the water level in the well 

is drawn down low enough that water needs to be pumped only intermittently. Effectively, this 

signifies that a portion of the time the engines are operating with a very low load when no water 

is being pumped and the rest of the time are operating at a load sufficient to pump water. At this 

time, it has not been possible to estimate the fraction of time that the pumps are actually moving 

water and fifty percent has been assumed. This means that fifty percent of the time engines are 

assumed to be idling with only ten percent of their loaded horsepower. These idling emissions, 

discussed below, are added to the emissions resulting from the work performed to lift water from 
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the wells. In terms of the determination of flowrates, this 50 percent operational schedule means 

that flowrates are determined based on the total annual water production divided by 4,380 hours 

per year of pumping. 

Calculation 5. Method for calculating the frictional losses (HL) 

ν

D V R× =

where: 

 R = The Reynolds number 

 D = The diameter of the pipe 

 V = The velocity of flow (flowrate divided by cross-sectional area of pipe) 

ν = The kinematic viscosity of water (assumed = 1.0) 

If R < 3000 then, 

 

g

V

D

L H f L 2

2

= × (the Darcy-Weisbach equation) 

 where 

 L = The length of pipe 

 D = The diameter of pipe 

 V = The velocity of flow 

 g = The acceleration of gravity 

and with 

 

R f 64 =

Else if R > 3000, 

1.85 1.17

1.85

(1.318 C ) R

V L H

H

L

× × = (the Hazen-Williams equation) 

 

where: 

 V = The velocity of flow 

 L = The length of pipe 

R = The hydraulic radius (cross-sectional area of pipe divided by the wetted 

perimeter) 

CH = The Hazen-Williams coefficient, 140 for plastics 
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As shown in calculations 4 and 5, determining the frictional loss and adding that to the depth of 

the well yields the energy that is imparted by the pump. Then, to determine the power of the 

pump we apply the equation shown in Calculation 6. 

Calculation 6. Determining the pump power 

P = H ×Q ×γ / 550 P

where 

 P = the power supplied by the pump (hp) 

 HP = the energy supplied by the pump (ft) 

 Q = the flowrate (cfs) 

γ = specific weight of water (62.4 lb/ft2

) 

Once the power delivered by the pump was determined, determining the power developed by the 

engine was a matter of applying the pump and generator efficiencies as shown in Calculation 7. 

Calculation 7. Determining the engine power 

PE P P G = / ε / ε

where 

 PE = the power developed by the engine (hp) 

 P = the power delivered by the pump (hp) 

εP = the efficiency of the pump (0.60) 

εG = the efficiency of the generator (0.85) 

Total annual engine activity due to pumping water at one well was estimated as the product of 

the power developed by the engine and 4,380 hours per year. To this activity, with units of 

horsepower-hours, was added the engine activity while not pumping water. Engines that are 

idling while no water is being pumped are assumed to operate at ten percent of their operational 

load. Thus, for a single well, the idling engine activity was calculated as ten percent of the 

pumping horsepower determined in Calculation 7 multiplied by 4,380 hours per year. The total 

engine activity was thus the sum of 4,380 hours of engine activity while idling plus 4,380 hours 

of engine activity while pumping. Emissions were then calculated in New Mexico and Colorado 

as the product of total engine activity and the 12 g/hp-hr emission factor for natural gas fired 

engines (SCC 2268006005) provided in EPA’s NONROAD (2004). For Wyoming, an emission 

factor was developed that reflected the controls imposed by WYDEQ on natural gas fired 

engines and the use of some diesel generators to power pumps. That emission factor is 6.1 g/hphr. 

The total emissions estimated by this method for Colorado, New Mexico and Wyoming are 

presented in Table 2-15. This method has resulted in per well NOx emissions for these three 

states of 0.59 tpy/well in Colorado, 0.06 tpy/well in New Mexico and 0.23 tpy/well in Wyoming. 

This represents a significant increase over the emissions predicted by the previous method, 0.080 
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tpy/well, 0.010 tpy/well and 0.067 tpy/well respectively. Despite having a large number of 

wells, New Mexico’s emissions from CBM engines are substantially less than in Colorado and 

Wyoming. This is a result of the relatively low water production in New Mexico. This low 

water production implies less work is done by engines. Industry representatives indicated that 

the San Juan Basin, where most coalbed methane production occurs in New Mexico, is a mature 

field where at this point comparatively little dewatering is necessary (Gantner, 2005). 

Table 2-15. State total NOx emissions from coalbed methane engines. 

State 

CBM 

Wells 

Engine Emissions 

- Pumping (ton/yr)

Engine 

Emissions - 

Idling (ton/yr) 

Total Engine 

Emissions (ton/yr) 

Colorado 2,535 1,354 135 1,489

New Mexico 3,516 204 20 225

Wyoming 12,147 1,298 130 1,428

VOC AND MINOR NOx SOURCE INVENTORY 

In addition to the area sources identified as potentially major sources of NOx emissions, we have 

estimated emissions for several other processes occurring at oil and gas wellheads. Emissions 

were estimated for both NOx and VOC using well-specific production and emission factors 

provided by the Wyoming Department of Environmental Quality and the Colorado Department 

of Public Health and Environment. The sources for which emissions were estimated in this 

portion of the inventory are listed in Table 2-16. 

Table 2-16. Emissions sources estimated in the VOC and minor NOx source inventory. 

Process Pollutants Emission Factors Units 

Tanks - Flashing & 

Standing/Working/Breathing 

VOC lbs per year/barrel per day of 

condensate production 

Glycol Dehydration Units VOC lbs per year/million cubic feet 

per day of gas production 

Heaters NOx, CO lbs per year/well site 

Pneumatic Devices VOC tons per year/well 

Completion - Flaring and Venting VOC, NOx, CO tons/completion 

As proposed in the work plan, the default emission factors used for these sources were the 

emission factors provided by the Wyoming DEQ (2004b). State agencies and industry were 

given the option of providing their own emission factors. Only the CDPHE (2005) provided 

alternate emission factors. The emission factors used are presented in Table 2-17. 
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Table 2-17. Wyoming DEQ emission factors. 

Gas Wells Emission Factor 

Oil Wells 

Source Emission Factor 

Condensate Tanks 

3,271 lbs VOC per 

year/BPD Heater 0.005 lbs NOx per barrel 

Dehydrator 

27,485 lbs per 

year/MMCFD 

Pneumatic 

Devices 0.1 tons VOC / well 

Heater 

1,752.0 lbs NOx per 

year/well Tanks 

160.0 lbs VOC per year / 

BPD 

86.0 tons VOC/well 

completion 

Completion 

1.75 tons NOx/well 

completion 

Pneumatic Devices 

0.2 tons VOC per 

year/well 

CDPHE Emission Factors 

16.664 ton VOC/well 

completion 

Completion 

0.85 ton NOx/well 

completion1

 1

Though the CDPHE only provided an emission factor for VOC, we have used the assumptions used by the CDPHE 

to prepare that emission factor in order to develop an appropriate NOx emission factor. 

2

For documentation of the Wyoming DEQ emission factors, refer to Appendix A.

To use these emission factors, it was necessary to obtain well-specific production data from the 

State oil and gas commissions. In most cases, the necessary data was either compiled by the oil 

and gas commission and submitted to ENVIRON or was downloaded from the oil and gas 

commission’s website. The list of well-specific information obtained from the oil and gas 

commissions is presented in Table 2-18. The list of sources for this production data is similar to 

the list of sources of drill permit data, but is included here as Table 2-19 for completeness. 

Table 2-18. Well-specific data obtained from the oil and gas commissions. 

2002 oil produced 

2002 gas produced 

2002 water produced 

well location (latitude/longitude) 

well field 

well formation 

well depth 

well class (oil/gas) 

coal bed methane (yes/no) 

completion date 
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Table 2-19. Sources of well-specific production data. 

States with Oil/Gas Production in 2002 Source of Production Data 

Alaska Alaska Oil and Gas Conservation Commission 

(AK OGCC), 2005 

Arizona Arizona Geological Survey (AZ GS), 2005 

Colorado Colorado Oil and Gas Conservation 

Commission (CO OGCC), 2005 

Montana Montana Board of Oil and Gas Conservation 

(MT BOGC), 2005 

North Dakota North Dakota Industrial Commission, Oil and 

Gas Division (ND OGD), 2005 

New Mexico New Mexico Environmental Department (NM 

ED), 2005 and New Mexico Oil Conservation 

Division (NM OCD), 2004 

Nevada Nevada Division of Minerals (NV DM), 2005 

Oregon Oregon Department of Geology and Mineral 

Industries (OR DGMI), 2005 

South Dakota South Dakota Department of Environment & 

Natural Resources, Minerals and Mining 

Program (SD MMP), 2005 

Utah Utah Division of Oil, Gas and Mining (UT 

DOGM), 2005 

Wyoming Wyoming Oil and Gas Conservation 

Commission (WY OGCC), 2005 

The fact that records were obtained for all wells that contained each of the fields in Table 2-18 

did not mean that for every well all those fields were populated. The most important fields for 

the purposes of this inventory were those containing the production figures. These appeared to 

be well maintained. However, in some cases the completion date and the well class, which are 

also used in this emission estimate, were blank. It did not appear possible to obtain additional 

data for completion dates, and the assumption is that a blank completion date implies the well 

was completed some time in the past, prior to 2002. 

The data provided by the State of Colorado Oil and Gas Commission presented the most 

difficulty due to the absence of data specifying whether a well was considered an oil or gas well. 

This information was necessary because the emission factors shown in Table 2-17 were 

determined specifically for oil wells or gas wells (WYDEQ, 2004b). In order to proceed, it was 

necessary to divide the wells into these two categories. For the State of Colorado this was 

accomplished by calculating the ratio of gas production (MCF) to oil production (BBL) for all 

wells and then determining where an appropriate division would be. The distribution of wells 

according to their gas oil ratios is presented in Figure 2-7. 
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Distribution based on Gas:Oil Ratio

0

500

1000

1500

2000

2500

3000

3500

4000

0.01

0.1

1

20406080

100

120

140160180

200220240

Gas:Oil Ratio

Number of Wells

Figure 2-7. Distribution of Colorado wells based on the ratio of gas production to oil production. 

There is a clear break in the distribution between wells with a ratio under 0.1 and those with a 

ratio above 0.1. This break places the great majority of wells into the gas well category. Using a 

gas:oil ratio of 0.1 to distinguish between oil and gas wells places 1,385 wells in the category of 

oil wells and 19,847 in the category of gas wells. This may seem an arbitrary division, but it was 

done based on two considerations. First, this division places the large majority of wells into the 

category of gas wells. Gas wells have higher emission factors and thus this represents a 

conservative emissions estimate. Also, the Energy Information Administration estimates over 23 

thousand gas wells in the State of Colorado in 2002, which supports this high number of gas 

wells (EIA, 2005). 

The other important division made was between traditional gas wells and coalbed methane gas 

wells. According to the Wyoming DEQ, the emission factors in Table 2-17 are representative of 

processes at traditional gas wells, not at coalbed methane wells. The only State for which an 

identifier was not provided for coalbed methane wells was the State of New Mexico. In the State 

of New Mexico, coalbed methane wells were identified based on the producing formation 

reported for the well. The wells producing from one of the formations listed in Table 2-20 were 

classified as coalbed methane wells. These are the fields indicated for New Mexico in the map 

of US coalbed methane production produced by the EIA (2004), a section of which is shown in 

Figure 2-8. 

Table 2-20. Coalbed methane producing formations in New Mexico. 

Basin Fruitland Coal 

Castle Rock Park-Vermejo 

Stubblefield Canyon Raton-Vermejo 

Van Bremmer Canyon - Vermejo 
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Figure 2-8. Coalbed methane fields in New Mexico. 

Having obtained well-specific data from all states, divided those wells into oil and gas wells and 

then eliminated the coalbed methane wells, there was still one more filtering of the production 

data required. Because some of the emission factors have units of emissions per well, wells with 

zero oil and zero gas production and a non-2002 completion date were removed from 

consideration. This action would prevent emissions from being estimated at wells where no 

activity actually occurred in 2002. 

Several states reported requiring controls on some of the processes considered in this portion of 

the inventory. The controls reported and the sources of information are presented in Table 2-21. 

Both the controls reported by the CDPHE and WY DEQ are included in the emission factors 

provided by those agencies. The inclusion of these controls in the Wyoming emission factors 

actually presents a small complication, as those emission factors are used to estimate emissions 

in all other States, including those States that did not report any controls on condensate tanks or 

completion emissions. Emissions for completion activities are estimated in all States, except 

North Dakota and Colorado, using the Wyoming emission factors for completions, despite the 

inclusion of controls in the WY DEQ emission factors. This has been done because the flaring 

assumed in the emission factor is not very different from the flaring we would assume based only 

on safety considerations. 
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Table 2-21. Controls on sources considered in the VOC and minor NOx source inventory. 

State 

Condensate 

Tanks 

Completion: Flaring 

& Venting Source 

Colorado Included in EF 

provided 

CDPHE, 2005; 

CDPHE, 2005b 

Montana Flare or vapor 

recovery 

required 

Flare or vapor recovery 

required 

MT DEQ, 2005 

North Dakota Flare or vapor 

recovery 

required 

Flare or vapor recovery 

required 

ND DH, 2005 

Wyoming Included in EF 

provided 

Included in EF 

provided 

WY DEQ, 2004b 

Wyoming DEQ assumed that condensate tanks with greater than 18.3 barrels per day of 

condensate production would be controlled with an overall efficiency of 98 percent. For wells 

with condensate production less than 18.3 barrels per day WY DEQ provided an uncontrolled 

emission factor (see Table 2-17). To account for the absence of controls on condensate tanks in 

States, emissions were simply estimated for all wells in those States using the uncontrolled 

emission factor. 

In contrast to those States where no controls were reported for condensate tanks, Montana and 

North Dakota reported that all condensate tanks are required to achieve the same 98 percent 

control efficiency reported for the larger wells in Wyoming. For these two States, emissions for 

all condensate tanks were estimated using the controlled emission factors provided by WY DEQ. 

Montana and North Dakota environmental agencies also reported that completion emissions 

must be routed to a flare. No modifications were made to account for the completion controls in 

North Dakota because flaring completion gases whenever possible is already assumed in the 

Wyoming emission factor. In the State of Montana, however, it was specified that the control 

efficiency assumed was 98 percent for an elevated flare (MT DEQ, 2005). The control 

efficiency for a flaring assumed by WY DEQ was only 50 percent based on observations that 

flares burn with varying opacity, from 0 to 100 percent, indicating that in many cases a 

significant portion of the fluid is not combusted (WYDEQ, 2004b). To account for the greater 

control efficiency reported by Montana DEQ, the Wyoming emission factors were adjusted for 

use in Montana. 

Based on a typical well completion log, the Wyoming DEQ assumed that 5.0 MMSCF of gas are 

flared or vented during 10 days of completion activity. Using the same characteristics of the 

completion gas as were used by Wyoming DEQ and substituting the Montana DEQ assumption 

of 98 percent control, it was possible to calculate new emission factors for Montana using AP-42 

emission factors for a flare. The details of this calculation, including the assumed gas 

characteristics are shown in Calculation 8. 
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Calculation 8. Calculation of completion emission factors for Montana 

Assumptions adopted from Wyoming DEQ: 

• 5.0 MMCF gas flared or venting daily for 10 days of completion activities 

• VOC and HAP weight percent of gas is 9.43 

• Gas molecular weight of 18.456 lb/lb-mol 

• 1000 Btu/SCF 

Information provided by Montana DEQ: 

• 100 percent of completion gases must be flared 

• flare has a 98 percent destruction efficiency 

AP-42 emission factors: 

• 0.14 lb NOx/MMBtu 

• 0.035 lb CO/MMBtu 

VOC Emission Factor

EF = V x (106

 SCF/MMCF) x F x MW x 1/D x (1 - e) x (ton/2000 lb) x W 

with: 

EF = VOC emission factor (ton VOC per completion) 

V = the volume of gas vented or flared per completion (MMCF per completion) 

F = the fraction of gas sent to the flare (1.0 for Montana) 

MW = molecular weight of gas (lb/lb-mol) 

D = conversion factor, 379 SCF/lb-mol 

e = flare destruction efficiency (0.98 for Montana) 

W = fraction of gas that is VOC 

EF = 50 MMCF x (106

 SCF/MMCF) x 1 x 18.46 lb/lb-mol x 1/(379 SCF/lb-mol) x (1-

0.98) x (ton/2000 lb) x 0.0943 

EF = 2.3 tons VOC per completion 

NOx Emission Factor

EF = V x (106 SCF/MMCF) x F x H x (MMBtu/106 Btu) x A x (ton/2000 lb) 

with: 

EF = NOx emission factor (ton NOx per completion) 

V = the volume of gas vented or flared per completion (MMCF per completion) 

F = the fraction of gas sent to the flare (1.0 for Montana) 

H = the heating value of the gas (1000 Btu/SCF) 

A = AP-42 emission factor for a flare (0.14 lb NOx/MMBtu) 

EF = 50 MMCF x (106

 SCF/MMCF) x 1.0 x 1000 Btu/SCF x (MMBtu/106 Btu) x 0.14 lb 

NOx/MMBtu x (ton/2000 lb) 

EF = 3.5 ton NOx per completion 
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A summary of the final gas well emission factors used is presented in Table 2-22. The final oil 

well emission factors used are those presented in Table 2-17. Having determined the controladjusted Montana completion emission factors, and the procedure for incorporating condensate 

controls into emissions calculations, we proceeded to estimate emissions. Emission factors, 

adjusted as described for controls, were combined with the well data to estimate emissions 

following the general procedure shown in Calculation 9. For completion emissions in the State 

of Colorado, the emission factors provided by CDPHE were used. CDPHE personnel indicated 

that the completion emission factor was based on information for one area of the State and may 

not be applicable to the entire State (CDPHE, 2005). However, because no additional factor was 

provided for the rest of the State, this same emission factor has been used for all of Colorado. 

Table 2-22. Summary of control-adjusted gas well emission factors for VOC and minor NOx 

sources. 

Gas Well Process 

State 

Condensate 

Tanks (lb VOC 

per year/BPD) 

Dehydrator 

(lbs VOC per 

year/MCFD) 

Heater (lbs 

NOx per 

year/well) 

Completion 

(tons per 

completion) 

Pneumatic 

Devices 

(tons VOC 

per year/well)

Alaska NA NA VOC = 86 

NOx = 1.75 

Arizona 3,271 27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

Colorado NA NA 1,752 VOC = 16.7 

NOx = 0.85 

0.2 

Montana 65 NA 1,752 VOC = 2.3 

NOx = 3.5 

0.2 

Nevada 3,271 27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

New Mexico 3,271 27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

North Dakota 65 27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

Oregon 3,271 27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

South Dakota 3,271 27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

Utah 3,271 27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

Wyoming 3,271 

(uncontrolled) 

65 (controlled) 

27,485 1,752 VOC = 86 

NOx = 1.75 

0.2 

Calculation 9 presents a general outline of how emissions were estimated for the VOC and minor 

NOx processes. For detailed sample calculations for each of these processes, refer to Appendix 

B. A summary of the emissions estimated for VOC and minor NOx processes is presented in 

Table 2-23. 
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Calculation 9. Calculation of wellhead emissions for individual wells 

Gas Well

E = SUMi(Pg x EFg,i) + SUMj(Pc x EFc,j) + SUM(EFw) 

where: 

E = The 2002 emission 

Pg = 2002 gas production 

EFg,i = Emission factor for gas process i 

Pc = 2002 condensate production 

EFc,j = Emission factor for condensate process j 

EFw = Per well emission factor 

Oil Well

E = SUMi(Po x EFg,i) + SUM(EFw) 

where: 

E = The 2002 emission 

Po = 2002 oil production 

EFo,i = Emission factor for oil process i 

EFw = Per well emission factor 

Table 2-23. State total emissions for VOC and minor NOx sources. 

State VOC NOx 

Alaska1 430 9

Arizona 

Colorado2 25,386 15,924

Idaho 

Montana3 5,439 4,721

Nevada 129 5

New Mexico 166,773 13,482

North Dakota 7,740 176

Oregon 34 12

South Dakota 288 47

Utah 34,757 2,143

Washington 

Wyoming 115,027 6,283

1

Emissions in Alaska estimated only for completion emissions. 

2

Emissions in Colorado not estimated for condensate tanks or glycol dehydrators. 

3

Emissions in Montana not estimated for glycol dehydrators.

Several modifications are represented in this summary table that have not yet been mentioned. 

Emissions for condensate tanks and glycol dehydrators are not included for the State of 
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Colorado. In Colorado, those sources are expected to be included in the point source inventory 

due to the low inventory threshold (CDPHE, 2005b). Nor are emissions included for any 

process, except completion activities, in the State of Alaska. Again, emissions from the other 

VOC and minor NOx sources are expected to be included in the State’s point source inventory; 

in this case because wellhead equipment is permitted under the umbrella of larger facilities (AK 

OGCC, 2005b; AK DEC, 2005b). Emissions have not been estimate for glycol dehydrators in 

the State of Montana because it was reported that no wellhead dehydrators have been installed in 

Montana (MT DEQ, 2005). 
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3. SPATIAL ALLOCATION SURROGATES FOR MODELING 

For air quality modeling, the EPA default spatial allocation surrogates were not appropriate for 

the area source oil and gas production emissions. ENVIRON therefore developed a new set of 

spatial allocation surrogates to be used in SMOKE to allocate the county-level area source 

emissions to the appropriate oil and gas fields. This section summarizes the development of 

these new oil and gas spatial allocation surrogates in the WRAP states. 

Spatial allocation surrogates were developed for two modeling domains: 

36 km 12 km 

Origin (-2736, -2088) Origin (-2376, -936) 

NX = 148, NY = 112 NX = 207, NY = 186 

As outlined in Table 3-1, twelve oil and gas emission source categories were assigned to one of 

four different surrogate categories designed to represent the location of emissions. The oil, gas 

and water production surrogates were based on production data at known well locations, while 

the drill rig surrogate was based solely on the number and location of wells drilled. 

Table 3-1. Emission sources and surrogate categories. 

Source SCC Allocation Surrogate Surrogate Code 

Drill rigs 2310000220 Drill Rigs 688 

Oil well - heaters 2310010100 Oil Production 686 

Oil well - tanks 2310010200 Oil Production 686 

Oil well - pneumatic devices 2310010300 Oil Production 686 

Compressor engines 2310020600 Gas Production 685 

Gas well - heaters 2310021100 Gas Production 685 

Gas well - pneumatic devices 2310021300 Gas Production 685 

Gas well - dehydration 2310021400 Gas Production 685 

Gas well - completion 2310021500 Gas Production 685 

CBM pump engines 2310023000 Water production at CBM wells 687 

Gas well - tanks, uncontrolled 2310030210 Gas Production 685 

Gas well - tanks, controlled 2310030220 Gas Production 685 

Methods 

Latitude and longitude coordinates for oil and gas wells and drill rigs were obtained for the 

WRAP states, except California. The locations of all wells and drill rigs are shown in Figure 3-

1. Also displayed are the boundaries of the Tribal lands of the Arapahoe and Shoshone of the 

Wind River Reservation, Assiniboine and Sioux of the Fort Peck Reservation, Jicarilla Apache, 

Navajo, Southern Ute and Ute Mountain Ute. Note that neither Washington nor Idaho had any 

wells in the database. 

Once the well locations were known, creation of the surrogates took place in several steps, and 

relied on the use of ArcINFO GIS software. 
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1. All wells and drill rigs were labeled with the appropriate grid cell IJ values for both the 

36 and 12 km domains. 

2. For each individual well, the oil, gas and water production values were divided by the 

total oil, gas and water production values corresponding to the county in which the well 

was located. This division resulted in determination of the fraction of a county’s total 

production taking place at each well. In the case of drill rigs, the number of drills, rather 

than the production values, were used. 

3. For each unique grid cell / county combination with wells, each well’s production 

fractions were summed to create the surrogate value. This step was repeated for both 

domains separately. 

Figure 3-1. Locations of wells and drill rigs. 

The surrogate values for each grid cell / county combination were reformatted to comply with 

the SMOKE emissions processor AGPRO file format. A separate file for each modeling domain 

was created, and a single accompanying SMOKE AGREF file was created for use with either 
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domain. The purpose of the AGREF file, which is shown in Table 3-2, is to define the 

relationship between the 3-digit codes chosen to represent each of the four surrogate categories 

in the AGPRO file and the SCC codes for the twelve oil and gas emission categories to be 

allocated with these surrogates. This file also specifies which county/state/county (COSTCY) 

should use the given cross-reference. In this case, COSTCY is set to 000000 to indicate that all 

states and counties can use these cross-references. 

Table 3-2. SMOKE gridding surrogate cross-reference (AGREF) file. 

COSTCY SCC CODE 

000000 2310000220 686 

000000 2310010100 688 

000000 2310010200 686 

000000 2310010300 686 

000000 2310020600 686 

000000 2310021100 685 

000000 2310021300 685 

000000 2310021400 685 

000000 2310021500 685 

000000 2310023000 687 

000000 2310030210 685 

000000 2310030220 685 

Results 

To display the surrogates, each grid cell / county surrogate value was multiplied by the county’s 

total production, and then production was summed for each grid cell. Figures 3-2 through 3-5 

depict the four different 36 km domain surrogate values; Figures 3-6 through 3-9 depict the 12 

km domain surrogate values. These spatial allocation surrogates were used in both the 2002 and 

2018 air quality modeling. 

Figure 3-10 shows an example daily spatial emissions plot of the 2002 oil and gas emissions as 

processed through SMOKE. 
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Figure 3-2. Oil production surrogates for the 36 km domain. 
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Figure 3-3. Gas production surrogates for the 36 km domain. 
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Figure 3-4. CBM well water production surrogates for the 36 km domain. 
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Figure 3-5. Drill rig surrogates for the 36 km domain. 
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Figure 3-6. Oil production surrogates for the 12 km domain. 
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Figure 3-7. Gas production surrogates for the 12 km domain. 
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Figure 3-8. CBM well water production surrogates for the 12 km domain. 
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Figure 3-9. Drill rig surrogates for the 12 km domain. 
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Figure 3-10. Example daily spatial emissions plot of the 2002 oil and gas emissions as 

processed through SMOKE.
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4. 2018 BASE CASE PROJECTIONS 

INTRODUCTION 

This section describes the methods for estimating the 2018 base case emission inventory of oil 

and gas area sources for the Western States. This inventory reflects the anticipated 2018 

emission levels with the future controls currently defined by state and federal regulation. The 

2018 oil and gas point source emissions inventory has been prepared under a separate task, and is 

reported separately (ERG, 2005b). Thus, while some tables in this section present summaries of 

the 2018 point source emissions, information about the methodology used to develop those 

emissions estimates will be found in the report addressing the 2018 point source emissions 

inventory. 

The emissions summaries presented here for the 2018 base case inventory do not include 

emissions falling under tribal jurisdiction. Under another project, ENVIRON has prepared 

separate emissions estimates of tribal oil and gas emissions for four tribes. Those emissions 

estimates have been reconciled with the emissions reported here, and tribal emissions are being 

reported separately (ERG/ENVIRON, 2005). 

Apart from those western states that have no oil or gas production, such as Idaho and 

Washington, the only state for which area source emissions are not estimated here is the State of 

California. The California Air Resources Board (CARB) has provided point and area source oil 

and gas emissions projections directly to WRAP. Those estimates have been adopted by this 

inventory and are considered to be complete. 

Table 4-1a presents a summary of the estimated 2018 NOx emissions from oil and gas area point 

and area sources in the WRAP States. Table 4-1b presents a similar summary of VOC 

emissions. The area source emissions are distinguished by source category, except in California 

where only the total NOx emission from the ARB inventory is given. The point source 

emissions included in Tables 4-1a and 4-1b include several types of oil and gas facilities that are 

listed under SIC codes 13**, 492* or 4612. In most states, the major contributors of point source 

oil and gas emissions are natural gas transmission stations and natural gas processing plants. 

Crude oil pump stations and large storage sites also make a significant contribution in some 

states. Notably, the point source inventory methods in the State of Colorado and the State of 

Alaska are such that the majority of oil and gas emissions sources are included in the point 

source inventory. 
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Table 4-1a. 2018 State total NOx emissions (tons) from oil and gas sources. 

Alaska 566 2 568 36,501 37,069 

Arizona 3,468 3,468 

California 13,390 13,390 

Colorado 4,051 23,474 184 27,709 15,832 43,541 

Idaho 1,734 1,734 

Montana 19,029 3,630 7,631 240 30,529 2,554 33,084 

Nevada 48 17 7 72 139 212 

New Mexico 102,260 7,850 28,420 21 138,551 36,323 174,874 

North Dakota 6,751 1,293 633 1 8,678 2,946 11,624 

Oregon 42 - 7 48 608 656 

South Dakota 414 25 68 507 311 818 

Utah 4,736 2,212 6,225 1 13,174 2,314 15,488 

Washington 703 703 

Wyoming 32,729 7,437 18,466 901 59,533 9,713 69,246 

 27,082 166,009 84,932 1,348 279,370 126,536 405,907 

Point Source 

State Wellhead Total TOTAL

CBM Pump 

Engines

Area Source 

Total

Total

Compressor 

Engines Drill Rigs

Table 4-1b. 2018 State total VOC emissions (tons) from oil and gas sources. 

Note: Entries with a “-“ indicate emissions were estimated to be zero. Entries that are blank indicate that emissions 

for the state/source combination are not estimated in this area source portion of the inventory.

Table 4-2 compares the results of the 2018 oil and gas inventory with the 2002 oil and gas 

emissions inventories for NOx. Area source NOx emissions estimated for 2018 show a 114 

percent increase over 2002 levels. In the total oil and gas emissions, this large increase in area 

source emissions is partially offset by a greater than 50 thousand ton decrease in NOx emissions 

predicted for point sources. The area source and overall increases are most substantial in places 

where recent development plans predict large-scale oil and gas projects in future years. Such is 

the case in Montana and Wyoming where major development is anticipated for the Powder River 

Basin and the Jonah-Pinedale area. 

State

Oil Well, Tanks - 

Flashing & 

Standing/Worki

ng/Breathing

Oil Well, 

Pneumatic 

Devices

Gas Well, 

Pneumatic 

Devices

Gas Well, 

Dehydrators

Gas Well, 

Completion - 

Flaring and 

Venting

Condensate 

Tanks, 

Uncontrolled

Condensate 

Tanks, 

Controlled

Area Source 

Total

Point Source 

Total TOTAL

Alaska 92 92 2,112 2,204 

Arizona 345 345 

California 4,962 4,962 

Colorado 973 176 4,997 30,912 37,058 59,436 96,494 

Idaho 114 114 

Montana 4,938 471 1,507 - 637 - 2 7,556 1,024 8,580 

Nevada 162 9 1 0 - - - 173 32 205 

New Mexico 9,357 1,345 5,981 97,981 103,954 110,028 - 328,647 18,339 346,986 

North Dakota 8,227 415 120 3,370 659 - 261 13,052 262 13,315 

Oregon - - 2 18 - - - 19 23 42 

South Dakota 329 16 15 28 - - - 387 38 426 

Utah 3,960 304 1,153 13,666 55,569 20,634 - 95,286 3,028 98,314 

Washington 36 36 

Wyoming 11,369 1,196 3,586 195,221 129,292 62,501 1,469 404,633 10,155 414,788 

Total 39,315 3,932 17,361 310,285 321,115 193,163 1,732 886,904 99,907 986,811 
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Table 4-2. Change in oil and gas NOx emissions from 2002 to 2018. 

Alaska -35% -79% -36% -20% -21%

Arizona 27% 27%

California -20% -46%

Colorado -29% 47% -88% 20% -39% -11%

Idaho -33% -33%

Montana 839% 248% 62% 292% -40% 174%

Nevada 46% -31% 42% 16% 68% 46%

New Mexico 155% 18% 111% -91% 129% -36% 49%

North Dakota 131% -16% 261% 87% -38% 24%

Oregon -43% 0% -43% -43% -49% -48%

South Dakota 46% -31% 45% 38% -4% 19%

Utah 100% 227% 191% 154% -30% 82%

Washington -45% -45%

Wyoming 366% 50% 194% -37% 202% -35% 99%

203% 26% 98% -57% 114% -30% 30%

Compressor 

Engines Drill Rigs Wellhead

CBM Pump 

Engines

Area Source 

Total

Point Source 

Total TOTAL

Total

State

AREA SOURCE OIL AND GAS GROWTH FACTORS 

At the most basic level there were two methods used to estimate 2018 county-level oil and gas 

emissions. The first and by far the dominant method was to develop growth factors that were 

then used to project from the 2002 oil and gas emissions. A second method was necessary to 

estimate emissions in the handful of counties that had no 2002 oil and gas emissions but are 

anticipated to see oil and gas development by 2018. The decision of which method was used to 

estimate 2018 emissions was based on the existence of oil and gas emissions in 2002. 

Discussion of the method used for the group of counties with no emissions in 2002 is reserved 

for later in this section. Here, the data sources and methodologies are presented that were used 

to project 2002 emissions to 2018 for the three conditions where oil and gas emissions were 

present in 2002. 

Production Growth Factors 

The projection of emissions from 2002 to 2018 required the development of county-level growth 

factors. These growth factors were derived from projections of future oil and gas production 

reported by several sources. The preferred source of production projections was the Bureau of 

Land Management (BLM). The BLM periodically prepares Resource Management Plans (RMP) 

for the lands and mineral resources under its stewardship. RMP for oil and gas production areas 

typically include an estimate of reasonable foreseeable oil and gas development. The future 

development is usually estimated as a number of new oil, gas and possibly CBM wells 

anticipated over the next 10 or 20 years. Table 4-3 provides a brief summary of the reasonable 

foreseeable development (RFD) scenarios that were ultimately used to obtain the necessary 

information for creating the 2002 to 2018 growth factors. 
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Table 4-3. BLM Resource Management Plans considered for use in projections. 

RMP 

ID RMP_NAME Source 

Start 

Date End Date

Gas 

Wells 

Oil 

Wells 

CBM 

Wells 

Wells 

Drilled 

1 

Northern San Juan Basin 

Coal Bed Methane Project 

USDA 

FS, 2004 1/1/2004 1/1/2018 296 296 

2 Pinedale RMP 

WY BLM, 

2005 1/1/2006 1/1/2025 9800 9800 

3 

Wyoming Powder River 

Basin Final EIS 

WY BLM, 

2001 1/1/2002 1/1/2022 81000 81000 

4 

White River Resource Area 

RMP EIS 

CO BLM, 

1996 1/1/1996 1/1/2016 919 1100 

5 

RMP EIS for Mineral Leasing 

and Development in Sierra 

and Otero Counties 

NM BLM, 

2003 

1/1/2003 1/1/2023 36 48 105 

6 

Dakota Prairie Grasslands 

Oil and Gas Leasing 

USDA 

FS, 2003 1/1/2003 1/1/2013 450 60 660 

7 

Farmington Proposed 

Resource Management Plan 

NM BLM, 

2003 1/1/2002 1/1/2022 13271 380 2964 16615 

8 

Desolation Flats Natural Gas 

Field Development Project 

WY BLM, 

2004 1/1/2004 1/1/2024 308 474 

9 

Draft Vernal Resource 

Management Plan 

UT BLM, 

2005 1/1/2006 1/1/2021 4345 2055 130 6530 

10 

Jack Morrow Hills 

Coordinated Activity 

WY BLM, 

2004b 7/1/2004 1/1/2021 107 50 255 

12 

Wind River Natural Gas 

Project 

BIA, 2004

1/1/2005 1/1/2018 325 325 

13 

Powder River and Billings 

Resource Management Plan 

MT DEQ, 

2003 1/1/2003 1/1/2023 800 18200 19000 

14 

Powder River and Billings 

Resource Management Plan 

MT DEQ, 

2003 1/1/2003 1/1/2023 250 6400 6650 

15 

Powder River and Billings 

Resource Management Plan 

MT DEQ, 

2003 1/1/2003 1/1/2023 150 150 

As shown in Table 4-3, we obtained a number of RMPs covering a large portion of the WRAP 

production areas. Figure 4-1 shows the approximate area covered by these resource management 

plans. Despite the broad combined coverage of these plans, there are some significant 

production areas for which management plans could not be located. 
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Figure 4-1. Coverage of resource management plans ultimately used to create growth factors.

For some of the areas where it was not possible to obtain recent local development forecasts 

from the BLM, other sources of local data were identified. For example, the Alaska Department 

of Natural Resources (AK DNR, 2004) prepares 20-year production forecasts that were used in 

this effort. Other local sources of data were considered, but were ultimately discarded due either 

to a lack of detail, the reporting of only the next two or three years, or for a combination of 

inadequate detail and time-span. Thus, for the areas not covered by the RMP listed in Table 4-3 

and not in the State of Alaska, regional production forecasts published by the Energy 

Information Administration (EIA, 2005b) were used. 

The EIA has published projection forecasts out to 2025. For production areas where EIA 

forecasts were the only source of data identified, separate oil and gas growth factors have been 

calculated as the 2018 regional production forecast by the EIA divided by 2002 regional 

production reported by the EIA. There are three EIA growth regions in which some portion of 

emissions in that region were projected using EIA data. Those regions are the Rocky Mountain 

Region, the Southwest Region and the West Coast Region. Growth factors developed for those 
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regions based on the EIA’s production forecasts are shown in Table 4-4. The delineation of 

those regions is shown in Figure 4-2. 

Table 4-4. 2002 to 2018 oil and gas growth factors based on EIA forecasts. 

Region Oil Production Gas Production

Rocky Mountain 1.334 1.458 

Southwest 0.866 1.354 

West Coast 0.601 0.568 

Figure 4-2. EIA production forecasting regions. 

Projections to 2018 based on the BLM resource management plans or Alaska DNR data were 

made using growth factors derived from the proposed future development and the actual 2002 

activity. In order to estimate the future number of wells, both the number of wells installed and 

the number of wells plugged and abandoned had to be estimated. The RMPs do not include 

estimates of the number of wells that will be plugged and abandoned in future years. The 

historical plugging and abandoning of wells was, however, available from the OGCs. Thus, 

lacking other projections of future well abandonment, we used OGC data to estimate the number 

of wells plugged and abandoned annually at the county level. We then developed an estimate of 

the future number of wells in a production area based on the number of existing wells in 2002, 

the number of new wells anticipated by the RMP and the estimated number of wells that would 

be abandoned based on the assumed persistence of historical abandonment rates. The calculation 

of a growth factor was thus accomplished as shown in Calculation 1. 
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Calculation 1: Determination of CBM, oil and gas well growth factor based on BLM RMP 

( )

02

02

W

W W W

G

+ f − P =

where: 

G = the 2002 to 2018 growth factor 

W02 = the wells (oil/gas/CBM) active in 2002 

Wf = the wells (oil/gas/CBM) forecast to be added by 2018 

WP = the wells (oil/gas/CBM) estimated to be plugged and abandoned by 2018 

Because gas production at all well types drives compressor emissions, none of the three growth 

factors developed for oil wells, gas wells or CBM wells was alone representative of growth in 

compression. Compressor engine emissions needed to be projected based on the total growth in 

gas production. Thus a growth factor for total gas production was developed as shown in 

Calculation 2. 

Calculation 2: Derivation of a gas production growth factor based on BLM RMP 

( )

∑

∑ + − =

i i i

i i i f i P i

gas P W

W W W P

G

02,

02, , ,

*

*

where: 

 i refers to the three well types: oil, gas and CBM 

Ggas = the 2002 to 2018 growth factor 

Pi = the average 2002 production of an oil/gas/CBM well 

W02,i = the oil/gas/CBM wells active in 2002 

Wf,i = the oil/gas/CBM wells forecast to be added by 2018 

WP,i = the oil/gas/CBM wells estimated to be plugged and abandoned by 2018 

In areas with coverage by a RMP, a separate growth factor was estimated for drill rig activity as 

the number of wells drilled per year suggested by the development scenario divided by the 

number of wells drilled in the same area in 2002. A growth factor for drilling in areas where 

EIA forecasts were used was determined based on the total predicted growth in well drilling in 

the lower 48 states as reported the EIA forecast, as regional drilling growth was not available. 

27.25 thousand wells are anticipated to be drilled in the lower 48 states in 2018, versus 25.45 

thousand wells drilled in 2002. From this information a drill rig activity growth factor of 1.071 

was calculated. 

A total of eight types of growth factors were used to project 2018 oil and gas emissions; three 

types were developed from EIA forecasts, and five types were based on local production 

projections. A summary of these eight types of growth factors is presented in Table 4-5. The 

estimation of emissions in the year 2018 using these growth factors is discussed below. 
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Table 4-5. Projection growth factors. 

ID Data Source 

Growth 

Factor Derivation 

G1 EIA Gas production 2018 estimated gas production for the region divided by 

2002 gas production for the region 

G2 EIA Oil production 2018 estimated oil production for the region divided by 

2002 gas production for the region 

G3 EIA Well drilling 2018 estimated wells drilled in the lower 48 divided by 

2002 wells drilled in the lower 48 

G4 Local Gas wells 2018 estimated gas wells in the planning area divided 

by 2002 gas wells in the planning area (Calculation 1) 

G5 Local Oil wells 2018 estimated oil wells in the planning area divided by 

2002 oil wells in the planning area (Calculation 1) 

G6 Local CBM wells 2018 estimated CBM wells in the planning area divided 

by 2002 CBM wells in the planning area (Calculation 1) 

G7 Local Gas production 2018 estimated total gas production in the planning 

area divided by total 2002 gas production in the 

planning area (Calculation 2). 

G8 Local Well drilling Number of wells drilled per year suggested by the 

development forecast divided by the number of wells 

drilled in 2002 

2018 Emissions Projections 

In all counties having 2002 emissions for a given oil and gas area source process, the 2018 

emissions estimate for that process was made by applying a growth factor to the 2002 emissions 

and then adjusting the estimate to incorporate future year controls. As growth factors were 

developed for production areas rather than counties, it was necessary to intersect the production 

areas with the WRAP counties to determine which growth factor to apply in each county. This 

intersection yielded three distinct conditions: Counties entirely within a RMP area, counties 

partially within an RMP area and counties not in a RMP area. In the counties only partially 

intersected by a RMP area, it was necessary to apply BLM-based growth factors to the fraction 

of the wells in the RMP area and EIA-based growth factors to the remaining wells. The general 

formula used to estimate 2018 emissions for the process-specific emissions estimates is 

presented in Calculation 3. Which of the eight growth factors were applied to each of the 

emissions sources is stipulated in Tables 4-6 and 4-7. 

 

Calculation 3. General formula for projecting process-specific emissions estimates 

E18 = G * E02

where: 

 E18 = the emissions from a process in 2018 

 G = the growth factor for the process, as indicated in Tables 4-6 and 4-7 

 E02 = the emissions from a process in 2002 
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Table 4-6. Growth factor used for each source in areas where local plans were used. 

Source Growth Factor*

Compressor Engines Local Gas Production (ID = G7) 

CBM Pump Engines Emissions grown based on CBM well growth factor (ID = G6) 

Oil Well - Minor NOx & 

VOC sources 

Emissions grown based on oil well growth factor (ID = G5) 

Gas Well - Minor NOx & 

VOC sources 

Emissions grown based on gas well growth factor (ID = G4) 

Drill Rigs Emissions grown based on growth in number of wells drilled 

annually (ID = G8) *

IDs correspond to those assigned in Table 4-5 

Table 4-7. Growth factor used for each source in areas where EIA data were used. 

Source Growth Factor* 

Compressor Engines Emissions grown based on gas production growth factor (ID = G1)

CBM Pump Engines Emissions grown based on gas production growth factor (ID = G1)

Oil Well - Minor NOx & 

VOC sources 

Emissions grown based on oil production growth factor (ID = G2) 

Gas Well - Minor NOx & 

VOC sources 

Emissions grown based on gas production growth factor (ID = G1)

Drill Rigs Emissions grown based on growth in wells drilled (ID = G3) 

*

IDs correspond to those assigned in Table 4-5 

Figure 4-3 shows a sample of how different growth rates would be applied to areas that, while 

physically near each other, fell in distinct EIA forecast regions or one inside and the other 

outside of a RMP area. Figure 4-4 then displays the growth factors developed for gas production 

in the WRAP states. A complete list of the growth factors developed to project 2002 area source 

oil and gas emissions to 2018 is provided as Appendix D. 
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Figure 4-3. Sample application of growth factors derived from RMP and from EIA sources. 

Figure 4-4. Growth factors developed to represent growth in gas production in WRAP region. 
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Independent 2018 emissions estimates 

As is apparent in Figure 4-3, there were some areas where an RMP predicted oil and gas 

development, but no oil or gas wells existed in 2002. In those cases, the growth factor approach 

could not be applied. Instead, a method was developed whereby emissions were estimated based 

on the development forecast by the RMP and the average emissions associated with similar oil 

and gas sources in the same State. The general form of the calculation used to estimate 2018 

emissions in these counties is presented as Calculation 4. 

 

Calculation 4. General formula for independent estimates of 2018 emissions 

E18,P = DP* E02,P

where: 

 E18,P = the emissions from a process in 2018 

 D = the forecast development of process p in the area 

 E02,P = the state average emissions from process p in 2002 

Counties where this method was applied were first identified when the intersection of the RMP 

areas with counties resulted in the assignment of 2018 RMP-predicted oil, gas, CBM and/or 

drilled wells to a county that had no such wells in 2002. This number of 2018 oil, gas, CBM 

and/or drilled wells served as the activity measure for the 2018 emissions estimates. State 

specific emission factors were derived by dividing 2002 state total process-specific emissions by 

the number of 2002 oil, gas or drilled wells. In the case of CBM wells, the lack of 2002 

emissions in some states required that an emission factor be adopted from another area. In these 

cases, data from the State of Wyoming were adopted. The emission factors that resulted for NOx 

are shown in Table 4-8. Emission factors for other pollutants were developed by the same 

approach. 

Table 4-8. State NOx emission factors used to estimate 2018 emissions. 

Process Drill Rigs Compressor 

Engines 

Oil Well 

Heaters 

Gas Well 

Heaters 

Gas Well 

Completion 

Flaring & 

Venting 

CBM Pump 

Engines 

Derivation Drill Rig 

Emissions/

Wells Drilled 

Compressor 

Emissions/ 

Gas 

Produced 

Oil Well 

Heater 

Emissions

/Oil Wells 

Gas Well 

Heater 

Emissions/

Gas Wells 

Gas Well 

Completion 

Emissions/ 

Gas Wells 

CBM 

Emissions/ 

CBM Wells 

Units tons/well 

drilled 

tons/MCF tons/well tons/well tons/well tons/well 

Montana 2.26 2.34x10-5 0.011 0.859 0.147 0.12 

New Mexico 7.12 2.34x10-5 0.008 0.868 0.046 0.12 

North Dakota 9.78 2.34x10-5 0.867 0.031 0.12 

Utah 5.37 4.11x10-6 0.015 0.12 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec4_2018emissions.doc 4-12

The emission factors in Table 4-8 were combined with development forecasts as shown in 

Calculation 4 to produce the county-level emissions shown in Table 4-9. These emissions 

estimates were then combined with the projected 2018 emissions to produce a comprehensive 

2018 area source oil and gas emission inventory. 

Table 4-9. 2018 emissions estimates for counties with no 2002 emissions. 

State County Drill Rigs 

Compressor 

Engines Wellhead 

CBM Pump 

Engines 

Montana Big Horn 720.45 7,754.11 35.00 119.81 

 Golden Valley 7.23 - - - 

 Mussellshell 124.73 22.42 64.46 - 

 Powder River 720.45 7,740.31 - 119.81 

 Yellowstone 50.61 10.45 26.49 - 

New Mexico McKinley 67.83 - - - 

 Otero 9.22 26.74 12.02 - 

 Sandoval 35.05 - - - 

 Sierra 13.83 28.44 12.94 - 

North Dakota Billings 137.76 799.48 213.00 0.15 

 Dunn - 13.70 1.15 0.15 

 Golden Valley 8.54 58.42 13.20 0.15 

 Slope 7.43 52.03 11.48 0.15 

Utah Daggett 6.21 0.55 0.13 - 

 Duschene - 14.40 - 1.27 

Total 1,909.34 16,521.05 389.87 241.47 

Future Year Emission Controls 

Implementation of new federal and state control programs will have a substantial impact on 

future emissions. Known State and Federal emissions control estimates were incorporated into 

the base case projections for 2018. A summary of the controls that have been identified and the 

actions taken to incorporate them into the 2018 projections is provided in Table 4-10. These 

controls add to those previously identified in the 2002 inventory. Thus, although not presented 

here, the state-specific controls included in the 2002 inventory are adopted by the 2018 

inventory. A discussion of the controls identified by the 2002 inventory is provided in Section 2. 

Table 4-10. Projection information provided by State DEQ. 

State Future Controls Action 

All Nonroad diesel engine standards (EPA, 2004) Used phase-in and emissions standards 

information for 750+ hp drill rig engines from 

EPA’s NONROAD model to adjust drill rig 

engine emissions for future performance 

standards 

All Nonroad spark-ignition engine standards (EPA, 

2004) 

Used phase-in and emissions standards 

information for natural gas fired nonroad 

engines (SCC 2268000000) from EPA’s 

NONROAD model to adjust CBM pump engine 

emissions for future performance standards 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec4_2018emissions.doc 4-13

State Future Controls Action 

Colorado1

• 2004, control for glycol dehydrators 

requiring units in the nonattainment area 

with greater than 15 tpy VOC emission to 

achieve 90% control. 

• 2006, new control of large engines in the 

Denver-Joulsbourgh Basin NA Area 

• 2006, new control on condensate tanks 

requiring VOC emissions in nonattainment 

area reduced by 47.5% during the VOC 

season and 38% during off season 

(CDPHE, 2005) 

The following was used as inputs to the 

procedure used to project point sources: 

• Determine fraction of dehydrators in 

nonattainment area and for 2004 and 

beyond apply 90% control to that fraction. 

• Select engines with greater than 500 hp 

and apply 90% control for 2006 and 

beyond. 

• Reduce annual VOC emissions from 

condensate tanks by 43% for 2006 and 

beyond. 

Montana 2006, allow producers to include controls in their 

potential to emit estimates so that they can stay 

under 25 tpy and thus not be permitted. DEQ 

regulation will probably be introduced to require 

controlling PTE to 25 tpy (MT DEQ, 2005) 

No action taken because control requirement 

has not been promulgated. 

Utah Controls under development with EPA Region 8 

(UT DEQ, 2005) 

No action taken because control requirements 

have not been promulgated. 1

In Colorado, due to the low point source inventory threshold, these control adjustments have been made in the point 

source inventory 

With the exception of the rules imposed in the State of Colorado, the future year controls 

reported by States were not certain to be implemented and their potential impact was uncertain. 

In other words, only “on-the-books” controls have been accounted for in this inventory. Due to 

the low inventory threshold in the State of Colorado, those state-level controls were incorporated 

in the point source inventory. That left only the federal nonroad engine performance standards to 

incorporate in this inventory. 

After discussion with members of the oil and gas working group, it was determined that the 

nonroad engine performance standards were applicable to drill rig engines and CBM pump 

engines, but not to compressor engines. The compressor engine 2018 emissions assume future 

compressor engines are therefore not required to meet federal nonroad engine standards. In 

contrast, the 2018 drill rig and CBM pump emissions were adjusted downward under the 

assumption that future equipment purchases will be required to meet the federal nonroad engine 

standards. The adjustment for drill rig emissions was performed by comparing the emission 

rates yielded by EPA’s NONROAD model for 750+ horsepower drill rig engines in 2018 versus 

those for the same category in 2002. For CBM pump engines, the adjustment was performed by 

comparing the emission rates given by the NONROAD model for natural gas fired engines in 

2018 versus those for the same category in 2002. These comparisons were performed on a 

county level for all WRAP counties and control factors were derived for each county as the 2018 

emission rates divided by the 2002 emission rates. The county-level controlled 2018 emissions 

were then calculated as the product of the county control factor and the uncontrolled 2018 

emissions estimate. The emission summaries presented at the beginning of this section represent 

the comprehensive 2018 oil and gas emissions estimates with “on-the-books” controls. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec5_References.doc 5-1 

5. REFERENCES 

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Oil and Gas Conservation Commission (Elaine Johnson, 

elaine_johnson@admin.state.ak.us). March 9, 2005. 

AK OGCC, 2005b. Information on oil and gas production facilities in Alaska provided by staff 

of the Alaska OGCC (Tom Maunder, tom_maunder@admin.state.ak.us). March 18, 

2005. 

AK DEC, 2005b. Information on permitting of oil and gas production facilities in Alaska 

provided by staff of the Alaska DEC (Bill Walker, 907-465-5124). March 18, 2005. 

AK DNR, 2004. “Alaska: Oil and Gas Report”. Alaska Department of Natural Resources, 

Division of Oil & Gas. December. Internet address: 

http://www.dog.dnr.state.ak.us/oil/products/publications/annual/report.htm. 

AZ DEQ, 2005. Information on permitting and inventory efforts in the State of Arizona 

provided by staff of the Arizona Department of Environmental Quality (Latha Toopal, 

toopal.latha@AZDEQ.GOV). May 31, 2005. 

AZ GS, 2005. Well drilling and well production information provided by staff of the Arizona 

Geological Survey (Steve Rauzi, steve.rauzi@azgs.az.gov). February 28, 2005. 

BLM, 2002. Powder River Basin Oil and Gas Environmental Impact Statement. Prepared by the 

Bureau of Land Management. 

CC DAQM, 2005. Information on permitting and inventory efforts in Clark County, Nevada 

provided by staff of the Clark County Department of Air Quality Management (Cheng 

Shih, Shih@Co.Clark.NV.US). May 9, 2005. 

CDPHE, 2005b. Information on permitting and inventory efforts in the State of Colorado 

provided by staff of the Colorado Department of Public Health and Environment (David 

Thayer, david.thayer@state.co.us). 

CDPHE, 2005. Emission factors for oil and gas production processes in the State of Colorado 

provided by staff of the Colorado Department of Health and Environment (Roy Doyle, 

roy.Doyle@state.co.us). March 25, 2005. 

CO OGCC, 2005. Well drilling and well production information provided by staff of the 

Colorado Oil and Gas Conservation Commission (Thom Kerr, thom.kerr@state.co.us). 

March 21, 2005. 

Daniels, 2005. Information on coalbed methane production in Utah provided by Ron Daniels of 

the Utah Department of Natural Resources. March 2005. 

EIA, 2004. “Coalbed Methane in the US”. The Energy Information Administration. Internet 

address: 
December 2005 

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http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm#T

op. 

EIA, 2005. “Number of Producing Gas and Gas Condensate Wells”. Energy Information 

Administration. Internet address: 

http://tonto.eia.doe.gov/dnav/ng/ng_prod_wells_s1_a.htm. 

EIA, 2005b. “Annual Energy Outlook 2005 with Projections to 2025”. Energy Information 

Administration. January. Internet address: http://www.eia.doe.gov/oiaf/aeo/index.html. 

EPA. 2004. EPA’s NONROAD 2004 Emissions Model. Internet address: 

http://www.epa.gov/otaq/nonrdmdl.htm. 

ERG. 2005a. "Quality Assurance of the 2002 WRAP Stationary Sources Emissions Inventory," 

Draft, December 5, 2005. 

 

ERG. 2005b. "WRAP Point and Area Source Emissions Projections for the 2018 Base Case 

Inventory," Draft, December 21, 2005. 

ERG/ENVIRON. 2005. "Point and Area Source Emission Inventories on Native American 

Reservations and Tribal Lands". Prepared for the Western Regional Air Partnership. 

December. 

ERG/ENVIRON, 2005. "Point Source and Oil and Gas Area Source Emission Inventories on 

Native American Reservations and Tribal Lands." Prepared for the Western Regional Air 

Partnership. December 16, 2005. 

Gantner, 2005. Information on coalbed methane pump operation provided by Bruce Gantner of 

the New Mexico Oil and Gas Association. June 2005. 

MT BOGC, 2005. Well drilling and well production information provided by staff of the 

Montana Board of Oil and Gas Conservation (Jim Halvorson, jhalvorson@mt.gov). 

April 12, 2005. 

MT DEQ, 2005. Information on permitting and inventory efforts in the State of Montana 

provided by staff of the Montana Department of Environmental Quality (Dave Aguirre, 

daguirre@mt.gov). March 9, 2005. 

ND DH, 2005. Information on permitting and inventory efforts in the State of North Dakota 

provided by staff of the North Dakota Department of Health (Tom Bachman, 

tbachman@state.nd.ud). March 21, 2005. 

ND OGC, 2005. Well drilling and well production information provided by staff of the North 

Dakota Industrial Commission, Oil and Gas Division (Jim Lindholm, 

Jlindholm@state.nd.us). March 9, 2005. 

NM ED, 2005. Well drilling and well production information provided by staff of the New 

Mexico Environmental Department (Ken Lienemann, kenneth.lienemann@state.nm.us). 

March 25, 2005. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec5_References.doc 5-3 

NM ED, 2005b. Information on permitting and inventory efforts in New Mexico provided by 

staff of the New Mexico Environmental Department (Heather Lancour, 

heather_lancour@nmenv.state.nm.us). March 10, 2005. 

NMOGA, 2003. Inventory of Unpermitted Sources in the San Juan Basin. Prepared by The 

New Mexico Oil and Gas Association. 

NM OCD, 2004. “AllWells050424.zip”. Well database maintained by the New Mexico Energy, 

Minerals and Natural Resources Department, Oil Conservation Division. Internet 

address: ftp://164.64.103.5/public/ocd/Data/. 

NMT, 2005. GO-TECH. Online oil and gas production database for the State of New Mexico, 

maintained by New Mexico Institute of Mining and Technology. Internet address: 

http://octane.nmt.edu/data/ongard/general.asp. 

NONROAD, 2004. EPA’s NONROAD 2004 Emissions Model. Internet address: 

http://www.epa.gov/otaq/nonrdmdl.htm. 

NV DEP, 2005. Information on permitting and inventory efforts in the State of Nevada provided 

by staff of the Nevada Division of Environmental Protection (Lori Campbell, 

loric@ndep.nv.gov). March 9, 2005. 

NV DM, 2005. Well drilling and well production information provided by staff of the Nevada 

Division of Minerals (Linda Wells, lwells@govmail.state.nv.us). March 16, 2005. 

Olson, 2005. Information on coalbed methane pump efficiency provided by Joe Olson at 

Williams Exploration and Production. June 2005. 

OR DEQ, 2005. Information on permitting and inventory efforts in the State of Oregon provided 

by staff of the Oregon Department of Environmental Quality (Mark Fisher, 

fisher.mark@deq.state.or.us). March 23, 2005. 

OR DGMI, 2005. Well drilling and well production information provided by staff of the Oregon 

Department of Geology and Mineral Industries (Robert Houston, 

robert.a.houston@mlrr.oregongeology.com). 

Pollution Solutions, 2005. Tyler/Longview/Marshall Flexible Attainment Region Emission 

Inventory, Ozone Precursors, VOC, NOx and CO, 2002 Emissions. 

Richmond, 2005. Information on coalbed methane production in Montana provided by Tom 

Richmond of the Montana Board of Oil and Gas Conservation. February, 2005. 

SD DENR, 2005. Information on permitting and inventory efforts in the State of South Dakota 

provided by staff of the South Dakota Department of Environment and Natural Resources 

(Jason Knapp, Jason.Knapp@state.sd.us). March 11, 2005. 

SD MMP, 2005. Well drilling and well production information provided by staff of the South 

Dakota Department of Environment & Natural Resources, Minerals and Mining Program 

(Mack McGillivray, mack.mcgillivray@state.sd.us). March 23, 2005. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec5_References.doc 5-4 

Strong, 2005. Information on typical coalbed methane design provided by Gary Strong of the 

Wyoming Oil and Gas Conservation Commission. June 2005. 

UT DOGM, 2005. Well drilling and well production information provided by staff of the Utah 

Division of Oil, Gas and Mining (Vicky Dyson, vickydyson@utah.gov). March 16, 

2005. 

UT DEQ, 2005. Information on permitting and inventory efforts in the State of Utah provided 

by staff of the Utah Department of Environmental Quality (Tad Anderson, 

TDAnderson@utah.gov). May 9, 2005. 

Weatherford, 2005. Information on typical tubing installed in coalbed methane wells in 

Wyoming provided by a representative of Weatherford U.S., Gillette, Wyoming. June 

2005. 

Weatherford, 2005b. “Reciprocating Rod Lift Pumping Units”. Weatherford Artificial Lift 

Systems. Internet address: 

http://www.weatherford.com/weatherford/groups/public/documents/general/wft003549.p

df

WY OGCC, 2005. Well drilling and well production information provided by staff of the 

Wyoming Oil and Gas Conservation Commission (Robert Meyer, rmeyer2@state.wy.us). 

March 18, 2005. 

WY DEQ, 2005. Emissions factors for drilling in Southwest Wyoming provided by staff of the 

Wyoming Department of Environmental Quality (Chad Schlichtemeier, 

CSCHLI@state.wy.us). April 8, 2005. 

WY DEQ, 2005b. Information on natural gas fired generators associated with Coalbed Methane 

Production provided by staff of the Wyoming Department of Environmental Quality 

(Chad Schlichtemeier, CSCHLI@state.wy.us). March 22, 2005. 

WY DEQ, 2004. Information on diesel fired generators associated with coalbed methane 

production provided by staff of the Wyoming Department of Environmental Quality 

(Chad Schlichtemeier, CSCHLI@state.wy.us). November 10, 2004. 

WY DEQ, 2005c. Information on permitting and inventory efforts in the State of Wyoming 

provided by staff of the Wyoming Department of Environmental Quality (Chad 

Schlichtemeier, CSCHLI@state.wy.us). March 14, 2005. 

WY DEQ, 2004b. Wellhead emission factors provided by the Wyoming Department of 

Environmental Quality, Air Quality Division. Phone: (307)777-7345. Cheyenne, 

Wyoming. 

USDA FS, 2004. “Northern San Juan Basin CBM DEIS”. USDA Forest Service and USDI 

Bureau of Land Management. June. Salt Lake City, UT. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec5_References.doc 5-5 

WY BLM, 2005. Reasonable foreseeable development scenario for the upcoming Pinedale 

Resource management plan provided by staff of the Wyoming BLM (Kelly Rotterford; 

Pinedale Field Office; Wyoming Bureau of Land Management; 307-367-5300). August. 

WY BLM, 2001. “Reasonable Foreseeable Development Scenario for Oil and Gas Development 

in the Buffalo Field Office Area, Campbell, Johnson, and Sheridan Counties, Wyoming”. 

Wyoming State Office, Bureau of Land Management. February. Cheyenne, WY. 

CO BLM, 1996. “White River Resource Area; Proposed Resource Management Plan and Final 

Environmental Impact Statement”. Craig District, Colorado Bureau of Land 

Management. June. Craig, CO. 

NM BLM, 2003. “Proposed Resource Management Plan Amendment and Final Environmental 

Impact Statement for Federal Fluid Minerals Leasing and Development in Sierra and 

Otero Counties”. Las Cruces Field Office, New Mexico Bureau of Land Management. 

December. Las Cruces, NM. 

USDA FS, 2003. “Dakota Prairie Grasslands Oil and Gas Leasing Record of Decision”. R-1, 

Northern Region, USDA Forest Service and Montana State Office, USDI Bureau of Land 

Management. June. Bismarck, ND. 

NM BLM, 2003. “Farmington Proposed Resource Management Plan and Final Environmental 

Impact Statement”. Farmington Field Office, New Mexico Bureau of Land Management. 

March. Farmington, NM. 

WY BLM, 2004. “Final Environmental Impact Statement, Desolation Flats Natural Gas Field 

Development Project”. Wyoming State Office, Bureau of Land Management. May. 

Cheyenne, WY. 

UT BLM, 2005. “Draft Resource Management Plan and Environmental Impact Statement. 

Vernal Field Office, Utah Bureau of Land Management. January. Vernal, UT. 

WY BLM, 2004b. “Final Environmental Impact Statement for the Jack Morrow Hills 

Coordinated activity Plan/Proposed Green River Resource Management Plan 

Amendment”. Rock Springs Field Office, Wyoming Bureau of Land Management. 

Rock Springs, WY. 

BIA, 2004. “Final Environmental Impact Statement; Wind River Gas Field Development 

Project, Fremont County, Wyoming”. Wind River Agency, Bureau of Indian Affairs. 

Fort Washakie, WY. 

MT DEQ, 2003. “Statewide Oil and Gas Final Environmental Impact Statement and 

Amendment of the Powder River and Billings Resource Management Plans”. Montana 

Department of Environmental Quality and the Bureau of Land Management. January. 

Billings, MT. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxA_WYDEQ_EFs.doc A-1

Appendix A 

Wyoming Emission Factor Documentation 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxA_WYDEQ_EFs.doc A-2

Gas Wells – Completion Emissions from Flaring and Venting

Standardized statewide factors for VOC and HAP emissions associated with flaring and venting 

activities during gas well completions were created using a weighted average statewide produced 

gas composition. The averaged analysis indicates VOC and HAP weight percents of 9.43% and 

0.33%, respectively 

A typical well completion log indicated 5.0 MMCFD of gas are flared and/or vented during 10-

days of completion activities. This is the only well completion log available to the Division and 

is representative of gas well completions in the Pinedale, Wyoming area, where the majority of 

gas well completions during 2002 occurred. 

During well completions, fluids routed to the flares burn when the entrained liquid volumes are 

low enough. Sometimes the flares are burning basically pure gas, while other times the flares 

don’t or won’t ignite when liquid volumes are excessive. Since typical volumes of gas and 

liquid routed to a completion flare are not known, 50% of the time for each situation is assumed. 

During flaring of completion gas, different opacity levels have been observed, ranging from 0 to 

100%. This indicates completion fluids are not 100% combusted. Sometimes well flares smoke 

excessively and sometimes they burn clean, depending on the amount of liquids entrained in the 

flared vapors. To account for this, 50% destruction efficiency of flares for VOCs and HAPs are 

assumed. 

Emissions associated with gas venting are calculated as follows: 

(5 MMCF/day) × (18.4565 lb/lb-mol) × (lb-mol/379 scf) × (106

 scf/MMCF) × (ton/2000 lb) 

 = 121.7447 tons of total gas flared or vented per day per completion 

121.7447 tons of gas per day × 10 days = 1217.4472 tons of gas per completion 

1217.4472 total tons × 0.0943 wt% VOC = 114.8053 total tons VOC 

50% of 114.8053 tons VOC are vented = 57.4027 tons VOC vented per completion 

50% of 114.8053 tons VOC are flared w/ 50% destruction efficiency 

 = 28.7013 tons VOC from incomplete combustion per completion 

Total VOC from flaring/venting = 86.0 tons per well completion 

1217.4472 total tons × 0.0033 wt% HAP = 4.0176 total tons HAP 

50% of 4.0176 tons HAP are vented = 2.0088 tons HAP vented per completion 

50% of 4.0176 tons HAP are flared w/ 50% destruction efficiency 

 = 1.0044 tons HAP from incomplete combustion per completion 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxA_WYDEQ_EFs.doc A-3

Gas Wells – Completion Emissions from Flaring and Venting cont’d

Total HAP from flaring/venting = 3.0 tons per well completion 

0.6087 total tons Benzene @ 50% vented/50% flared = 0.5 tons Benzene per well/completion

1.0957 total tons Toluene @ 50% vented/50% flared = 0.7 tons Toluene per well/completion 

0.3652 total tons Xylene @ 50% vented/50% flared = 0.8 tons Xylene per well/completion

1.9479 total tons n-C6 @ 50% vented/50% flared = 1.3 tons n-C6 per well/completion

undetectable e-Benzene 

For NOX and CO emissions from flaring, AP-42 flare emission factors were used as follows: 

(5.0 MMCF/day) × (0.14 lb NOX/MMBtu) × (1000 Btu/SCF) × (106

 SCF/MMCF) × 

(MMBtu/106 Btu) × (ton/2000 lb) = 0.35 tons NOX per day. 

Using the same calculate with 0.035 lb CO/MMCF = 0.0875 tons CO per day 

Assuming gas wells are flared 50% of the time during 10 days of completion operations flaring 

emissions are: 

1.75 tons NOX & 0.44 tons CO per gas well completion 

VOC and HAP emissions from pneumatic devices at gas and oil well facilities

The average pneumatic pump uses and emits approximately 5.0 SCF/hr. These pumps are to 

inject methanol into flowlines and equipment at oil and gas well facilities. Most gas wells have 

two associated pneumatic injection pumps. Most oil wells have one associated pneumatic pump. 

Each type of well has various other pneumatic devices. 

VOC and HAP emission from pneumatic pumps are calculated using the statewide average 

weighted gas composition, 5.0 SCF/hr gas usage, two pumps per gas well and one pump per oil 

well, as follows: 

(5 SCF/hr) × (18.4565 lb/lb-mol) × (lb-mol/379 SCF) × (8760 hr/yr) (ton/2000 lb) 

 = 1.07 tons gas used per year per pump 

1.07 tons × 0.0943 wt% VOC = 0.1 tons VOC per year/pump 

1.07 tons × 0.0033 wt% HAP = 0.004 tons HAP per year/pump 

For each gas well pneumatic emissions are 0.2 tons VOC/yr/well and 0.008 tons 

HAP/yr/well 

For each oil well pneumatic emissions are 0.1 tons VOC/yr/well and 0.004 tons HAP/yr/well 

VOC and HAP emissions from other pneumatic devices at each oil and gas well are 

typically less than 1.0 TPY VOC and less than 0.1 TPY HAP. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxA_WYDEQ_EFs.doc A-4

Gas Wells – Flashing & Standing/Working/Breathing VOC Emissions 

Standardized statewide emission factors for storage tank emissions were created by calculating 

the average compositions of condensate for each formation for which analyses were available. 

These averages were used to formulate a weighted average for condensate composition across 

the state, based on production per formation. The weighted average was used with E&P Tanks 

modeling software to calculate emission factors in tons per year (TPY) per barrel per day (BPD) 

of condensate production. 

The calculations yielded emissions of 3,271.0 pounds per year (1.64 TPY) of VOCs per BPD and 

116.0 pounds per year (0.06 TPY) of HAPs per BPD uncontrolled. For wells that produce above 

18.3 BPD of condensate controls would be installed, since the VOC emission would be above 

the 30.0 TPY threshold used in 2002. The emission factors would then be 65.74 pounds per year 

(0.03 TPY) of VOCs per BPD and 2.32 pounds per year (0.001 TPY) of HAPs per BPD 

controlled with 98% efficiency. 

Uncontrolled Controlled

Benzene = 31.4 lb per yr/BPD Benzene = 0.63 lb per yr/BPD 

Toluene = 0.8 lb per yr/BPD Toluene = 0.02 lb per yr/BPD 

Ethyl benzene = 2.6 lb per yr/BPD Ethyl benzene = 0.05 lb per yr/BPD 

Xylenes = 1.8 lb per yr/BPD Xylenes = 0.04 lb per yr/BPD 

n-Hexane = 7.8 lb per yr/BPD n-Hexane = 0.16 lb per yr/BPD 

Gas Wells – Dehydration Unit VOC & HAP Emissions 

Standardized statewide emission factors for dehydration unit emissions were created by 

calculating the average compositions of wet gas for each formation for which analyses were 

available. These averages were used to formulate a weighted average for gas composition across 

the state, based on production per formation. The weighted average was then used with GRI 

GlyCalc modeling software to calculate emission factors based on one million standard cubic 

foot of gas per day (MSCFD) at 0.425 gpm or 25.0 spm for a Kimray 4015 glycol pump. 25.0 

spm is an observed average pump rate and the Kimray 4015 model is the most widely used. 

The calculations yielded emissions of 27,485.6 pounds per year (13.74 TPY) of VOCs per 106

cubic feet per day (MMCFD) and 13,695.6 pounds per year (6.85 TPY) of HAPs per MMCFD. 

Benzene = 3,019.0 lb per yr/MMCFD 

Toluene = 6,944.2 lb per yr/MMCFD 

Ethyl benzene = 288.8 lb per yr/MMCFD 

Xylenes = 3,054.8 lb per yr/MMCFD 

n-Hexane = 361.0 lb per yr/MMCFD 

Gas Wells – Heater Emissions 

For an average gas well site, approximately 2.0 MMBtu/hr are used in all of the different heaters 

and burners. The average heat content of the fuel used in these heaters is estimated at 1000 

Btu/scf. This activity results in 1,752.0 pounds per year (0.88 TPY) of NOx and 367.92 pounds 

per year (0.18 TPY) of CO for each gas well installation. These were calculated using AP-42 

emission factors for fuel boilers and heaters, 100 lb/mmcf for NOx and 21 lb/mmcf for CO. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxA_WYDEQ_EFs.doc A-5

Oil Wells – Flashing & Standing/Working/Breathing VOC Emissions 

Statewide standardized emission factors for storage tank emissions were formulated using the 

geographical database built into E&P Tanks emissions modeling software. The data gathered for 

sales oil with an API Gravity of 30.0 and Reid Vapor Pressure of 2.7 psia was selected as it most 

closely approximates the majority of Wyoming crude oil. The resulting factors in pounds of 

emissions per year per BPD oil production at individual wells: 

VOCs = 160.0 lb per yr/BPD 

HAPs = 2.66 lb per yr/BPD 

Benzene = 0.014 lb per yr/BPD 

Toluene = 0.018 lb per yr/BPD 

Ethyl Benzene = 0.004 lb per yr/BPD 

Xylenes = 0.034 lb per yr/BPD 

n-Hexane = 2.598 lb per yr/BPD

Oil Wells – Heater Emissions 

In Wyoming, most oil wells are produced to a central battery where various heated vessels are 

used for separation of crude and water. An average throughput of 2000 barrels per day at a 

facility using 4.0 MMBtu/hr total heat input was used along with AP-42 emission factors for fuel 

boilers and heaters to estimate 0.005 pounds per year of NOX per BPD and 0.001 pounds per yr 

of CO per BPD of oil production at each individual oil well [later corrected units to 0.005 pounds 

per year of NOx per barrel and 0.001 pounds per year of CO per barrel]. 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxB_SampleCalcs.doc B-1

Appendix B 

Sample Calculations for the VOC and Minor NOx Processes 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxB_SampleCalcs.doc B-2

Sample Calculation for Gas Well 

Well Name = 476 

Well Type = Gas 

Field Name = Five Mile 

County = Big Horn 

2002 Gas Production (GP) = 193,559 1000CF 

2002 Condensate Production (CP) = 2,968 barrels 

Completion Date = 6/25/2002 

Calculate approximate number of operational days per year 

 Number of days June - December = 214 well days per year (wdpy) 

Flashing & Standing/Working/Breathing Emissions 

Will there be controls on flashing & standing/working/breathing? 

 CP / wdpy <= 18.3 

 2,968 barrels / 214 wdpy <= 18.3 

 13.9 <= 18.3 therefore there will be no controls 

 VOC EF = 3,271 lbs/yr per BPD CP 

 Benzene EF = 31.4 lbs/yr per BPD CP 

 Annual VOC = CP / wdpy * VOC EF / 2000 lb/ton * wdpy / total dpy 

 Annual VOC = 2,968 barrels / 214 wdpy * 3,271 lbs/yr per BPD CP / 2000 lb/ton 

* 214 wdpy / 365 dpy 

 Annual VOC = 13.9 bpd * 3,271 lbs/yr per BPD CP / 2000 lb/ton * .586 

 Annual VOC = 13.3 tons 

 Annual Benzene = CP / wdpy * Benzene EF / 2000 lb/ton * wdpy / total dpy 

 Annual Benzene = 13.9 bpd * 31.4 lbs/yr per BPD CP / 2000 lb/ton * .586 

 Annual Benzene = .13 tons 

Dehydration Unit Emissions 

 VOC EF = 27,485.6 lbs per year / MCFD 

 Annual VOC = VOC EF * GP / 1000 MCF/1000CF / 214 wdpy / 2000 lb/ton * 

214 wdpy / 365 dpy 

 Annual VOC = 27,485.6 lbs per year / MCFD * 193.6MCF / 214 wdpy / 2000 

lb/ton * .586 

 Annual VOC = 7.3 tons 

Heater Emissions 

 NOx EF = 1,752 lbs / year - well 

 Annual NOx = NOX EF * Number of Wells / 2000 lb/ton * wdpy / dpy 

 Annual NOx = 1,752 lbs / year-well * 1 well / 2000 lb/ton * .586 

 Annual NOx = .51 tons 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxB_SampleCalcs.doc B-3

Pneumatic Devices 

 VOC EF = .2 tons / year-well 

 Annual VOC = VOC EF * Number of Wells * wdpy / dpy 

 Annual VOC = .2 tons / year-well * 1 well * .586 

 Annual VOC = .12 tons 

Completion Flaring and Venting 

 VOC EF = 86 tons / completion 

 Annual VOC = completions * VOC EF 

 Annual VOC = 1 completion * 86 tons / completion 

 Annual VOC = 86 tons 

These sample calculations only present the calculation for one pollutant for each process. 

The calculations for other pollutants within the same process were identical, with the 

exception of the emission factor. 

Sample Calculation for Oil Well 

Well Name = 483 

Well Type = Oil 

Field Name = Torchlight 

County = Big Horn 

2002 Oil Production (OP) = 8,758 barrels 

Completion Date = 2/4/2002 

Calculate approximate number of operational days per year 

 Number of days February - December = 334 well days per year (wdpy) 

Flashing & Standing/Working/Breathing Emissions 

 VOC EF = 160 lb/year per BPD OP 

 Annual VOC = VOC EF * OP / wdpy / 2000 lb/ton * wdpy / dpy 

 Annual VOC = 160 lb/year per BPD OP * 8,758 barrels / 334 wdpy / 2000 lb/ton 

* 334 wdpy / 365 dpy 

 Annual VOC = 160 lb/year per BPD OP * 26.2 BPD / 2000 lb/ton * .915 

 Annual VOC = 1.92 tons 

Heater 

 NOx EF = 0.005 lb/yr per BPD OP 

 Annual NOx = NOx EF * OP / wdpy / 2000 lb/ton * wdpy / dpy 

 Annual NOx = 0.005 lb/yr per BPD OP * 26.2 BPD / 2000 lb/ton * .915 

 Annual NOx = 0.00006 tons 

Pneumatic Devices 

 VOC EF = 0.10 tons/yr per well 

 Annual VOC = VOC EF * Number of Wells * wdpy / dpy 

 Annual VOC = 0.10 tons/yr per well * 1 well * .915 

 Annual VOC = 0.092 tons 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxC_nonroad_diesel_S.doc C-1

Appendix C 

Nonroad Diesel Fuel Sulfur Levels 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxC_nonroad_diesel_S.doc C-2

County FIPs 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel Sulfur 

(%) 

02013 0.075 08071 0.050 30013 0.240 

02016 0.075 08073 0.050 30015 0.240 

02020 0.119 08075 0.050 30017 0.240 

02050 0.075 08077 0.050 30019 0.240 

02060 0.075 08079 0.050 30021 0.240 

02068 0.075 08081 0.050 30023 0.240 

02070 0.075 08083 0.050 30025 0.240 

02090 0.119 08085 0.050 30027 0.240 

02100 0.035 08087 0.050 30029 0.240 

02110 0.035 08089 0.050 30031 0.240 

02122 0.119 08091 0.050 30033 0.240 

02130 0.035 08093 0.050 30035 0.240 

02150 0.075 08095 0.050 30037 0.240 

02164 0.075 08097 0.050 30039 0.240 

02170 0.119 08099 0.050 30041 0.240 

02180 0.075 08101 0.050 30043 0.240 

02185 0.075 08103 0.050 30045 0.240 

02188 0.075 08105 0.050 30047 0.240 

02201 0.035 08107 0.050 30049 0.240 

02220 0.035 08109 0.050 30051 0.240 

02232 0.035 08111 0.050 30053 0.240 

02240 0.119 08113 0.050 30055 0.240 

02261 0.119 08115 0.050 30057 0.240 

02270 0.075 08117 0.050 30059 0.240 

02280 0.035 08119 0.050 30061 0.240 

02282 0.075 08121 0.050 30063 0.240 

02290 0.075 08123 0.050 30065 0.240 

04001 0.240 08125 0.050 30067 0.240 

04003 0.240 16001 0.330 30069 0.240 

04005 0.340 16003 0.330 30071 0.240 

04007 0.340 16005 0.330 30073 0.240 

04009 0.240 16007 0.330 30075 0.240 

04011 0.240 16009 0.330 30077 0.240 

04012 0.340 16011 0.330 30079 0.240 

04013 0.036 16013 0.330 30081 0.240 

04015 0.340 16015 0.330 30083 0.240 

04017 0.240 16017 0.330 30085 0.240 

04019 0.340 16019 0.330 30087 0.240 

04021 0.340 16021 0.330 30089 0.240 

04023 0.240 16023 0.330 30091 0.240 

04025 0.340 16025 0.330 30093 0.240 

04027 0.340 16027 0.330 30095 0.240 

08001 0.050 16029 0.330 30097 0.240 

08003 0.050 16031 0.330 30099 0.240 

08005 0.050 16033 0.330 30101 0.240 

08007 0.050 16035 0.330 30103 0.240 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxC_nonroad_diesel_S.doc C-3

County FIPs 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel Sulfur 

(%) 

08009 0.050 16037 0.330 30105 0.240 

08011 0.050 16039 0.330 30107 0.240 

08013 0.050 16041 0.330 30109 0.240 

08014 0.050 16043 0.330 30111 0.240 

08015 0.050 16045 0.330 30113 0.240 

08017 0.050 16047 0.330 32001 0.050 

08019 0.050 16049 0.330 32003 0.025 

08021 0.050 16051 0.330 32005 0.050 

08023 0.050 16053 0.330 32007 0.050 

08025 0.050 16055 0.330 32009 0.050 

08027 0.050 16057 0.330 32011 0.050 

08029 0.050 16059 0.330 32013 0.050 

08031 0.050 16061 0.330 32015 0.050 

08033 0.050 16063 0.330 32017 0.025 

08035 0.050 16065 0.330 32019 0.050 

08037 0.050 16067 0.330 32021 0.050 

08039 0.050 16069 0.330 32023 0.025 

08041 0.050 16071 0.330 32027 0.050 

08043 0.050 16073 0.330 32029 0.050 

08045 0.050 16075 0.330 32031 0.050 

08047 0.050 16077 0.330 32033 0.050 

08049 0.050 16079 0.330 32510 0.050 

08051 0.050 16081 0.330 35001 0.240 

08053 0.050 16083 0.330 35003 0.240 

08055 0.050 16085 0.330 35005 0.240 

08057 0.050 16087 0.330 35006 0.240 

08059 0.050 30001 0.240 35007 0.240 

08061 0.050 30003 0.240 35009 0.240 

08063 0.050 30005 0.240 35011 0.240 

08065 0.050 30007 0.240 35013 0.240 

08067 0.050 30009 0.240 35015 0.240 

08069 0.050 30011 0.240 35017 0.240 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxC_nonroad_diesel_S.doc C-4

County FIPs 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel Sulfur 

(%) 

35019 0.240 41007 0.340 46095 0.371 

35021 0.240 41009 0.340 46097 0.371 

35023 0.240 41011 0.340 46099 0.371 

35025 0.240 41013 0.340 46101 0.371 

35027 0.240 41015 0.340 46103 0.240 

35028 0.240 41017 0.340 46105 0.240 

35029 0.240 41019 0.340 46107 0.371 

35031 0.240 41021 0.340 46109 0.371 

35033 0.240 41023 0.340 46111 0.371 

35035 0.240 41025 0.340 46113 0.240 

35037 0.240 41027 0.340 46115 0.371 

35039 0.240 41029 0.340 46117 0.371 

35041 0.240 41031 0.340 46119 0.371 

35043 0.240 41033 0.340 46121 0.371 

35045 0.240 41035 0.340 46123 0.371 

35047 0.240 41037 0.340 46125 0.371 

35049 0.240 41039 0.340 46127 0.371 

35051 0.240 41041 0.340 46129 0.371 

35053 0.240 41043 0.340 46135 0.371 

35055 0.240 41045 0.340 46137 0.371 

35057 0.240 41047 0.340 49001 0.340 

35059 0.240 41049 0.340 49003 0.240 

35061 0.240 41051 0.340 49005 0.240 

38001 0.240 41053 0.340 49007 0.240 

38003 0.371 41055 0.340 49009 0.240 

38005 0.371 41057 0.340 49011 0.240 

38007 0.240 41059 0.340 49013 0.240 

38009 0.371 41061 0.340 49015 0.240 

38011 0.240 41063 0.340 49017 0.340 

38013 0.240 41065 0.340 49019 0.240 

38015 0.371 41067 0.340 49021 0.340 

38017 0.371 41069 0.340 49023 0.240 

38019 0.371 41071 0.340 49025 0.340 

38021 0.371 46003 0.371 49027 0.240 

38023 0.240 46005 0.371 49029 0.240 

38025 0.240 46007 0.371 49031 0.340 

38027 0.371 46009 0.371 49033 0.240 

38029 0.371 46011 0.371 49035 0.240 

38031 0.371 46013 0.371 49037 0.240 

38033 0.240 46015 0.371 49039 0.240 

38035 0.371 46017 0.371 49041 0.240 

38037 0.371 46019 0.240 49043 0.240 

38039 0.371 46021 0.371 49045 0.240 

38041 0.240 46023 0.371 49047 0.240 

38043 0.371 46025 0.371 49049 0.240 

38045 0.371 46027 0.371 49051 0.240 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxC_nonroad_diesel_S.doc C-5

County FIPs 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel 

Sulfur (%) 

County FIPs 

(cont.) 

Fuel Diesel Sulfur 

(%) 

38047 0.371 46029 0.371 49053 0.340 

38049 0.371 46031 0.371 49055 0.240 

38051 0.371 46033 0.240 49057 0.240 

38053 0.240 46035 0.371 53001 0.340 

38055 0.371 46037 0.371 53003 0.340 

38057 0.371 46039 0.371 53005 0.340 

38059 0.371 46041 0.371 53007 0.340 

38061 0.240 46043 0.371 53009 0.340 

38063 0.371 46045 0.371 53011 0.340 

38065 0.371 46047 0.240 53013 0.340 

38067 0.371 46049 0.371 53015 0.340 

38069 0.371 46051 0.371 53017 0.340 

38071 0.371 46053 0.371 53019 0.340 

38073 0.371 46055 0.371 53021 0.340 

38075 0.371 46057 0.371 53023 0.340 

38077 0.371 46059 0.371 53025 0.340 

38079 0.371 46061 0.371 53027 0.340 

38081 0.371 46063 0.240 53029 0.340 

38083 0.371 46065 0.371 53031 0.340 

38085 0.371 46067 0.371 53033 0.340 

38087 0.240 46069 0.371 53035 0.340 

38089 0.240 46071 0.371 53037 0.340 

38091 0.371 46073 0.371 53039 0.340 

38093 0.371 46075 0.371 53041 0.340 

38095 0.371 46077 0.371 53043 0.340 

38097 0.371 46079 0.371 53045 0.340 

38099 0.371 46081 0.240 53047 0.340 

38101 0.371 46083 0.371 53049 0.340 

38103 0.371 46085 0.371 53051 0.340 

38105 0.240 46087 0.371 53053 0.340 

41001 0.340 46089 0.371 53055 0.340 

41003 0.340 46091 0.371 53057 0.340 

41005 0.340 46093 0.240 53059 0.340 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxC_nonroad_diesel_S.doc C-6

County FIPs 

Fuel Diesel Sulfur 

(%) 

53061 0.340 

53063 0.340 

53065 0.340 

53067 0.340 

53069 0.340 

53071 0.340 

53073 0.340 

53075 0.340 

53077 0.340 

56001 0.270 

56003 0.270 

56005 0.270 

56007 0.270 

56009 0.270 

56011 0.270 

56013 0.270 

56015 0.270 

56017 0.270 

56019 0.270 

56021 0.270 

56023 0.270 

56025 0.270 

56027 0.270 

56029 0.270 

56031 0.270 

56033 0.270 

56035 0.270 

56037 0.270 

56039 0.270 

56041 0.270 

56043 0.270 

56045 0.270 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-1

Appendix D 

2002 to 2018 Oil and Gas Growth Factors 
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-2

SCC FIPS 

Growth 

Factor 

2310000220 00000 4.4368 

2310000220 02020 0.0000 

2310000220 02122 1.0000 

2310000220 02185 1.0000 

2310000220 08001 1.0710 

2310000220 08007 1.0580 

2310000220 08009 1.0710 

2310000220 08014 1.0710 

2310000220 08017 1.0710 

2310000220 08045 1.0614 

2310000220 08051 1.0710 

2310000220 08055 1.0710 

2310000220 08057 1.0710 

2310000220 08061 1.0710 

2310000220 08067 1.1138 

2310000220 08071 1.0710 

2310000220 08073 1.0710 

2310000220 08075 1.0710 

2310000220 08077 1.0710 

2310000220 08081 1.0582 

2310000220 08083 1.0710 

2310000220 08087 1.0710 

2310000220 08099 1.0710 

2310000220 08103 1.5108 

2310000220 08107 1.0710 

2310000220 08113 1.0710 

2310000220 08121 1.0710 

2310000220 08123 1.0710 

2310000220 08125 1.0710 

2310000220 30003 39.4556 

2310000220 30005 0.1202 

2310000220 30009 129.8828 

2310000220 30011 1.0710 

2310000220 30015 1.0710 

2310000220 30017 8.2123 

2310000220 30019 1.0710 

2310000220 30021 1.0710 

2310000220 30025 1.0710 

2310000220 30027 1.0710 

2310000220 30035 1.0710 

2310000220 30041 1.0710 

2310000220 30045 1.0710 

SCC FIPS 

Growth 

Factor

2310000220 30051 1.0710

2310000220 30055 1.0710

2310000220 30065 85.3516

2310000220 30069 1.0710

2310000220 30071 1.0710

2310000220 30073 1.0710

2310000220 30075 76.3745

2310000220 30079 1.0710

2310000220 30083 1.0710

2310000220 30085 1.0710

2310000220 30087 1.0710

2310000220 30091 1.0710

2310000220 30095 12.3698

2310000220 30097 2.4740

2310000220 30101 1.0710

2310000220 30105 1.0710

2310000220 30111 34.6354

2310000220 32007 1.0710

2310000220 32011 1.0710

2310000220 32023 1.0710

2310000220 35005 1.0710

2310000220 35007 1.0710

2310000220 35015 1.0710

2310000220 35025 1.0710

2310000220 35039 2.6956

2310000220 35041 1.0710

2310000220 35045 2.6596

2310000220 35059 1.0710

2310000220 38007 2.8811

2310000220 38009 1.0710

2310000220 38011 1.0710

2310000220 38013 1.0710

2310000220 38023 1.0710

2310000220 38025 1.0889

2310000220 38033 0.9604

2310000220 38035 1.0710

2310000220 38049 1.0710

2310000220 38053 2.1276

2310000220 38059 1.0710

2310000220 38075 1.0710

2310000220 38087 0.1172

2310000220 38089 1.0710

2310000220 38093 1.0710

2310000220 38103 1.0710

2310000220 38105 1.0710

SCC FIPS 

Growth 

Factor

2310000220 46047 1.0710

2310000220 46063 1.0710

2310000220 49007 1.0710

2310000220 49013 5.1715

2310000220 49015 1.0710

2310000220 49019 1.0710

2310000220 49037 1.0710

2310000220 49047 8.7089

2310000220 56001 1.0710

2310000220 56003 1.0710

2310000220 56005 2.2528

2310000220 56007 1.1995

2310000220 56009 24.1974

2310000220 56011 1.0710

2310000220 56013 1.0710

2310000220 56017 1.0710

2310000220 56019 0.7792

2310000220 56023 1.3425

2310000220 56025 1.0710

2310000220 56027 1.0710

2310000220 56029 1.0710

2310000220 56033 1.5976

2310000220 56035 3.8028

2310000220 56037 1.1577

2310000220 56041 1.0710

2310010100 00000 1.2753

2310010100 08001 1.3340

2310010100 08005 1.3340

2310010100 08007 1.0022

2310010100 08009 1.3340

2310010100 08013 1.3340

2310010100 08017 1.3340

2310010100 08033 1.3340

2310010100 08039 1.3340

2310010100 08043 1.3340

2310010100 08045 1.3300

2310010100 08057 1.3340

2310010100 08061 1.3340

2310010100 08063 1.3340

2310010100 08067 1.3307

2310010100 08069 1.3340

2310010100 08073 1.3340

2310010100 08075 1.3340

2310010100 08077 1.3340

2310010100 08081 1.3253
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-3

SCC FIPS 

Growth 

Factor 

2310010100 08083 1.3340 

2310010100 08087 1.3340 

2310010100 08099 1.3340 

2310010100 08103 0.9979 

2310010100 08107 1.3340 

2310010100 08113 1.3340 

2310010100 08115 1.3340 

2310010100 08121 1.3340 

2310010100 08123 1.3340 

2310010100 30003 0.9649 

2310010100 30005 0.9899 

2310010100 30009 0.9746 

2310010100 30019 1.3340 

2310010100 30021 1.3340 

2310010100 30025 1.3340 

2310010100 30033 1.3340 

2310010100 30035 1.3340 

2310010100 30041 1.3340 

2310010100 30051 1.3340 

2310010100 30055 1.3340 

2310010100 30065 0.9227 

2310010100 30069 1.3340 

2310010100 30073 1.3340 

2310010100 30075 1.0000 

2310010100 30079 1.3340 

2310010100 30083 1.3340 

2310010100 30085 1.3340 

2310010100 30087 1.3340 

2310010100 30091 1.3340 

2310010100 30095 0.8333 

2310010100 30099 1.3340 

2310010100 30101 1.3340 

2310010100 30105 1.3340 

2310010100 30109 1.3340 

2310010100 30111 1.0000 

2310010100 32011 1.3340 

2310010100 32023 1.3340 

2310010100 35005 0.8660 

2310010100 35015 0.8660 

2310010100 35025 0.8660 

2310010100 35031 0.9953 

2310010100 35039 1.2786 

2310010100 35041 0.8660 

2310010100 35043 1.0263 

2310010100 35045 1.7402 

SCC FIPS 

Growth 

Factor

2310010100 38007 1.0336

2310010100 38009 1.3340

2310010100 38011 1.3340

2310010100 38013 1.3340

2310010100 38023 1.3340

2310010100 38025 1.3268

2310010100 38033 1.1452

2310010100 38041 1.3340

2310010100 38049 1.3340

2310010100 38053 1.1667

2310010100 38055 1.3340

2310010100 38061 1.3340

2310010100 38075 1.3340

2310010100 38087 0.9789

2310010100 38089 1.3340

2310010100 38101 1.3340

2310010100 38105 1.3340

2310010100 46041 1.3340

2310010100 46047 1.3340

2310010100 46063 1.3340

2310010100 49013 1.6365

2310010100 49015 1.3340

2310010100 49017 1.3340

2310010100 49019 1.3340

2310010100 49037 1.3340

2310010100 49043 1.3340

2310010100 49047 3.8530

2310010100 56001 1.3340

2310010100 56003 1.3340

2310010100 56005 0.9965

2310010100 56007 1.2974

2310010100 56009 1.0727

2310010100 56011 1.3340

2310010100 56013 1.3340

2310010100 56017 1.3340

2310010100 56019 0.9771

2310010100 56021 1.3340

2310010100 56023 1.3285

2310010100 56025 1.3340

2310010100 56027 1.3340

2310010100 56029 1.3340

2310010100 56033 0.9994

2310010100 56035 0.9955

2310010100 56037 1.3158

2310010100 56041 1.3340

SCC FIPS 

Growth 

Factor

2310010100 56043 1.3340

2310010100 56045 1.3340

2310010200 00000 1.2753

2310010200 08001 1.3340

2310010200 08005 1.3340

2310010200 08007 1.0022

2310010200 08009 1.3340

2310010200 08013 1.3340

2310010200 08017 1.3340

2310010200 08033 1.3340

2310010200 08039 1.3340

2310010200 08043 1.3340

2310010200 08045 1.3300

2310010200 08057 1.3340

2310010200 08061 1.3340

2310010200 08063 1.3340

2310010200 08067 1.3307

2310010200 08069 1.3340

2310010200 08073 1.3340

2310010200 08075 1.3340

2310010200 08077 1.3340

2310010200 08081 1.3253

2310010200 08083 1.3340

2310010200 08087 1.3340

2310010200 08099 1.3340

2310010200 08103 0.9979

2310010200 08107 1.3340

2310010200 08113 1.3340

2310010200 08115 1.3340

2310010200 08121 1.3340

2310010200 08123 1.3340

2310010200 30003 0.9649

2310010200 30005 0.9899

2310010200 30009 0.9746

2310010200 30019 1.3340

2310010200 30021 1.3340

2310010200 30025 1.3340

2310010200 30033 1.3340

2310010200 30035 1.3340

2310010200 30041 1.3340

2310010200 30051 1.3340

2310010200 30055 1.3340

2310010200 30065 0.9227

2310010200 30069 1.3340

2310010200 30073 1.3340
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-4

SCC FIPS 

Growth 

Factor 

2310010200 30075 1.0000 

2310010200 30079 1.3340 

2310010200 30083 1.3340 

2310010200 30085 1.3340 

2310010200 30087 1.3340 

2310010200 30091 1.3340 

2310010200 30095 0.8333 

2310010200 30099 1.3340 

2310010200 30101 1.3340 

2310010200 30105 1.3340 

2310010200 30109 1.3340 

2310010200 30111 1.0000 

2310010200 32011 1.3340 

2310010200 32023 1.3340 

2310010200 35005 0.8660 

2310010200 35015 0.8660 

2310010200 35025 0.8660 

2310010200 35031 0.9953 

2310010200 35039 1.2786 

2310010200 35041 0.8660 

2310010200 35043 1.0263 

2310010200 35045 1.7402 

2310010200 38007 1.0336 

2310010200 38009 1.3340 

2310010200 38011 1.3340 

2310010200 38013 1.3340 

2310010200 38023 1.3340 

2310010200 38025 1.3268 

2310010200 38033 1.1452 

2310010200 38041 1.3340 

2310010200 38049 1.3340 

2310010200 38053 1.1667 

2310010200 38055 1.3340 

2310010200 38061 1.3340 

2310010200 38075 1.3340 

2310010200 38087 0.9789 

2310010200 38089 1.3340 

2310010200 38101 1.3340 

2310010200 38105 1.3340 

2310010200 46041 1.3340 

2310010200 46047 1.3340 

2310010200 46063 1.3340 

2310010200 49013 1.6365 

2310010200 49015 1.3340 

2310010200 49017 1.3340 

SCC FIPS 

Growth 

Factor

2310010200 49019 1.3340

2310010200 49037 1.3340

2310010200 49043 1.3340

2310010200 49047 3.8530

2310010200 56001 1.3340

2310010200 56003 1.3340

2310010200 56005 0.9965

2310010200 56007 1.2974

2310010200 56009 1.0727

2310010200 56011 1.3340

2310010200 56013 1.3340

2310010200 56017 1.3340

2310010200 56019 0.9771

2310010200 56021 1.3340

2310010200 56023 1.3285

2310010200 56025 1.3340

2310010200 56027 1.3340

2310010200 56029 1.3340

2310010200 56033 0.9994

2310010200 56035 0.9955

2310010200 56037 1.3158

2310010200 56041 1.3340

2310010200 56043 1.3340

2310010200 56045 1.3340

2310010300 00000 1.2753

2310010300 08001 1.3340

2310010300 08005 1.3340

2310010300 08007 1.0022

2310010300 08009 1.3340

2310010300 08013 1.3340

2310010300 08017 1.3340

2310010300 08033 1.3340

2310010300 08039 1.3340

2310010300 08043 1.3340

2310010300 08045 1.3300

2310010300 08057 1.3340

2310010300 08061 1.3340

2310010300 08063 1.3340

2310010300 08067 1.3307

2310010300 08069 1.3340

2310010300 08073 1.3340

2310010300 08075 1.3340

2310010300 08077 1.3340

2310010300 08081 1.3253

2310010300 08083 1.3340

SCC FIPS 

Growth 

Factor

2310010300 08087 1.3340

2310010300 08099 1.3340

2310010300 08103 0.9979

2310010300 08107 1.3340

2310010300 08113 1.3340

2310010300 08115 1.3340

2310010300 08121 1.3340

2310010300 08123 1.3340

2310010300 30003 0.9649

2310010300 30005 0.9899

2310010300 30009 0.9746

2310010300 30019 1.3340

2310010300 30021 1.3340

2310010300 30025 1.3340

2310010300 30033 1.3340

2310010300 30035 1.3340

2310010300 30041 1.3340

2310010300 30051 1.3340

2310010300 30055 1.3340

2310010300 30065 0.9227

2310010300 30069 1.3340

2310010300 30073 1.3340

2310010300 30075 1.0000

2310010300 30079 1.3340

2310010300 30083 1.3340

2310010300 30085 1.3340

2310010300 30087 1.3340

2310010300 30091 1.3340

2310010300 30095 0.8333

2310010300 30099 1.3340

2310010300 30101 1.3340

2310010300 30105 1.3340

2310010300 30109 1.3340

2310010300 30111 1.0000

2310010300 32011 1.3340

2310010300 32023 1.3340

2310010300 35005 0.8660

2310010300 35015 0.8660

2310010300 35025 0.8660

2310010300 35031 0.9953

2310010300 35039 1.2786

2310010300 35041 0.8660

2310010300 35043 1.0263

2310010300 35045 1.7402

2310010300 38007 1.0336
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-5

SCC FIPS 

Growth 

Factor 

2310010300 38009 1.3340 

2310010300 38011 1.3340 

2310010300 38013 1.3340 

2310010300 38023 1.3340 

2310010300 38025 1.3268 

2310010300 38033 1.1452 

2310010300 38041 1.3340 

2310010300 38049 1.3340 

2310010300 38053 1.1667 

2310010300 38055 1.3340 

2310010300 38061 1.3340 

2310010300 38075 1.3340 

2310010300 38087 0.9789 

2310010300 38089 1.3340 

2310010300 38101 1.3340 

2310010300 38105 1.3340 

2310010300 46041 1.3340 

2310010300 46047 1.3340 

2310010300 46063 1.3340 

2310010300 49013 1.6365 

2310010300 49015 1.3340 

2310010300 49017 1.3340 

2310010300 49019 1.3340 

2310010300 49037 1.3340 

2310010300 49043 1.3340 

2310010300 49047 3.8530 

2310010300 56001 1.3340 

2310010300 56003 1.3340 

2310010300 56005 0.9965 

2310010300 56007 1.2974 

2310010300 56009 1.0727 

2310010300 56011 1.3340 

2310010300 56013 1.3340 

2310010300 56017 1.3340 

2310010300 56019 0.9771 

2310010300 56021 1.3340 

2310010300 56023 1.3285 

2310010300 56025 1.3340 

2310010300 56027 1.3340 

2310010300 56029 1.3340 

2310010300 56033 0.9994 

2310010300 56035 0.9955 

2310010300 56037 1.3158 

2310010300 56041 1.3340 

2310010300 56043 1.3340 

SCC FIPS 

Growth 

Factor

2310010300 56045 1.3340

2310020600 00000 2.1729

2310020600 30003 

2310020600 30005 1.2437

2310020600 30009 2.8663

2310020600 30015 1.4580

2310020600 30017 12.9403

2310020600 30019 1.4580

2310020600 30021 1.4580

2310020600 30025 1.4580

2310020600 30027 1.4580

2310020600 30033 1.4580

2310020600 30035 1.4580

2310020600 30037 1.9294

2310020600 30041 1.4580

2310020600 30051 1.4580

2310020600 30065 0.9227

2310020600 30069 1.4580

2310020600 30071 1.4580

2310020600 30073 1.4580

2310020600 30075 311.8023

2310020600 30079 1.4580

2310020600 30083 1.4580

2310020600 30085 1.4580

2310020600 30087 1.4580

2310020600 30091 1.4580

2310020600 30095 1.8116

2310020600 30097 1.7071

2310020600 30099 1.4580

2310020600 30101 1.4580

2310020600 30105 1.4580

2310020600 30109 1.4580

2310020600 32003 1.4580

2310020600 32023 1.4580

2310020600 35001 1.4580

2310020600 35005 1.3540

2310020600 35007 1.3540

2310020600 35015 1.3540

2310020600 35021 1.3540

2310020600 35025 1.3540

2310020600 35031 36.4321

2310020600 35039 2.9281

2310020600 35041 1.3540

2310020600 35043 1.2953

2310020600 35045 3.6832

SCC FIPS 

Growth 

Factor

2310020600 35059 1.3540

2310020600 38003 1.4580

2310020600 38007 1.0525

2310020600 38009 1.4580

2310020600 38011 1.4580

2310020600 38013 1.4580

2310020600 38015 1.4580

2310020600 38023 1.4580

2310020600 38025 1.4483

2310020600 38033 1.2043

2310020600 38049 1.4580

2310020600 38053 3.1848

2310020600 38055 1.4580

2310020600 38059 1.4580

2310020600 38061 1.4580

2310020600 38075 1.4580

2310020600 38077 1.4580

2310020600 38087 0.9789

2310020600 38089 1.4580

2310020600 38093 1.4580

2310020600 38101 1.4580

2310020600 38105 1.4580

2310020600 41009 0.5680

2310020600 41019 0.5680

2310020600 41041 0.5680

2310020600 41043 0.5680

2310020600 41047 0.5680

2310020600 46033 1.4580

2310020600 46041 1.4580

2310020600 46047 1.4580

2310020600 46063 1.4580

2310020600 49007 1.4580

2310020600 49009 2.1185

2310020600 49013 3.7360

2310020600 49015 1.4580

2310020600 49017 1.4580

2310020600 49019 1.4580

2310020600 49037 1.4580

2310020600 49043 1.4580

2310020600 49047 2.6255

2310020600 56001 1.4580

2310020600 56003 1.4580

2310020600 56005 7.1804

2310020600 56007 1.6387

2310020600 56009 1.1066
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-6

SCC FIPS 

Growth 

Factor 

2310020600 56011 1.4580 

2310020600 56013 1.4580 

2310020600 56017 1.4580 

2310020600 56019 6.9460 

2310020600 56021 1.4580 

2310020600 56023 1.5406 

2310020600 56025 1.4580 

2310020600 56027 1.4580 

2310020600 56029 1.4580 

2310020600 56033 7.6748 

2310020600 56035 7.4527 

2310020600 56037 1.5236 

2310020600 56041 1.4580 

2310020600 56043 1.4580 

2310020600 56045 1.4580 

2310021100 00000 2.3099 

2310021100 08001 1.4580 

2310021100 08005 1.4580 

2310021100 08007 1.0177 

2310021100 08009 1.4580 

2310021100 08011 1.4580 

2310021100 08013 1.4580 

2310021100 08014 1.4580 

2310021100 08017 1.4580 

2310021100 08029 1.4580 

2310021100 08031 1.4580 

2310021100 08033 1.4580 

2310021100 08039 1.4580 

2310021100 08045 1.4595 

2310021100 08051 1.4580 

2310021100 08055 1.4580 

2310021100 08057 1.4580 

2310021100 08061 1.4580 

2310021100 08063 1.4580 

2310021100 08067 1.4535 

2310021100 08069 1.4580 

2310021100 08071 1.4580 

2310021100 08073 1.4580 

2310021100 08075 1.4580 

2310021100 08077 1.4580 

2310021100 08081 1.4638 

2310021100 08083 1.4580 

2310021100 08087 1.4580 

2310021100 08095 1.4580 

2310021100 08099 1.4580 

SCC FIPS 

Growth 

Factor

2310021100 08103 1.6764

2310021100 08107 1.4580

2310021100 08113 1.4580

2310021100 08121 1.4580

2310021100 08123 1.4580

2310021100 08125 1.4580

2310021100 30005 1.2437

2310021100 30009 3.6853

2310021100 30015 1.4580

2310021100 30017 12.9403

2310021100 30025 1.4580

2310021100 30027 1.4580

2310021100 30035 1.4580

2310021100 30037 1.9294

2310021100 30041 1.4580

2310021100 30051 1.4580

2310021100 30071 1.4580

2310021100 30073 1.4580

2310021100 30075 371.1493

2310021100 30079 1.4580

2310021100 30083 1.4580

2310021100 30085 1.4580

2310021100 30091 1.4580

2310021100 30095 1.8116

2310021100 30097 1.7071

2310021100 30099 1.4580

2310021100 30101 1.4580

2310021100 30105 1.4580

2310021100 30109 1.4580

2310021100 32023 1.4580

2310021100 35001 1.4580

2310021100 35005 1.3540

2310021100 35007 1.3540

2310021100 35015 1.3540

2310021100 35021 1.3540

2310021100 35025 1.3540

2310021100 35031 36.4321

2310021100 35039 2.9921

2310021100 35041 1.3540

2310021100 35043 1.4274

2310021100 35045 3.7217

2310021100 35059 1.3540

2310021100 38011 1.4580

2310021100 38013 1.4580

2310021100 38053 5.9557

SCC FIPS 

Growth 

Factor

2310021100 38105 1.4580

2310021100 41009 0.5680

2310021100 46063 1.4580

2310021100 49007 1.4580

2310021100 49009 2.1185

2310021100 49013 116.0424

2310021100 49015 1.4580

2310021100 49019 1.4580

2310021100 49037 1.4580

2310021100 49043 1.4580

2310021100 49047 2.5806

2310021100 56001 1.4580

2310021100 56003 1.4580

2310021100 56005 0.9965

2310021100 56007 1.6616

2310021100 56009 1.1075

2310021100 56011 1.4580

2310021100 56013 1.4580

2310021100 56017 1.4580

2310021100 56019 0.9771

2310021100 56023 1.5411

2310021100 56025 1.4580

2310021100 56027 1.4580

2310021100 56029 1.4580

2310021100 56035 7.4972

2310021100 56037 1.5467

2310021100 56041 1.4580

2310021100 56043 1.4580

2310021100 56045 1.4580

2310021300 00000 2.3099

2310021300 08001 1.4580

2310021300 08005 1.4580

2310021300 08007 1.0177

2310021300 08009 1.4580

2310021300 08011 1.4580

2310021300 08013 1.4580

2310021300 08014 1.4580

2310021300 08017 1.4580

2310021300 08029 1.4580

2310021300 08031 1.4580

2310021300 08033 1.4580

2310021300 08039 1.4580

2310021300 08045 1.4595

2310021300 08051 1.4580

2310021300 08055 1.4580
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-7

SCC FIPS 

Growth 

Factor 

2310021300 08057 1.4580 

2310021300 08061 1.4580 

2310021300 08063 1.4580 

2310021300 08067 1.4535 

2310021300 08069 1.4580 

2310021300 08071 1.4580 

2310021300 08073 1.4580 

2310021300 08075 1.4580 

2310021300 08077 1.4580 

2310021300 08081 1.4638 

2310021300 08083 1.4580 

2310021300 08087 1.4580 

2310021300 08095 1.4580 

2310021300 08099 1.4580 

2310021300 08103 1.6764 

2310021300 08107 1.4580 

2310021300 08113 1.4580 

2310021300 08121 1.4580 

2310021300 08123 1.4580 

2310021300 08125 1.4580 

2310021300 30005 1.2437 

2310021300 30009 3.6853 

2310021300 30015 1.4580 

2310021300 30017 12.9403 

2310021300 30025 1.4580 

2310021300 30027 1.4580 

2310021300 30035 1.4580 

2310021300 30037 1.9294 

2310021300 30041 1.4580 

2310021300 30051 1.4580 

2310021300 30071 1.4580 

2310021300 30073 1.4580 

2310021300 30075 371.1493 

2310021300 30079 1.4580 

2310021300 30083 1.4580 

2310021300 30085 1.4580 

2310021300 30091 1.4580 

2310021300 30095 1.8116 

2310021300 30097 1.7071 

2310021300 30099 1.4580 

2310021300 30101 1.4580 

2310021300 30105 1.4580 

2310021300 30109 1.4580 

2310021300 32023 1.4580 

2310021300 35001 1.4580 

SCC FIPS 

Growth 

Factor

2310021300 35005 1.3540

2310021300 35007 1.3540

2310021300 35015 1.3540

2310021300 35021 1.3540

2310021300 35025 1.3540

2310021300 35031 36.4321

2310021300 35039 2.9921

2310021300 35041 1.3540

2310021300 35043 1.4274

2310021300 35045 3.7217

2310021300 35059 1.3540

2310021300 38011 1.4580

2310021300 38013 1.4580

2310021300 38053 5.9557

2310021300 38105 1.4580

2310021300 41009 0.5680

2310021300 46063 1.4580

2310021300 49007 1.4580

2310021300 49009 2.1185

2310021300 49013 116.0424

2310021300 49015 1.4580

2310021300 49019 1.4580

2310021300 49037 1.4580

2310021300 49043 1.4580

2310021300 49047 2.5806

2310021300 56001 1.4580

2310021300 56003 1.4580

2310021300 56005 0.9965

2310021300 56007 1.6616

2310021300 56009 1.1075

2310021300 56011 1.4580

2310021300 56013 1.4580

2310021300 56017 1.4580

2310021300 56019 0.9771

2310021300 56023 1.5411

2310021300 56025 1.4580

2310021300 56027 1.4580

2310021300 56029 1.4580

2310021300 56035 7.4972

2310021300 56037 1.5467

2310021300 56041 1.4580

2310021300 56043 1.4580

2310021300 56045 1.4580

2310021400 00000 2.3099

2310021400 32023 1.4580

SCC FIPS 

Growth 

Factor

2310021400 35001 1.4580

2310021400 35005 1.3540

2310021400 35007 1.3540

2310021400 35015 1.3540

2310021400 35021 1.3540

2310021400 35025 1.3540

2310021400 35031 36.4321

2310021400 35039 2.9921

2310021400 35041 1.3540

2310021400 35043 1.4274

2310021400 35045 3.7217

2310021400 35059 1.3540

2310021400 38011 1.4580

2310021400 38013 1.4580

2310021400 38053 5.9557

2310021400 38105 1.4580

2310021400 41009 0.5680

2310021400 46063 1.4580

2310021400 49007 1.4580

2310021400 49009 2.1185

2310021400 49013 116.0424

2310021400 49015 1.4580

2310021400 49019 1.4580

2310021400 49037 1.4580

2310021400 49043 1.4580

2310021400 49047 2.5806

2310021400 56001 1.4580

2310021400 56003 1.4580

2310021400 56005 0.9965

2310021400 56007 1.6616

2310021400 56009 1.1075

2310021400 56011 1.4580

2310021400 56013 1.4580

2310021400 56017 1.4580

2310021400 56019 0.9771

2310021400 56023 1.5411

2310021400 56025 1.4580

2310021400 56027 1.4580

2310021400 56029 1.4580

2310021400 56035 7.4972

2310021400 56037 1.5467

2310021400 56041 1.4580

2310021400 56043 1.4580

2310021400 56045 1.4580

2310021500 00000 2.3099
December 2005 

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxD_GrowthFactors.doc D-8

SCC FIPS 

Growth 

Factor 

2310021500 02122 0.2138 

2310021500 08001 1.4580 

2310021500 08009 1.4580 

2310021500 08013 1.4580 

2310021500 08014 1.4580 

2310021500 08017 1.4580 

2310021500 08045 1.4595 

2310021500 08067 1.4535 

2310021500 08071 1.4580 

2310021500 08073 1.4580 

2310021500 08075 1.4580 

2310021500 08077 1.4580 

2310021500 08081 1.4638 

2310021500 08087 1.4580 

2310021500 08099 1.4580 

2310021500 08103 1.6764 

2310021500 08113 1.4580 

2310021500 08121 1.4580 

2310021500 08123 1.4580 

2310021500 08125 1.4580 

2310021500 30005 1.2437 

2310021500 30015 1.4580 

2310021500 30025 1.4580 

2310021500 30041 1.4580 

2310021500 30051 1.4580 

2310021500 30071 1.4580 

2310021500 30101 1.4580 

2310021500 30105 1.4580 

2310021500 35001 1.4580 

2310021500 35005 1.3540 

2310021500 35007 1.3540 

2310021500 35015 1.3540 

2310021500 35025 1.3540 

2310021500 35039 2.9921 

2310021500 35045 3.7217 

2310021500 35059 1.3540 

2310021500 38011 1.4580 

2310021500 49007 1.4580 

2310021500 49043 1.4580 

2310021500 49047 2.5806 

2310021500 56003 1.4580 

2310021500 56005 0.9965 

2310021500 56007 1.6616 

2310021500 56013 1.4580 

2310021500 56023 1.5411 

SCC FIPS 

Growth 

Factor

2310021500 56025 1.4580

2310021500 56029 1.4580

2310021500 56035 7.4972

2310021500 56037 1.5467

2310021500 56041 1.4580

2310023000 00000 1.6924

2310023000 08007 1.4580

2310023000 08045 1.4580

2310023000 08055 1.4580

2310023000 08067 1.5838

2310023000 08071 1.4580

2310023000 08077 1.4580

2310023000 08081 1.4580

2310023000 08103 0.9955

2310023000 08107 1.4580

2310023000 35007 0.0000

2310023000 35039 1.9105

2310023000 35045 1.9162

2310023000 56005 7.6917

2310023000 56007 1.4580

2310023000 56009 7.6666

2310023000 56019 7.6901

2310023000 56033 7.6748

2310023000 56035 0.9926

2310023000 56037 1.4580

2310023000 56041 1.4580

2310030210 00000 2.3099

2310030210 35001 1.4580

2310030210 35005 1.3540

2310030210 35015 1.3540

2310030210 35025 1.3540

2310030210 35039 2.9921

2310030210 35041 1.3540

2310030210 35043 1.4274

2310030210 35045 3.7217

2310030210 49007 1.4580

2310030210 49009 2.1185

2310030210 49013 116.0424

2310030210 49015 1.4580

2310030210 49019 1.4580

2310030210 49037 1.4580

2310030210 49043 1.4580

2310030210 49047 2.5806

2310030210 56003 1.4580

2310030210 56005 0.9965

SCC FIPS 

Growth 

Factor

2310030210 56007 1.6616

2310030210 56009 1.1075

2310030210 56013 1.4580

2310030210 56017 1.4580

2310030210 56023 1.5411

2310030210 56025 1.4580

2310030210 56027 1.4580

2310030210 56029 1.4580

2310030210 56035 7.4972

2310030210 56037 1.5467

2310030210 56041 1.4580

2310030210 56043 1.4580

2310030210 56045 1.4580

2310030220 30009 3.6853

2310030220 30035 1.4580

2310030220 30091 1.4580

2310030220 30101 1.4580

2310030220 38013 1.4580

2310030220 38053 5.9557

2310030220 38105 1.4580

2310030220 56005 0.9965

2310030220 56007 1.6616

2310030220 56009 1.1075

2310030220 56013 1.4580

2310030220 56023 1.5411

2310030220 56025 1.4580

2310030220 56027 1.4580

2310030220 56029 1.4580

2310030220 56035 7.4972

2310030220 56037 1.5467

2310030220 56041 1.4580

2310030220 56043 1.4580

2310030220 56045 1.4580