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 415.899.0700December 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 SURR OGATES 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 ga s 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-specifi c emission factors could not be created........ 2-7 Table 2-5. State tota l 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 re view of compressor engine studies ............................ 2-14 Table 2-8. State controls on compressor e ngines and controlled emission factors............. 2-15December 2005

ii Table 2-9. State total NOx emissions from gas compressor engines .................................. 2-16 Table 2-10. State point sour ce 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 es timate 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 da ta obtained from the oil and gas commissions......................... 2-27 Table 2-19. Sources of well-sp ecific production data........................................................... 2-28 Table 2-20. Coalbed methane produci ng formations in New Mexico .................................. 2-29 Table 2-21. Controls on sources co nsidered in the VOC and minor NOx source inventory........................................................................................ 2-31 Table 2-22. Summary of control-adju sted 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 ga s NOx emissions from 2002 to 2018 .................................. 4-3 Table 4-3. BLM Resource Management Plan s 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 sour ce in areas where local plans were used.......... 4-9 Table 4-7. Growth factor used for each s ource in areas where EIA data were used............. 4-9 Table 4-8. State NOx emission factor s 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 informa tion provided by State DEQ................................................. 4-12

FIGURES

Figure 2-1. Distribution of well preparation activ ities 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 Colora do wells based on the ratio of gas production to oil production............................................................................... 2-29 Figure 2-8. Coal bed methan e fields in New Mexico........................................................... 2-30 Figure 3-1. Locations of wells and drill rigs........................................................................... 3-2 Figure 3-2. Oil production surroga tes 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 ........................... 3-6December 2005

iii Figure 3-5. Drill rig surrogate s for the 36 km domain ........................................................... 3-7 Figure 3-6. Oil production surroga tes 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 surrogate s for the 12 km domain ......................................................... 3-11 Figure 3-10. Example daily spatial emi ssions 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 develo ped to represent growth in gas production in WRAP region .............................................................................. 4-10December 2005

G:\WRAP SSJF O&G\Reporting\Document ation\Final\Tribal preface.doc iv PREFACE

Regulatory Framework for Tribal Visibility Implementation Plans

The Regional Haze Rule explicitly recognizes the au thority 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 Author ity Rule (TAR) (40 CFR §§49.1– .11). Those provisions create the following framework:

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

2. Federally recognized tribes may apply for a nd receive delegation of federal authority to implement CAA programs, including visibility regul ation, or "reasonably se verable" elements of such programs (40 CFR §§49.3, 49.7). The mechanism for this delegation is a Tribal Implementation Plan (TIP). A reasonably severabl e 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 regulator y requirements.

3. The Regional Haze Rule expressly provides that tribal visibility programs are “not dependent on the strategies selected by th e state or states in which th e tribe is located” (64. Fed. Reg. 35756), and that the authority to implement §309 TI Ps extends to all tribes within the GCVTC region (40 CFR §51.309(d)(12).

4. The EPA has indicated that under the TAR trib es 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). EP A 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 re ferences 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.December 2005

G:\WRAP SSJF O&G\Reporting\Document ation\Final\Tribal preface.doc v 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 fr om the “stakeholders” (private interest) which participate on Forums and Comm ittees but are not eligible for the Board.

Despite this equality of representation on the Bo ard, tribes are very differently situated than states. There are over four hundred federally re cognized tribes in the WRAP region, including Alaska. The sheer number of tribes makes full pa rticipation 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 importa nt 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, includ ing Board members Forum and Committee members and co-chairs, make their best effort to ensure th at WRAP products are in the best interest of the tribes, the environment, and the public. One inte rest is to ensure that WRAP policies, as implemented by states and tribes, will not constr ain 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 stak eholder interests in appr oving this report as a consensus document.

An adjunct study of oil and gas emissions poi nt and area source emissions was conducted by ENVIRON and ERG. Oil and ga s 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 in ventoried, 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 Amer ican Reservations and Tribal Lands (ERG/ENVIRON, 2005), does not include Jicarilla Apache data.December 2005

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec1_Intro.doc 1-1 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 quantiti es 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 othe r segments of the industry. The largest oil and gas production facilities, gas plants and ma jor compressor stations, have been previously inventoried as stationary sour ces. All states in the wester n region had previously compiled emission inventories for the year 2002 that includ ed the major “point” emi ssion sources in the oil and gas production industry. Howe ver, what was included in thes e emission inventories varied from state to state, depending on the permitting and/or reporting thresholds.

Oil and gas production facilities that are geographically distri buted and have lesser emissions than the point source threshold ar e considered area sources. Pr ior to this study, there had not been a comprehensive emission inventory of o il and gas production opera tions in the western region that covered both point a nd area sources. Nor had there been a methodology developed to produce an inventory of this scop e. 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 region ally consistent emission inventory for oil and gas area sources, and resources were limited, this inve ntory is neither comprehensive nor as accurate as it might be with more resources. The focu s was on the larger sources of NOx emissions; NOx and VOC emissions from minor wellhead processe s for which emission factors were available were also estimated. This i nventory and the methodology used s hould be considered as a first step toward a better understanding of oil and ga s emissions, and the basis for further work to improve the estimates.

In developing the emission estimation methodolo gy, considerable resources were devoted to incorporating the insights and guida nce of a variety of stakeholde rs, as well as integrating the point source emissions estimates developed in prev ious inventory efforts. The work plans that guided this project were devel oped 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 em issions 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 in clude 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 ofDecember 2005

G:\WRAP SSJF O&G\Reporting\Documentation\Final\Sec1_Intro.doc 1-2 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 formul ate and implement a procedure to project the emissions from oil and gas production opera tions in 2018. For the WRAP 2018 base case modeling, only those emission contro l strategies that have already been adopted are considered. Once again, the work plan that guided the deve lopment of the projection method was developed in collaboration with the stakeholders repr esented in the SSJF Oil And Gas Work Group. Ultimately, oil and gas production forecasts were dr awn from several sources and combined with the emissions estimates produced for the 2002 inve ntory and information on future controls to arrive at the 2018 inventory. O il and gas point source projections are described in a separate report (ERG, 2005b).

This report describes the procedures developed in each task of this projec t and the results that have been obtained. Section 2 presents th e methodology developed to create a comprehensive oil and gas emissions inventory for the wester n 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 describe s the data sources and methods th at have been used to project emissions in the year 2018, and provides the resulting emissions estimates.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-1 2. 2002 BASE YEAR EM ISSION INVENTORY

INTRODUCTION

This section describes the base year 2002 emission invent ory of oil and gas area sources for the Western States. The focus of this inventory e ffort 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 me thodologies were defined for es timating 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 we re 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 Boar d (CARB) has provided ar ea source oil and gas emissions estimates directly to WRAP. Those es timates 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 cate gory, except in California wher e only the total NOx emission from the ARB inventory is given. The point so urce emissions included in Tables 2-1a and 2-1b include several types of oil a nd gas facilities that are list ed under SIC codes 13**, 492* or 4612 (ERG, 2005a). In most states, the major contribu tors 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 contribu tion in some states. No tably, the point source inventory methods in the State of Colorado and the State of Alas ka are such that the majority of oil and gas emissions sources are incl uded in the point source inventory.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-2 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 8,070 16,707 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 54,828 21,536 42,800 3,141 130,376 181,191 311,566 Point Source Total TOTAL State Wellhead 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 18,712 7,101 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 33,127 3,424 8,849 91,636 115,176 103,414 378 374,715 93,371 468,087 Condensate

Tanks - Uncontrolled Condensate Tanks - Controlled

Total Point Source Total TOTAL State 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 o il 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.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-3 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 ba se measure of activity and to supplement that with more sophisticated data from drilling companie s. 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 activit y 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 c ontacted large drilling co mpanies to obtain data on the types of engines used for drilling, the normal operational schedu le of the engines, regional variation of drilling rates and th e relative activity of rotary vers us workover rigs. The response to this survey was a mixture of refusal to part icipate 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 OGC s to obtain, amid other information, the activity data afforded by drill pe rmits. The OGCs, in general, readily made the requested information available. The excepti on was the New Mexico Oil and Gas Conservation Commission, which declined to provide informati on. However, with considerable assistance from the New Mexico Air Quality Department, the necessary information was obtained for New

Mexico as well. The drilling informati on 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 EmissionsDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-4 • Well depth - the depth of the well; total vertical, measured or target depending on availability

• Completion date - the date well preparation is finalized; occurring wi th 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 consid erably from State to State. While each State maintained a database containing these fields, ev ery 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. T hose 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 C onservation 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, th e 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 dr illing 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 Environm ental Quality (DEQ) was able to provide results from a recent survey of drilli ng 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 theDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-5 WYDEQ (2005) survey are 13.5 tons NOx per well and 3.3 tons SO 2 per well. The Colorado Department of Public Health and Environment (CDPHE) was also able to offer an emission factor. That factor was provi ded by only one company and without information available as to the area for which such a factor would be approp riate. Due to the larger survey size and the greater information available it was therefore th e 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 compositi on of substrate and the charact eristics of the engine. For example, a small rig drilling a relatively sha llow 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 operati ons, 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 informati on about the char acteristics 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 charac teristics were commonly available was the formation. Creating formation-specific emi ssion 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 drilli ng operations at several formations . This analysis showed that while there was variation of th e 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 distributio n for the Blanco-Mesaverde formation in New Mexico. It shows that the large majority of wells drilled in that forma tion 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 we lls. 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 an d 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.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-6 Blanco-Mesaverde Distributi on of Drilling Durations

0 2 4 6 8 10 12 14 16 18

10 20 30 40 50 6 0 70 80 9 0 100 110 120 130 1 4 0 150 160 1 7 0 1 8 0 190 2 0 0

DurationWells 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 ac tivities for wells in a single formation are approximated by the average for th e formation, two other important assumptions were made. First, it was necessa ry to assume that the difference between the completion date and the date that drilling ceased is, on average, constant rela tive to the total duration of preparation activities. This assumption was need ed because the actual date that drilling ceased was not available. What this assumption mean s 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 no t 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 capac ity 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 differe nt 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 variati ons due to well depth, composition of substrate, and engine capacity.

The first step in scaling the Jonah-Pinedale em ission factor was to determine the appropriate average well depth and duration for the Jonah-Pine dale 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 a nd 2004 - was 11,896 ft and 80.6 days (WY OGCCDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-7 2005). The same type of average well depth a nd drilling duration was th en calculated for the other formations drilled in 2002 in the WRAP Stat es. 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 cr eation 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 t hose for well depths and durations. State DEQs were surveyed to determine if there were any co ntrol requirements for drill rigs. All State DEQs responded that controls were not required on dr ill 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 co unties. 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 le vel developed for the WRAP 2002 nonroad diesel equipment emission inventory. EF A = EF J x ( D A / D J ) x ( T A / T J )

where: EF A = The emission factor for another formation EF J = The Jonah-Pinedale emission factor D A = The average depth of wells drilled in another area Dj = The average depth of wells drilled in Jonah-Pinedale T A = The duration of drilling in another area T j = The duration of drilling in Jonah-PinedaleDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-8 Emissions for a single formation were calculated using Calculation 2. The emissions for that formation were then allocated to the counties th at intersected the formation based on the fraction of the total wells drilled that we re drilled in each c ounty’s portion of the formation, as shown in Calculation 3.

Calculation 2:

Calculation 3:

The state total drill rig NOx and SO 2 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 sh allow depth, as commonly occurs for the Powder River Basin CBM wells. In contrast, the wells in New Mexico were, on av erage, drilled deeper and took longer to drill. Where average drill de pths and durations were more comparable, such as in Colorado and New Mexico, the emissions pe r 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 rota ry 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 act ivity 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 drille d 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 dri lled in the county’s portion of the

formation TW = The total number of wells drilled in the formationDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-9 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 incl uded geographic coordinates, this map clearly displays the areas where well dr illing 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 geogra phic area defined by the State boundaries, but not necessarily to the States’ jurisdiction; a small am ount of those emissions in the State inventory fall under tribal jurisdiction.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-10 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 comp ressor 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 line s. These are typically Title V facilities and they are dealt with as point sour ces. The second tier of facilitie s 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 ar e not in the point sour ce 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 sm all, dispersed wellhead compressor engines. Figure 2-3 presents an example of such an engi ne. In all but two of the natural gas producing States, these engines have not b een included in previous emission inventories and their inclusion here represents a significant a dvance in understanding this impor tant 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 presente d in this subsection.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-11 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 fr om compressor operators. As was proposed, we contacted a large number of compressor opera tors, 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 th e 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 ne cessary to use an alternative methodology that did not rely on using data from operators.

The alternative methodology was to develop a pr oduction-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 appr opriate data from which to derive the emission factor. The strengths and weakne sses of each of those studies and the ultimate selection of an industry-compiled inventory of wellhead compresso r 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 a nd Environment compiled a point source emission inventory for the year 2002 that includes source s 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 wellh ead compressors are expected to have been included in the inventory. Gas production data wa s also obtained from the Colorado Oil and Gas Conservation Commission, maki ng it appear possible to cr eate a production-based emissionDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-12 factor by comparing emissions from the comp ressor engines in the Colorado point source inventory with gas producti on reported by the CO OGCC.

The extraction of only those engines used to po wer wellhead compressors from the point source inventory proved a more difficult task than expect ed. The coding of engines was such that it was difficult to distinguish between engines used for compression and e ngines used for other purposes such as pumping or generator sets. No r was it possible to determine with confidence the subset of engines that represented only sma ll wellhead compressor engines that would not be included in other States’ point s ource inventories. This second problem represented an obstacle, because if medium-sized facili ties were inadvertently include d in the development of the emission factor then the resulting area sour ce emission estimate for ot her States would be double-counting the emissions from medium-sized gas gathering facilities. Despite the fact that the CDPHE generously provided additional info rmation 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 Colora do point source inventory.

2002 New Mexico Oil and Gas Asso ciation’s Inventory of Unperm itted Sources in the San Juan Basin

The New Mexico Oil and Gas Association (NM OGA) 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 pro duction industry in the New Mexico portion of the San Juan Basin. In the State of New Mexi co, the threshold for pe rmitting 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 wellh ead compressor engines fall into this category. The NMOGA inventory provided emissions for we llhead 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 ac tivity 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 produc tion in three New Mexi co 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)December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-13 With these estimates of total gas production a nd total emissions for wellhead compression, it was possible to calculate a production based emission fact or 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 th e future development of gas wells. That information, in the form of expected installed wellhead compressi on capacity, was combined with an EPA emission factor for natural gas fired engi nes, to estimate the expected em issions 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 he nce compressor operati on, 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 fo r Light Commercial Gas Compressors (SCC2268006020) from the EPA’s NONROAD2004 emissions mode l, this compressor activity would result in 44 tons of NOx. Dividing this result by the associated production, 91,250 MCF, re sults 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 cal culate 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/L ongview/Marshal Flexible Attainment Region of East Texas included an estimate of the emissi ons for area source compressor engines. The method used by the contractor, Pollution Solution s (2005), to estimate gas compressor emissions was to develop a relationship between compre ssor engine activity and gas production from a survey of compressor operators. That relations hip was then used with gas production statistics and EPA emission factors to estimate engine emissions.

The survey of operators yielded a relations hip of 191 horsepower of compression per MMSCFday of gas production. Assuming 8760 hours per ye ar of operation, as was done in the East Texas Inventory, this results in 1,673,160 hp-hr/y ear per MMSCF-day. Conve rting that figure to an activity factor based on annual gas produc tion gives 4,584 hp-hr pe r 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-base d emission factor of 5.6x10 -5 tons NOx per MCF.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-14 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 fr om actual operations and falls between the factors derived from the NMOGA inventory and the BL M EIS. However, Pollution Solutions was unwilling to provide the details of th e 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 I nventory in the absence of supporting evidence. We therefore decided to use th e emission factor derived from the New Mexico Oil and Gas Association’s Inventory of Unpe rmitted Sources in the San Juan Basin. This study has several advantages over the other studies. It is a study of existing oper ations in an important production area of the WRAP States and the survey of co mpressor 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 contro lled 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-basedDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-15 emission factors for Utah and Wyoming have be en adjusted downward to account for this difference. In both States, the controlled emissi on 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 NA 1 Colorado CDPHE, 2005b NA 1 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 Tabl e 2-9, and graphically displayed in Figure 2-4, emissions resulting from this procedure are direc tly 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 compre ssor 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 emissi ons 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 fa cilities differ dramatical ly from those found in the other WRAP States. In Alaska, both personn el 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 pe rmitted along with the processing plant (AK OGCC, 2005b; AK DEC, 2005b). Wellhead compressor engine s 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

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-16 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 es timates of area source oil and gas emissions

Figure 2-4. County-level 2002 gas compressor engine emissions.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-17 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. Th is 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 em ission inventory. However, this wa s not the case in all States. A summary of the State i nventory 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 in ventories. The State of Alaska and the State of Colorado have different invent ory thresholds, but this did not require any reconciliation of the ar ea source compression emission estimat e as in those States wellhead compression is included entirely in the point source emission inventory.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-18 In Arizona, Nevada, Oregon and No rth Dakota, Utah and South Dakot a, the fact that the States’ inventory thresholds differed from the New Mexico PTE 25 tpy threshold required special treatment. Discussion with staff at the Ariz ona and Nevada DEQ revealed that despite the different thresholds, no further action was nece ssary. 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 thresh old, no wellhead compressor engines had been included in the point sour ce inventory (NV DEP, 2005).

In Oregon and North Dakota, State DEQ personnel indicated that ther e were oil and gas facilities that fell below the State point s ource inventory threshol d, but were larger faci lities that would not be accounted for in the area source wellhead compre ssion 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 emissi ons data were obtained fr om the State and have been included in the area source emission inventory (see Table 2-13).

In Utah and South Dakota, there existed th e same gap between the wellhead compression emissions and the state point s ource inventory as in Oregon a nd North Dakota. However, in Utah and South Dakota it was not possible to obtai n 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 th en scaling the emissions from those facilities to gas producti on 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 calcula te the potential to emit for each emission unit included in those oil and gas faci lities. 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 i nventory had emissions of 10 tons NOx, but had only operated 4000 hours, then the potential to emit for that unit was calculated as the pr oduct 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 es timating 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 fac ilities with a total PTE un der 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 ProductionDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-19 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 tota ls by the State total gas production we arrived at the production-based emission fact ors 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 w ith the county gas production in Utah and South Dakota, we estimated emissions for the medium-s ized 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 obtaine d emissions for this source a nd 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 fo r estimating emissions from coal bed methane generators relied on obtaining information on ge nerator specifications and usage from State environmental departments. Based on the map of CBM production obtained from the Energy Information Administration (Figure 2-5), enviro nmental departments were contacted for this information in five States: Colorado, Montan a, 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 pu mps are expected to be operated on line power (Richmond, 2005; Daniels, 2005). Th erefore it remained to determine generator usage in only Colorado and New Mexico.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-20 Figure 2-5. Western U.S. Coal bed methane fields (EIA, 2004).

While contacting the State envir onmental 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 productio n at CBM wells. In addition, the depth of wells was obtained for some sampling of the we lls in each State; depth information was not available for every well. Based on the data av ailable, 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 averag e 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 lif ted 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 possi ble explanation for the surprisingly low results determined by this method is that the ge nerator information obtain ed from the State of Wyoming excluded some of the engines, possibly t hose that are directly c oupled to CBM pumps. Also, actual hours of operation were only available for a subset of th e generators. Activity of the remaining generators in Wyoming was extrapolated from the activity of that subset. It’s possibleDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-21 that the activity of th e 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 databa se of generators obtained from the Wyoming DEQ may not include all the engines associated w ith 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. In formation on the design and operation of CBM wells in combination with engi neering calculations provided a wa y to estimate engine activity (horsepower-hours) based on wa ter production. Once horsepower- hours were estimated, it was then possible to derive an emission estim ate 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 th e pump. Assuming that losses in the electrical delivery system are negligible, the power supp lied 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 pos sible to estimate the horsepower-hours of the engine. This was then co mbined 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 Simp lification 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).December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-22 Information from State OGC and industry contacts enabled us to define th e 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 a pplications (Weatherford, 2005; Strong, 2005). A representative of one production company operating in Wyoming repor ted that the vast majority of the pumps it used (over 90 percent) are electric submer sible pumps (ESP) with an approximate efficiency of 60 percent (Olson, 200 5). 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 r od 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 assu med 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 lo st to heat and turbulen ce at the pipe-water interface). This system can be described usi ng a form of the Bernoulli equation, where theDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-23 energy at the exit of the pipe (labeled “2” in Figu re 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. Modifi ed Bernoulli equation

g P z H H g P z L P 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/ft 2

ν = Velocity H p = The head imparted by the pump (feet) H L = 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:

2 1 z H H z L P =

+ +

rearranging and substituting the depth (d) for z 2 - z 1 shows that the energy imparted by the pump, H p , is given by:

L P H d H + =

H L is somewhat difficult to calculate due to the dependence of the calculation method on the flowrate. For the same pipe under a certain thre shold 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 Br uce Gantner (2005) of the New Mexico Oil and Gas Association, it wa s clear that pumps ar e 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 ar e operating with a very low load when no water is being pumped and the rest of the time are operating at a load suffi cient 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 th e emissions resulting from the wo rk performed to lift water fromDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-24 the wells. In terms of the determination of fl owrates, this 50 percent operational schedule means that flowrates are determined based on the total annual water produc tion divided by 4,380 hours per year of pumping.

Calculation 5. Method for calcu lating the frictio nal losses (H L )

ν V D 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 f H 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,

17

. 1 85

. 1 85

. 1 ) 318

. 1 ( R C L V H

H L × × = (the Hazen-Williams equation)

where: V = The velocity of flow L = The length of pipe R = The hydraulic radius (cross-sectiona l area of pipe divided by the wetted perimeter) C H = The Hazen-Williams coefficient, 140 for plasticsDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-25 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

550 / γ × × = Q

H P P

where P = the power supplied by the pump (hp) H P = the energy supplied by the pump (ft) Q = the flowrate (cfs) γ = specific weight of water (62.4 lb/ft 2 )

Once the power delivered by the pump was determ ined, determining the power developed by the engine was a matter of applying th e pump and generator efficiencies as shown in Calculation 7.

Calculation 7. Determining the engine power

G P E P P ε ε / / =

where P E = the power developed by the engine (hp) P = the power delivered by the pump (hp)

ε P = the efficiency of the pump (0.60)

ε G = the efficiency of the generator (0.85)

Total annual engine activity due to pumping water at one well wa s estimated as the product of the power developed by the engine and 4,380 hours pe r year. To this acti vity, 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 emissi on factor for natural gas fired engines (SCC 2268006005) provided in EPA’s NONRO AD (2004). For Wyoming, an emission factor was developed that re flected the controls imposed by WYDEQ on natural gas fired engines and the use of some diesel generators to power pumps. That emi ssion 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 resu lted in per well NOx emissions for these three states of 0.59 tpy/well in Colora do, 0.06 tpy/well in New Mexico a nd 0.23 tpy/well in Wyoming. This represents a significant increase over the emissions predic ted by the previous method, 0.080December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-26 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 engine s 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 engi nes. Industry representatives indicated that the San Juan Basin, where most coalbed methan e production occurs in New Mexico, is a mature field where at this point co mparatively 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 pote ntially major sources of NOx emissions, we have estimated emissions for several other processes occurring at oil and ga s wellheads. Emissions were estimated for both NOx and VOC using well-specific production and emission factors provided by the Wyoming Department of Enviro nmental Quality and the Colorado Department of Public Health and Environment. The sources for which emissions were estimated in this portion of the inventory ar e 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 emi ssion 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 emissi on factors. Only the CDPHE (2005) provided alternate emission factors. The emission f actors used are presented in Table 2-17.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-27 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 completion 1

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, th e 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-speci fic 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 dateDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-28 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 we re those containing the producti on figures. These appeared to be well maintained. However, in some cases th e 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 whet her 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 well s (WYDEQ, 2004b). In order to proceed, it was necessary to divide the wells into these two ca tegories. For the Stat e of Colorado this was accomplished by calculating the ratio of gas produc tion (MCF) to oil production (BBL) for all wells and then determining wher e an appropriate division would be. The distribution of wells according to their gas oil ratios is presented in Figure 2-7.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-29 Distribution based on Gas:Oil Ratio

0 500 1000 1500 2000 2500 3000 3500 4000

0.01 0.1 1 20 40 60 80 10 0 12 0 14 0 16 0 18 0 20 0 22 0 24 0

Gas:Oil RatioNumber 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 di stribution between wells with a ratio under 0.1 and those with a ratio above 0.1. This break places the great majo rity of wells into the ga s well category. Using a gas:oil ratio of 0.1 to distingui sh 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 divi sion places the large majo rity of wells into the category of gas wells. Gas wells have higher emission factors and thus this represents a conservative emissions estimate. Also, the Ener gy Information Administration estimates over 23 thousand gas wells in the State of Colorado in 2002, which s upports 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 emi ssion factors in Table 2-17 are representative of processes at traditional gas wells, not at coalbe d methane wells. The only State for which an identifier was not provided for coalbed methane we lls 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 - VermejoDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-30 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, ther e was still one more f iltering of the production data required. Because some of the emission fact ors 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 emi ssions 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 sour ces 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 th ese 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 t hose States that did not report a ny 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 fact ors. This has been done because the flaring assumed in the emission factor is not very differe nt from the flaring we would assume based only on safety considerations.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-31 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 cont rolled with an overall efficien cy 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 th e absence of controls on condensate tanks in States, emissions were simply estimated for al l 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 tw o States, emissions for all condensate tanks were estima ted 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 wh enever possible is already assumed in the Wyoming emission factor. In the State of Mont ana, however, it was specified that the control efficiency assumed was 98 percent for an el evated flare (MT DEQ, 2005). The control efficiency for a flaring assumed by WY DEQ wa s 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 combus ted (WYDEQ, 2004b). To account for the greater control efficiency reported by Montana DEQ, th e Wyoming emission factors were adjusted for use in Montana.

Based on a typical well completion log, the Wyom ing DEQ assumed that 5.0 MMSCF of gas are flared or vented during 10 days of completion ac tivity. 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 calcula te new emission factors for Montana using AP-42 emission factors for a flare. The details of this calculation, in cluding the assumed gas characteristics are shown in Calculation 8.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-32 Calculation 8. Calculation of co mpletion 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 (10 6 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 (10 6 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 (10 6 SCF/MMCF) x F x H x (MMBtu/10 6 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 (10 6 SCF/MMCF) x 1.0 x 1000 Btu/SCF x (MMBtu/10 6 Btu) x 0.14 lb NOx/MMBtu x (ton/2000 lb) EF = 3.5 ton NOx per completionDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-33 A summary of the final gas well em ission 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 proceed ed to estimate emissions. Emission factors, adjusted as described for controls, were comb ined with the well data to estimate emissions following the general procedure shown in Calcula tion 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 em ission 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 genera l outline of how emissions were estimated for the VOC and minor NOx processes. For detailed sample calculations for each of these proces ses, refer to Appendix B. A summary of the emissions estimated for VOC and minor NOx processes is presented in Table 2-23.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-34 Calculation 9. Calculation of wellh ead emissions for individual wells

Gas Well E = SUM i (P g x EF g,i ) + SUM j (Pc x EF c,j ) + SUM(EF w )

where: E = The 2002 emission P g = 2002 gas production EF g,i = Emission factor for gas process i P c = 2002 condensate production EF c,j = Emission factor for condensate process j EF w = Per well emission factor

Oil Well E = SUM i (P o x EF g,i ) + SUM(EF w )

where: E = The 2002 emission P o = 2002 oil production EF o,i = Emission factor for oil process i EF w = Per well emission factor

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

State VOC NOx

Alaska 1 430 9

Arizona Colorado 2 25,386 15,924

Idaho

Montana 3 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 represen ted in this summary table that have not yet been mentioned. Emissions for condensate tanks and glycol de hydrators are not incl uded for the State ofDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec2_2002emissions.doc 2-35 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 Stat e 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 perm itted under the umbrella of larger facilities (AK OGCC, 2005b; AK DEC, 2005b). Emi ssions 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).December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-1 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 re present 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. No te 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.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-2 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 eitherDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-3 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 al so 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.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-4 Figure 3-2 . Oil production surrogates for the 36 km domain.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-5 Figure 3-3 . Gas production surrogates for the 36 km domain

.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-6 Figure 3-4 . CBM well water production surrogates for the 36 km domain.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-7 Figure 3-5 . Drill rig surrogates for the 36 km domain.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-8 Figure 3-6 . Oil production surrogates for the 12 km domain.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-9 Figure 3-7 . Gas production surrogates for the 12 km domain.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-10 Figure 3-8 . CBM well water production surrogates for the 12 km domain.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-11 Figure 3-9 . Drill rig surrogates for the 12 km domain.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Se c3_spatial.doc 3-12 Figure 3-10 . Example daily spatial emissions plot of the 2002 oil and gas emissions as processed through SMOKE.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-1 4. 2018 BASE CASE PROJECTIONS

INTRODUCTION

This section describes the methods for estima ting the 2018 base case emission inventory of oil and gas area sources for the Western States. This inventory reflect s the anticipated 2018 emission levels with the future controls curren tly defined by state and federal regulation. The 2018 oil and gas point source emissions inventory ha s been prepared under a separate task, and is reported separately (ERG, 2005b). Thus, while some tables in this sectio n present summaries of the 2018 point source emissions, information a bout the methodology used to develop those emissions estimates will be found in the re port 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 trib al 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 whic h area source emissions are not es timated here is the State of California. The California Air Resources Boar d (CARB) has provided po int 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 estimate d 2018 NOx emissions from oil and gas area point and area sources in the WRAP States. Tabl e 4-1b presents a similar summary of VOC emissions. The area source emissions are distin guished by source category, except in California where only the total NOx emission from the AR B 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 stat es, the major contribut ors 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 sour ce inventory methods in the Stat e of Colorado and the State of Alaska are such that the majority of oil and gas emissions sources ar e included in the point source inventory.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-2 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 69,246 166,009 27,082 84,932 1,348 279,370 126,536 405,907 Point Source Total TOTAL State Wellhead 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 invent ory 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 greate r than 50 thousand ton decrease in NOx emissions predicted for point sources. The area source and ove rall increases are most substantial in places where recent development plans predict large-scale oi l and gas projects in future years. Such is the case in Montana and Wyoming where major deve lopment 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 A rea 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 99,907 986,811December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-3 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 esti mate 2018 county-level oil and gas emissions. The first and by far the dominant me thod 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 201 8. 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 source s and methodologies are pres ented 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 re quired the development of county-level growth factors. These growth factors were derived fr om 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 st ewardship. RMP for oil and gas production areas typically include an estimate of reasonable fore seeable oil and gas development. The future development is usually estimated as a numbe r of new oil, gas and possibly CBM wells anticipated over the next 10 or 20 years. Tabl e 4-3 provides a brief summary of the reasonable foreseeable development (RFD) scenarios that we re ultimately used to obtain the necessary information for creating the 2002 to 2018 growth factors.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-4 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 approxima te area covered by these resource management plans. Despite the broad combined coverage of these plans, there are some significant production areas for which manageme nt plans could not be located.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-5 Figure 4-1. Coverage of resource management plans ultimately used to create growth factors.

For some of the areas where it was not possibl e 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, 200 4) prepares 20-year production forecasts that were used in this effort. Other local sources of data were co nsidered, but were ultimate ly 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 identifie d, separate oil and gas gr owth factors have been calculated as the 2018 regional production fore cast by the EIA divided by 2002 regional production reported by the EIA. Th ere are three EIA growth regi ons in which some portion of emissions in that region were projected using EIA data. Thos e regions are the Rocky Mountain Region, the Southwest Region and the West Coast Region. Growth factors developed for thoseDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-6 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 ma nagement plans or Alaska DNR data were made using growth factors derived from the pr oposed 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 abandon ment, we used OGC data to estimate the number of wells plugged and abandoned annually at the c ounty level. We then developed an estimate of the future number of wells in a production ar ea based on the number of existing wells in 2002, the number of new wells anticipated by the RMP a nd the estimated number of wells that would be abandoned based on the assumed persistence of historical aba ndonment rates. The calculation of a growth factor was thus accomplished as shown in Calculation 1.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-7 Calculation 1: Determination of CBM, oil and gas well growth factor based on BLM RMP 

# ( )

02 02 W W W W G P f − +

=

where: G = the 2002 to 2018 growth factor W 02 = the wells (oil/g as/CBM) active in 2002 W f = the wells (oil/gas/CBM) forecast to be added by 2018 W P = 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 tota l gas production was developed as shown in Calculation 2.

Calculation 2: Derivatio n of a gas production growth factor based on BLM RMP 

# ( ) ∑ ∑

− +

=

i i i i i i P i f i

gas W P P W W W G

, 02 , , , 02

* *

where: i refers to the three well types: oil, gas and CBM G gas = the 2002 to 2018 growth factor P i = the average 2002 production of an oil/gas/CBM well W 02,i = the oil/gas/CBM wells active in 2002 W f,i = the oil/gas/CBM wells forecast to be added by 2018 W P,i = the oil/gas/CBM wells estimated to be plugged and abandoned by 2018

In areas with coverage by a RMP, a separate grow th 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 inform ation 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, a nd 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 usi ng these growth factors is discussed below.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-8 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 gi ven 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 coun ties, 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 thre e distinct conditions: Counties enti rely 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 eigh t growth factors were applied to each of the emissions sources is stipulat ed in Tables 4-6 and 4-7.

Calculation 3. General formula for proj ecting process-specific emissions estimates

02 18 * E G E = where: E 18 = the emissions from a process in 2018 G = the growth factor for the process, as indicated in Tables 4-6 and 4-7 E 02 = the emissions from a process in 2002December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-9 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 EI A forecast regions or one inside and the other outside of a RMP area. Figure 4- 4 then displays the growth fact ors developed for gas production in the WRAP states. A complete list of the gr owth factors developed to project 2002 area source oil and gas emissions to 2018 is provided as Appendix D.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-10 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.December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-11 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 20 02. In those cases, the growth factor approach could not be applied. Instead, a method was de veloped whereby emissions were estimated based on the development forecast by the RMP and the av erage emissions associated with similar oil and gas sources in the same State. The gene ral 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

P P P E D E

, 02

, 18 * = where: E 18,P = the emissions from a process in 2018 D = the forecast development of process p in the area E 02,P = the state average emissions from process p in 2002

Counties where this method was applied were firs t identified when the in tersection 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 ha d no such wells in 2002. This number of 2018 oil, gas, CBM and/or drilled wells served as the activity m easure for the 2018 emissions estimates. State specific emission factors were de rived by dividing 2002 state tota l 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 adop ted. The emission factors that resulted for NOx are shown in Table 4-8. Emission factors fo r 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 0.12December 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-12 The emission factors in Table 4-8 were combin ed with development forecasts as shown in Calculation 4 to produce the county-level emissi ons shown in Table 4-9. These emissions estimates were then combined with the proj ected 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 contro l programs will have a substantial impact on future emissions. Known State and Federal emissi ons 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. T hus, although not presented here, the state-specific cont rols included in the 2002 i nventory are adopted by the 2018 inventory. A discussion of the controls identified by the 2002 inve ntory 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-igniti on 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 standardsDecember 2005

G:\WRAP SSJF O&G\Reporting\Docume ntation\Final\Sec4_2018emissions.doc 4-13 State Future Controls Action Colorado 1 • 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 thresh old, 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 po tential impact was uncertain. In other words, only “on-the-books” controls have been accounted for in this inventory. Due to the low inventory threshol d in the State of Colorado, those stat e-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 appl icable 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 em issions 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 em issions was performed by comparing the emission rates yielded by EPA’s NONROAD model for 750+ horsepower dr ill rig engines in 2018 versus those for the same category in 2002. For CBM pu mp engines, the adjustment was performed by comparing the emission rates given by the NONR OAD 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 f actors 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 c ounty control factor a nd the uncontrolled 2018 emissions estimate. The emission summaries presen ted at the beginning of this section represent the comprehensive 2018 oil and gas emissions estimates with “on-the-books” controls.December 2005

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CO OGCC, 2005. Well drilling and well production informati on provided by staff of the Colorado Oil and Gas Conserva tion Commission (Thom Kerr, thom.kerr@state.co.us ). March 21, 2005.

Daniels, 2005. Information on coalbed methane production in Utah provi ded 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

G:\WRAP SSJF O&G\Reporting\Document ation\Final\Sec5_References.doc 5-2 http://www.eia.doe.gov/pub/oil_gas/natural_ga s/analysis_publicati ons/maps/maps.htm#T op

. EIA, 2005. “Number of Producing Gas and Ga s Condensate Wells”. Energy Information Administration. Internet address: http://tonto.eia.doe.gov/dna v/ng/ng_prod_wells_s1_a.htm

. EIA, 2005b. “Annual Energy Outlook 2005 with Pr ojections to 2025”. Energy Information Administration. January. Internet address: http://www.eia.doe.gov/ oiaf/aeo/index.html

.

EPA. 2004. EPA’s NONROAD 2004 Emissi ons Model. Internet address: http://www.epa.gov/otaq/nonrdmdl.htm

. ERG. 2005a. "Quality Assurance of the 2002 WR AP Stationary Sources Emissions Inventory," Draft, December 5, 2005.

ERG. 2005b. "WRAP Point and Area Source Em issions Projections for the 2018 Base Case Inventory," Draft, December 21, 2005.

ERG/ENVIRON. 2005. "Point and Area Source Emission Inve ntories on Native American Reservations and Tribal Lands". Prepared for the Western Regional Air Partnership. December.

ERG/ENVIRON, 2005. "Point Source and Oi l and Gas Area Source Em ission Inventories on Native American Reservations and Tribal La nds." 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 informati on 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 i nventory 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 inve ntory efforts in the State of North Dakota provided by staff of the North Dakota De partment 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\Document ation\Final\Sec5_References.doc 5-3 NM ED, 2005b. Information on permitting and inve ntory efforts in New Mexico provided by staff of the New Mexico Environm ental 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 databa se 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 produc tion database for the State of New Mexico, maintained by New Mexico Institute of Mi ning 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 invent ory efforts in the State of Nevada provided by staff of the Nevada Division of E nvironmental Protection (Lori Campbell, loric@ndep.nv.gov ). March 9, 2005.

NV DM, 2005. Well drilling and well production in formation 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 pu mp efficiency provided by Joe Olson at Williams Exploration and Production. June 2005.

OR DEQ, 2005. Information on permitting and invent ory 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 Mine ral Industries (Robert Houston, robert.a.houston@mlrr.oregongeology.com ).

Pollution Solutions, 2005. Tyler/Longview/Mar shall Flexible Attainment Region Emission Inventory, Ozone Precursors, VOC, NOx and CO, 2002 Emissions.

Richmond, 2005. Information on coalbed meth ane 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 inve ntory efforts in the State of South Dakota provided by staff of the South Dakota Departme nt 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 & Natura l Resources, Minerals and Mining Program (Mack McGillivray, mack.mcgillivray@state.sd.us ). March 23, 2005.December 2005

G:\WRAP SSJF O&G\Reporting\Document ation\Final\Sec5_References.doc 5-4 Strong, 2005. Information on typical coalbed meth ane design provided by Gary Strong of the Wyoming Oil and Gas Conser vation Commission. June 2005.

UT DOGM, 2005. Well drilling and well production in formation 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 inve ntory efforts in the St ate 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 tubi ng installed in coalbed methane wells in Wyoming provided by a representative of W eatherford U.S., Gillette, Wyoming. June 2005.

Weatherford, 2005b. “Reciprocating Rod Lift Pu mping Units”. Weathe rford Artificial Lift Systems. Internet address: http://www.weatherford.com/weatherford/ groups/public/documents/general/wft003549.p df

WY OGCC, 2005. Well drilling an d well production information provided by staff of the Wyoming Oil and Gas Conservati on Commission (Robert Meyer, rmeyer2@state.wy.us ). March 18, 2005.

WY DEQ, 2005. Emissions factor s for drilling in Southwest Wy oming provided by staff of the Wyoming Department of Environmen tal 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 ge nerators 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 Depart ment 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, Ai r 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\Document ation\Final\Sec5_References.doc 5-5 WY BLM, 2005. Reasonable foreseeable develo pment scenario for the upcoming Pinedale Resource management plan provided by sta ff of the Wyoming BLM (Kelly Rotterford; Pinedale Field Office; Wyoming Bureau of Land Management; 307-367-5300). August.

WY BLM, 2001. “Reasonable Foreseeable Devel opment Scenario for Oil and Gas Development in the Buffalo Field Office Area, Campbell, Johnson, and Sheridan Counties, Wyoming”. Wyoming State Office, Bureau of Land Ma nagement. February. Cheyenne, WY.

CO BLM, 1996. “White River Resource Area; Proposed Resource Management Plan and Final Environmental Impact Statement”. Cr aig District, Colorado Bureau of Land Management. June. Craig, CO.

NM BLM, 2003. “Proposed Resource Manageme nt 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 Oi l and Gas Leasing Record of Decision”. R-1, Northern Region, USDA Forest Service and M ontana 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 Environm ental Impact Statement, Deso lation Flats Natural Gas Field Development Project”. Wyom ing State Office, Bureau of Land Management. May. Cheyenne, WY.

UT BLM, 2005. “Draft Resource Management Pl an and Environmental Impact Statement. Vernal Field Office, Utah Bureau of Land Management. January. Vernal, UT.

WY BLM, 2004b. “Final Environmental Imp act Statement for the Jack Morrow Hills Coordinated activity Plan/Proposed Gr een 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 Rive r Agency, Bureau of Indian Affairs. Fort Washakie, WY.

MT DEQ, 2003. “Statewide Oil and Gas Fi nal Environmental Impact Statement and Amendment of the Powder River and Billings Resource Management Plans”. Montana Department of Environmental Quality and th e 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 DocumentationDecember 2005

G:\WRAP SSJF O&G\Reporting\Documentation\Final\AppndxA_WYDEQ_EFs.doc A-2 Gas Wells – Completion Emissi ons from Flaring and Venting

Standardized statewide factors for VOC and HAP emissions associated with flaring and venting activities during gas well completions were crea ted using a weighted average statewide produced gas composition. The averaged analysis indica tes 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. Th is 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 fl ares burn when the entrained liquid volumes are low enough. Sometimes the flares are burning basi cally pure gas, while other times the flares don’t or won’t ignite when liqui d volumes are excessive. Sin ce 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, depe nding 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 ve nting are calculated as follows:

(5 MMCF/day) × (18.4565 lb/lb-mol) × (lb-mol/379 scf) × (10 6 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 completionDecember 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/compl etion 0.3652 total tons Xylene @ 50% vented/50% flared = 0.8 tons Xylene per well/completion 1.9479 total tons n-C 6 @ 50% vented/50% flared = 1.3 tons n-C 6 per well/completion undetectable e-Benzene

For NO X and CO emissions from flar ing, AP-42 flare emission fact ors were used as follows:

(5.0 MMCF/day) × (0.14 lb NO X /MMBtu) × (1000 Btu/SCF) × (10 6 SCF/MMCF) × (MMBtu/10 6 Btu) × (ton/2000 lb) = 0.35 tons NO X 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 comple tion operations flaring emissions are:

1.75 tons NO X & 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 ar e 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-mo l/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 stor age tank emissions were created by calculating the average compositions of condensate for each fo rmation 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. Th e 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 unc ontrolled. For wells that produce above 18.3 BPD of condensate controls would be insta lled, since the VOC em ission would be above the 30.0 TPY threshold used in 2002. The emis sion factors would then be 65.74 pounds per year (0.03 TPY) of VOCs per BPD and 2.32 pounds pe r 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 formul ate a weighted average for gas composition across the state, based on production per formation. Th e weighted average was then used with GRI GlyCalc modeling software to calculate emissi on factors based on one million standard cubic foot of gas per day (MSCFD) at 0.425 gpm or 25.0 sp m for a Kimray 4015 gl ycol pump. 25.0 spm is an observed average pump rate and th e 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 10 6 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 fu el used in these heat ers is estimated at 1000 Btu/scf. This activity resu lts 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 emissi ons 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 cr ude oil. The resulti ng 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 cen tral battery where various heated vessels are used for separation of crude a nd 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 estim ate 0.005 pounds per year of NO X per BPD and 0.001 pounds per yr of CO per BPD of oil production at each individu al 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\Document ation\Final\AppndxB_ SampleCalcs.doc B-1 Appendix B

Sample Calculations for the VOC and Minor NOx ProcessesDecember 2005

G:\WRAP SSJF O&G\Reporting\Document ation\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/Work ing/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 * Benzen e 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-w ell * 1 well / 2000 lb/ton * .586 Annual NOx = .51 tonsDecember 2005

G:\WRAP SSJF O&G\Reporting\Document ation\Final\AppndxB_ SampleCalcs.doc B-3 Pneumatic Devices VOC EF = .2 tons / year-well Annual VOC = VOC EF * Nu mber 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 pollu tants within the same proce ss 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/Work ing/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 BP D 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 * Nu mber of Wells * wdpy / dpy Annual VOC = 0.10 tons/yr per well * 1 well * .915 Annual VOC = 0.092 tonsDecember 2005

G:\WRAP SSJF O&G\Reporting\Document ation\Final\AppndxC_nonroad_diesel_S.doc C-1 Appendix C

Nonroad Diesel Fuel Sulfur LevelsDecember 2005

G:\WRAP SSJF O&G\Reporting\Document ation\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 0.240December 2005

G:\WRAP SSJF O&G\Reporting\Document ation\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 0.240December 2005

G:\WRAP SSJF O&G\Reporting\Document ation\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 0.240December 2005

G:\WRAP SSJF O&G\Reporting\Document ation\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 0.340December 2005

G:\WRAP SSJF O&G\Reporting\Document ation\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 0.270December 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\Final\AppndxD_GrowthFactors.doc D-1 Appendix D

2002 to 2018 Oil and Gas Growth FactorsDecember 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\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 1.3253December 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\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 1.3340December 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\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 1.0336December 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\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 1.1066December 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\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 1.4580December 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\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 2.3099December 2005

G:\WRAP SSJF O&G\Reporting\Documenta tion\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