# REGIONAL HAZE STATE IMPLEMENTATION PLAN FOR THE STATE OF ARIZONA

APPENDICES - VOLUME I

Appendix A-1 through Appendix A-9

Air Quality Division Arizona Department of Environmental Quality

### List of Appendices Arizona Regional Haze SIP 

## LIST OF APPENDICES

APPENDIX VOLUME I

APPENDIX A-1. BACKGROUND Appendix A-1a. Definitions Appendix A-1b. Arizona Department of Environmental Quality – Air Quality Division Organization Charts

APPENDIX A-2. DESCRIPTIONS OF ARIZONA Appendix A-2a. Bibliography for Chapter 2

APPENDIX A-5. ATTRIBUTABLE IMPAIRMENT Appendix A-5a. Arizona’s RAVI rule Appendix A-5b. Notification letters to FLMS on contact person, and Public Comment Period Appendix A-5c. Supporting Documents Related To The Promulgation Of Arizona’s RAVI Rule Appendix A-5d. New sour ce review rule-R18-2-410

APPENDIX A-6. CLEAN AIR CORRIDOR Appendix A-6a. WRAP Policy on Clean Air Corridors Appendix A-6b. WRAP Emission Tracking System and Assessment Process for the Clean Air Corridor

APPENDIX A-7. STATIONARY SOURCES Appendix A-7a. Arizona Draft Western Backstop SO2 Trading Program Rule Appendix A-7b. Proposed WRAP 309 Coordinating Committee Charter Appendix A-7c. WRAP Report on A ssessment of NOx/PM Strategies

APPENDIX A-8. SO2 MILESTONES/BACKSTOP Appendix A-8a. WRAP Market Trading Forum Non-Utility Sector Allocation Final Report from the Allocations Working Group (November 2002) Appendix A-8b. Western Emissions B ackstop (WEB) Emissions & Allowance Tracking Systerm (EATS) Analysis Appendix A-8c. Recommendations for Ma king Additional Determinations in the Context of Reasonably Attributable BART

APPENDIX A-9. MOBILE SOURCES Appendix A-9a. Arizona Mobile Source Work Group Findings and Recommendations Related to Mobile Source Emissions

### List of Appendices Arizona Regional Haze SIP 

## LIST OF APPENDICES (Cont.)

APPENDIX VOLUME II

APPENDIX A-10. FIRE PROGRAMS Appendix A-10a. WRAP report “Assessing St atus of Incorporating Smoke Effects into Fire Planning and Operation” Appendix A-10b. EPA’s “Interim Air Qual ity Policy on Wildland and Prescribed Fires” Appendix A-10c. Revised Arizona R18- 2-602, “Unlawful Open Burning” and Article 15, “Forest and Range Management Burns” Appendix A-10d. Supporting Documents Relate d to the Promulgation of Revised Arizona R18-2-602, “Unlawful Op en Burning” and Article 15, “Forest and Range Management Burns” Appendix A-10e. WRAP “Policy on Fire Tracking Systems” Appendix A-10f. WRAP report “Nonburni ng Alternatives for Vegetation and Fuel Management” Appendix A-10g. WRAP report “Burning Management Alternatives on Agricultural Lands in th e Western United States” Appendix A-10h. WRAP report “Enhanced Smoke Management Programs for Visibility” Appendix A-10i. Arizona Revised Statute 49-501 Appendix A-10j. WRAP report “Annual Emission Goals for Fire”

### List of Appendices Arizona Regional Haze SIP 

## LIST OF APPENDICES (Cont.)

APPENDIX VOLUME III

APPENDIX A-12. POLLUTION PREVENTION Appendix A-12a. Arizona Pollution Prev ention Work Group Review of WRAP Policy on Renewable Energy and Energy Conservation Appendix A-12b. Details of Renewabl e Energy Generation and Capacity Appendix A-12c. ICF Assessment of Renewable Energy and Energy Conservation Programs

APPENDIX A-13. OTHER GCVTC OPTIONS Appendix A-13a. Arizona’s Assessment of Other Recommendations Of The Grand Canyon Visibility Transport Commission Appendix A-13b. Summary of Discussi ons with Federal Land Managers on Emissions In-and-Near the F our Arizona GCVTC Class I Areas

APPENDIX A-14. PROJECTION OF VISIBILITY Appendix A-14a. Arizona Technical Re view Memoranda of WRAP Emission Inventories and Technical Support Document Appendix A-14b. Summary of Emission I nventories used in WRAP Modeling

APPENDIX A-18. PUBLIC PARTICIPATION Appendix A-18a. Notices of Public Hearings Appendix A-18b. Hearing Agendas, Si gn-in Sheets, Transcripts, and Certifications Appendix A-18c. Written Comments Received During Comment Period Appendix A-18d. Responsiveness SummaryAppendix A-1. Background Arizona Regional Haze SIP 

## APPENDIX A-1. BACKGROUND

This appendix contains work products a nd references relied u pon by Arizona in the development of Chapter 1 of the Regional Haze SIP.Appendix A-1. Background Arizona Regional Haze SIP 

## Appendix A-1a. DefinitionsAppendix A-1. Background Arizona Regional Haze SIP 

### Applicable definitions from 40 CFR 51.301:

BART-eligible source means an existing stationary facil ity as defined in this section.

Best Available Retrof it Technology (BART) means an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant, which is emitted by an existing stationary facility. The emission limitation must be established, on a case-by-case ba sis, taking into cons ideration the technology available, the costs of complia nce, the energy and non-air quality environmental impacts of compliance, any pollution control eq uipment in use or in existen ce at the source, the remaining useful life of the source, and th e degree of improvement in visibi lity which may reasonably be anticipated to result from the use of such technology.

Deciview means a measurement of visibility impair ment. A deciview is a haze index derived from calculated light extinction, such that uniform changes in haziness correspond to uniform incremental changes in perception across the entir e range of conditions, from pristine to highly impaired. The deciview haze index is calcula ted based on the following equation (for the purposes of calculating deciview, the atmospheric light extinction coefficient must be calculated from aerosol measurements):

Deciview haze index = 10 1n e 

### (b ext 

### /10 Mm -1 

### ). Where b ext 

### = the atmospheric light extinction coeffici ent, expressed in inverse megameters (Mm 1 

### ).

Existing stationary facility means any of the following stationary sources of air pollutants, including any reconstructed s ource, which was not in operati on prior to August 7, 1962, and was in existence on August 7, 1977, and ha s the potential to em it 250 tons per year or more of any air pollutant. In determining potential to emit, fugitiv e emissions, to the extent quantifiable, must be counted.

Fossil-fuel fired steam electric plants of mo re than 250 million British thermal units per hour heat input, Coal cleaning plants (thermal dryers), Kraft pulp mills, Portland cement plants, Primary zinc smelters, Iron and steel mill plants, Primary aluminum ore reduction plants, Primary copper smelters, Municipal incinerators capable of chargi ng more than 250 tons of refuse per day, Hydrofluoric, sulfuric, a nd nitric acid plants, Petroleum refineries, Lime plants, Phosphate rock processing plants, Coke oven batteries,Appendix A-1. Background Arizona Regional Haze SIP 

### Sulfur recovery plants, Carbon black plants (furnace process), Primary lead smelters, Fuel conversion plants, Sintering plants, Secondary metal production facilities, Chemical process plants, Fossil-fuel boilers of more than 250 million British thermal units per hour heat input, Petroleum storage and transfer faciliti es with a capacity exceeding 300,000 barrels, Taconite ore processing facilities, Glass fiber processing plants, and Charcoal production facilities.

Federal Class I area means any Federal land that is clas sified or reclassified Class I.

Federal Land Manager means the Secretary of the departme nt with authority over the Federal Class I area (or the Secretary's designee) or, with respect to Roosevelt- Campobello International Park, the Chairman of the Roosevelt-Ca mpobello International Park Commission.

Federally enforceable means all limitations and conditions which are enforceable by the Administrator under the Clean Air Act including those requirements developed pursuant to parts 60 and 61 of this title, requirements within a ny applicable State Implementation Plan, and any permit requirements established pursuant to S ec. 52.21 of this chapter or under regulations approved pursuant to part 51, 52, or 60 of this title.

Implementation plan means, for the purposes of this part, any State Implementation Plan, Federal Implementation Plan, or Tribal Implementation Plan.

Indian tribe or tribe means any Indian tribe, band, nation, or other organized group or community, including any Alaska Na tive village, which is federally recognized as eligible for the special programs and services provided by the Unite d States to Indians because of their status as Indians.

In existence means that the owner or operator ha s obtained all necessary preconstruction approvals or permits required by Federal, State, or local air pollution emissions and air quality laws or regulations and either has (1) begun, or caused to begin, a continuous program of physical on-site construction of th e facility or (2) entered into binding agreements or contractual obligations, which cannot be cancelled or modifi ed without substantial loss to the owner or operator, to undertake a program of construction of the facility to be completed in a reasonable time.

Least impaired days means the average visibility impairment (measured in deciviews) for the twenty percent of monitored days in a calenda r year with the lowest amount of visibility impairment.Appendix A-1. Background Arizona Regional Haze SIP 

### Major stationary source and major modification mean major stationa ry source and major modification, respectively, as defined in Sec. 51.166.

Mandatory Class I Federal Area means any area identified in part 81, subpart D of this title.

Most impaired days means the average visibility impairme nt (measured in deciviews) for the twenty percent of monitored days in a calendar year with the highest amount of visibility impairment.

Natural conditions includes naturally occurring phenomena th at reduce visibility as measured in terms of light extinction, visual range, contrast, or coloration.

Potential to emit means the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant includ ing air pollution control equipmen t and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation or the effect it would have on emissions is federally enforceable. Secondary emissions do not count in determining the potential to emit of a stationary source.

Reasonably attributable means attributable by visual obser vation or any other technique the State deems appropriate.

Reasonably attributable visibility impairment means visibility impairment that is caused by the emission of air pollutants from one , or a small number of sources.

Regional haze means visibility impairment that is cau sed by the emission of air pollutants from numerous sources located over a wide geographic area. Such sources include, but are not limited to, major and minor stationary source s, mobile sources, and area sources.

State means ``State'' as defined in section 302(d) of the CAA.

Stationary Source means any building, structure, facilit y, or installation, which emits or may emit any air pollutant.

Visibility impairment means any humanly perceptible change in visibility (light extinction, visual range, contrast, coloration) from that which would have existed under na tural conditions. Applicable Definitions from 40 CFR 51.309:

16 Class I areas means the following mandatory Class I Federal areas on the Colorado Plateau: Grand Canyon National Park, Sycamore Canyon Wild erness, Petrified Forest National Park, Mount Baldy Wilderness, San Pedro Parks Wild erness, Mesa Verde National Park, Weminuche Wilderness, Black Canyon of the Gunnison Wilderness, West Elk Wilderness, Maroon Bells Wilderness, Flat Tops Wilderness, Arches Na tional Park, Canyonlands National Park, Capital Reef National Park, Bryce Canyon Nati onal Park, and Zion National Park.Appendix A-1. Background Arizona Regional Haze SIP 

### Transport Region State means one of the States that is included within the Transport Region addressed by the Grand Canyon Visibility Tr ansport Commission (Arizona, California, Colorado, Idaho, Nevada, New Mexico, Oregon, Utah, and Wyoming).

Commission Report means the report of the Grand Canyon Visibility Transport Commission entitled Recommendations for Improving Western Vistas , dated June 10, 1996.

Fire means wildfire, wildland fire (including prescribed natural fire), prescribed fire, and agricultural burning con ducted and occurring on Federal, St ate, and privat e wildlands and farmlands.

Milestone means the maximum level of annual regiona l sulfur dioxide emissions for a given year, assessed annually consistent with paragra ph (h)(2) of this secti on beginning in the year 2003.

Mobile Source Emission Budget means the lowest level of VOC, NOx, SO 2 

### , elemental and organic carbon, and fine particles which are projected to occur in any area within the transport region from which mobile source emissions are determined to contribute significantly to visibility impairment in any of the 16 Class I areas.

Geographic enhancement means a method, procedure, or process to allow a broad regional strategy, such as a milestone or backstop market trading program designed to achieve greater reasonable progress than BART for regional haze, to accommodate BART for reasonably attributable impairment.

BHP San Manuel means: (i) The copper smelter located in San Manuel, Arizona which operated during 1990, but whose operations were suspende d during the year 2000, (ii) The same smelter in the event of a change of name or ownership.

Phelps Dodge Hidalgo means: (i) The copper smelter located in Hidalgo, New Mexico which operated during 1990, but whose operations were su spended during the year 2000, (ii) The same smelter in the event of a ch ange of name or ownership.

Definitions for the Fire Programs

Land Manager means any federal, state, local, or privat e entity that owns, administers, directs, oversees or controls the use of publ ic or private land, including the a pplication of fire to the land.

Prescribed fire orprescribed burn means any fire ignited by management actions to meet specific objectives, such as achieving resource benefits.

Wildland Fire Used for Resource Benefits means naturally ignited wild land fire that is managed to accomplish specific prestated resource management objectives in predefined geographic areas.Appendix A-1. Background Arizona Regional Haze SIP 

### Definitions for the Western Emission Backstop Trading Program Applicable to Sections 7 and 8 of Implementation Plan

EPA Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator’s duly authorized representative.

Floor allocation means the amount of allowances set by the Director in accordance with this Plan that represents the minimum necessary for a source to operate under stringent control assumptions.

Reducible allocation means the amount of allowances set by the Director in accordance with this Plan that represents, for each source, emissions in excess of the floor allocation that shall be reduced over time as the regional milestone is decreased.

Tribal Set-Aside means a 20,000-ton SO 2 

### WEB allowance allocated to tribes on an annual basis. The tribes will decide how to distribute the a llowances in the set-aside among tribes in the region. The set-side is intended to ensure equitable treatment for tribal economies and to prevent barriers to economic development.

Trigger refers to the activation of the WEB Trading Program for SO 2 

### in accordance with this Plan.

WEB Trading Program refers to the Western Backstop (WEB ) Trading Program Rule that shall be triggered as a backstop in accordance the provisions of this Plan to ensure that regional SO 2 

### emissions are reduced.

Western Regional Air Partnership (WRAP) means the collaborative effort of tribal governments, state governments, and federal agenci es to promote and monitor implementation of recommendations from the Grand Canyon Visib ility Transport Commi ssion authorized under Section 169B(f) of the Clean Air Act, and to address other common West ern regional air quality issues.Appendix A-2. Descriptions of Arizona Arizona Regional Haze SIP 

## Appendix A-1b. Arizona Department of Environmental Quality – Air Quality Division Organization ChartsAppendix A-2. Descriptions of Arizona Arizona Regional Haze SIPAppendix A-2. Descriptions of Arizona Arizona Regional Haze SIP 

## APPENDIX A-2. DESCRIPTIONS OF ARIZONA

This appendix contains work products and references relie d upon by Arizona in the development of Chapter 2 of the Regional Haze SIP.Appendix A-2. Descriptions of Arizona Arizona Regional Haze SIP 

## Appendix A-2a. Bibliography for Chapter 2Appendix A-2. Descriptions of Arizona Arizona Regional Haze SIP 

### Appendix A-2a. Bibliography for Chapter 2

Arizona Business . April 1999. “In 1990s, single-family sector drove AZ real estate.” Arizona State University (vol 46, No. 4).

Arizona Business . January 1998. “Arizona population lik ely to grow rapidly.” Arizona State University (vol 45, No. 1).

Arizona Business . May 1995. “AZ production of fruits, vegetables relatively high.” Arizona State University (vol 42, No. 5).

Arizona Business . June 1994. “Metro Phoenix one of the nation’s high-tech centers.” Arizona State University (vol 41, No. 6).

Arizona Department of Economic Secu rity. David Lillie. August 1986. A Demographic Guide To Arizona 1985. Population Statisti cs Unit, Report #14.

Arizona Department of Economic Security. State Data Center Newsletter. Spring 2001.

Berman, David R. 1998. Arizona Politics & Government: The Quest for Autonomy, Democracy, and Development . University of Nebraska Press, Lincoln.

Campbell, Julie A. 1998. Studies in Arizona History . Arizona Historical Society, Tucson.

Economic Outlook 03/04 . The University of Arizona. Eller College of Business and Public Administration.

Employment Security Commission of Arizona. August 1963. Arizona: A Century of Growth . Economics and Research Unit.

Hecht, Melvin E. and Richard W. Reeves. 1981. the Arizona Atlas . University of Arizona, Tucson. Office of Arid Lands Studies.

Mattern, Hal. June 5, 2001. The Arizona Republic . “Arizona was No. 1 for growth in > 90s” Web sites:

http://www.nps.gov/grca



### http://www.fs.fed.us/r3/ka i/recreation/wild_syc

http://www.wilderness.net/nwps/wilderness.cfm/Sycamore%20Canyon

http://www.americansouthwest .net/arizona/sycamore_canyon

http://www.cr.nps.gov/worldheritage/grcanAppendix A-2. Descriptions of Arizona Arizona Regional Haze SIP 

### Appendix A-2a. Bibliography for Chapter 2 (Continued)

http://www.petrifiedforest.areaparks.com/parkinformation

http://www.wmonline.com/attract/pforest/pforest

http://www.geo.arizona.edu/geos 256/azgeology/pwood/parkintro

http://cpluhna.nau.edu/Places/white_mountains

http://www.flyfishingworld.com/features/mwwhiteriver

http://geography.asu.edu/azclimate/narrativeAppendix A-5 – Attributable Impairment Arizona Regional Haze SIP 

## APPENDIX A-5. ATTRIBUTABLE IMPAIRMENT

This appendix contains work products a nd references relied u pon by Arizona in the development of Chapter 5 of the Regional Haze SIP.Appendix A-5 – Attributable Impairment Arizona Regional Haze SIP 

## Appendix A-5a. Arizona’s RAVI ruleArizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4541 Volume 9, Issue 43 

# NOTICES OF FINAL RULEMAKING

NOTICE OF FINAL RULEMAKING

TITLE 18. ENVIRONMENTAL QUALITY

CHAPTER 2. DEPARTMENT OF ENVIRONMENTAL QUALITY AIR POLLUTION CONTROL

PREAMBLE

1. Sections Affected Rulemaking Action R18-2-101 Amend Article 16 New Article R18-2-1601 New Section R18-2-1602 New Section R18-2-1603 New Section R18-2-1604 New Section R18-2-1605 New Section R18-2-1606 New Section

2. The statutory authority for the rulemaking, including both the authorizing statute (general) and the statutes the rules are implementing (specific) : Authorizing statutes: A.R.S. §§ 49-104(A)(11) and 49-425 Implementing statutes: A.R.S. §§ 49-414 and 49-414.01

3. The effective date of the rules: December 2, 2003

4. A list of all previous notices appearing in the Register addressing the final rules: Notice of Rulemaking Docket Opening: 9 A.A.R. 390, February 7, 2003 Notice of Proposed Rulemaking: 9 A.A.R. 763, March 7, 2003

5. The name and address of agency personnel with whom persons may communicate regarding the rulemaking : Name: Deborrah “Corky” Martinkovic Address: ADEQ, Air Quality Planning Section 1110 W. Washington Phoenix, AZ 85007Telephone: (602) 771-2372 (Any extension may be reached in-state by dialing 1-800-234-5677, and asking for a specific number.)
Fax: (602) 771-2366

E-mail: martinkovic.deborrah@ev.state.az.us

6. An explanation of the rules, including the agency’s reasons for initiating the rules : Summary. This rule sets forth the process Arizona Department of Environmental Quality (ADEQ) will use to determine whether Best Available Retrofit Technology (BART) will be required for sources determined to be contributing to visibility impairment in a mandatory Federal Class I area. Federal regulations allow Federal Land Managers (FLMs) to certify sources defined in 40 CFR 51.301 as potential contributors to visibility impairment in any of the Arizona mandatory Federal Class I areas under Section 169A of the Clean Air Act (CAA). Background. In 1977 Congress added a new section to the Clean Air Act - Section 169A, Visibility Protection for Federal Class I Areas - which established a national goal for, “ the prevention of any future, and the remedying of anyexisting impairment of visibility in mandatory class I Federal areas which impairment results from man-made air pollution. ” In addition, the section required states to submit state implementation plans (SIPs) requiring best availableretrofit technology (BART) for certain existing stationary sources found to cause or contribute to visibility impairThe Administrative Procedure Act requires the publication of the final rules of the state ’ s agencies. Final rules are those which have appeared in the Registerfirst as proposed rules and have been through the formal rulemaking process including approval by the Governor ’ s Regulatory Review Council or the Attorney General. The Secretary of State shall publish the notice along with the Preamble an d the full text in the next available issue of the Register after the final rules have been submitted for filing and publication.Volume 9, Issue 43 Page 4542 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

ment. On November 30, 1979, EPA promulgated a list of mandatory Federal Class I Areas (Class I areas) where visibility is an important value (44 FR 69122). There are 12 Class I areas identified in Arizona: Chiricahua NationalMonument Wilderness, Chiricahua Wilderness, Galiuro Wilderness, Grand Canyon National Park, Mazatzal Wilderness, Mount Baldy Wilderness, Petrified Forest National Park, Pine Mountain Wilderness, Saguaro Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore Canyon Wilderness (40 CFR 81.403). On December 2, 1980 (45 FR 80084), EPA defined the role of the FLMs in certifying visibility impairment in the mandatory Federal Class I areas. On November 24, 1987 (52 FR 45132), FLMs identified Petrified Forest National Park, Saguaro Wilderness, and Grand Canyon National Park, as having visibility impairment possibly attributable to stationary sources. Under the 1980 rule, if found to cause or contribute to the impairment, certain existing stationary sources operating in or near the identified Class I areas could be subject to BART (A list of sources eligible for the possible application of BART can be found at 40 CFR 51.301). On October 3, 1991, the Navajo Generating Station (NGS) was found by EPA to be causing or contributing to visibility impairment for the Grand Canyon National Parkand eligible for BART (56 FR 50172). BART control analyses were subsequently performed by EPA, and other parties through related court actions. Under the 1980 rule, the federal expectation is that actions for determination of possible source attribution will be performed by the states. Therefore, Arizona needs to be prepared to proceed with an attribution analysis and assessment for the application of controls upon any determination of a BART eligible source being the possible cause or contributor to visibility impairment in a Class I area. This rule addresses that need.

Current Conditions. ADEQ has determined that this rule applies to any source in existing stationary source categories identified in 40 CFR 51.301 that are operating in or near the mandatory federal Class I areas in Arizona. The source is an existing stationary facility that includes any reconstructed source that was not in operation prior to August 7, 1962, and was in existence on August 7, 1977, and has the potential to emit 250 tons per year of any regulated pollutant. ADEQ estimates that there are potentially 10 such sources within Arizona. “ In existence ” is interpreted by EPA to be consistent with the term, “ commence construction ” found in Prevention of Serious Deterioration (PSD) regulations (40 CFR 51.165(a)(1)(xvi) and 40 CFR 52.21(b)(9)). If construction commenced after August 7, 1977, the sourcewould be subject to the PSD/NSR (new source review) program (the state regulations are found at 18 A.C.C. 2, Article 4). However, EPA also notes “ that sources, are not BART eligible if the only change at the plant was the addition of pollution controls. For example, if the only change at a copper smelter during the 1962 through 1977 time period was the addition of acid plants for the reduction of SO 2 emissions, these emission controls would not themselves trigger a BART review. ” 1

[ 1 EPA proposed rule, 66 Federal Register 38119, July 20, 2001.] Under this rule, ADEQ, when analyzing an attributable source for BART controls, must consider several factors including, for example, costs, remaining useful life of the source, and degree of improvement anticipated to result from the application of the controls (the factors are detailed in R18-2-1605). Sources required by ADEQ to install and operate BART controls have a final opportunity to request exemption from the requirement prior to the application of controls. This opportunity for a federal exemption from BART, is contained in R18-2-1606, and 40 CFR 51.303. Summary. This rule outlines the process through which sources eligible for the application of BART will proceed ifcertified by the state of Arizona or an FLM as possibly causing or contributing to visibility impairment due to attribution. If found to be attributable for the impairment, a BART analysis will be performed to determine the level of controls necessary to remedy the impairment. This rule enables Arizona to fulfill the requirements of the Clean Air Act and the goal of section 169A of the Act to return the Nation ’ s federal parks and wilderness areas to natural conditions.

Section-by-Section Explanation for the Rules R18-2-1601 This Section lists the definitions that apply to this rule. R18-2-1602 This Section lists the Class I areas addressed by this rule for the applicable existing stationary facilities, as defined in R18-2-1601(2). R18-2-1603 This Section establishes the procedure for certification of impairment by either a Federal Land Manager with authority over a mandatory Federal Class I area, or the Director, should either believe there exists reasonably attributable visibility impairment in a Federal Class I area as listed in R18-2-1602. R18-2-1604 This Section establishes the procedure for an attribution analysis after certification of a source or group of sources as outlined in R18-2-1603. Upon completion of the attribution analysis, the procedure for the Director to issue draft and final attribution findings is outlined in R18-2- 1604(C). R18-2-1605 This Section establishes the best available retrofit technology (BART) analysis procedure aftera source is identified under R18-2-1604. Upon completion of the BART analysis, the procedure for the Director to issue draft and final BART findings, including alternatives to emission standards, is outlined in R18-2-1605(B) and (C), respectively. The specific conditions where BART would be satisfied due to past or planned actions by the facility are outlined in R18-2- 1605(D). EPA determinations regarding new technology that might require a BART analysisArizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4543 Volume 9, Issue 43for an applicable source, regardless of a source or small group of sources previously being certified and found attributable, are covered in R18-2-1605(E). R18-2-1606 This Section establishes the procedures for obtaining a federal exemption from a BART requirement.

7. A reference to any study relevant to the rules that the agency reviewed and either relied on in its evaluation of or justification for the rules or did not rely on in its evaluation of or justification for the rules, where the public may obtain or review each study, all data underlying each study, and any analysis of each study and other supporting material: None

8. A showing of good cause why the rules are necessary to promote a statewide interest if the rules will diminish a previous grant of authority of a political subdivision of this state: Not applicable

9. The summary of the economic, small business, and consumer impact: A. Rule Identification These rules amend R18-2-101 ( “ visibility impairment ” definition) and add new Sections R18-2-1601 through R18-2- 1606. For sources under ADEQ jurisdiction, the rules take the place of federal regulations that currently govern this

area. B. Entities Directly Impacted 1. Federal Land Managers. R18-2-1603 allows Federal Land Managers (FLMs) to certify visibility impairment in mandatory Class I areas. This was already allowed by federal rule. Under R18-2-1601 of the rule, the FLMs able to certify impairment in Arizona are with the United States Forest Service and the National Park Service. There are no FLMs in Arizona from the United States Fish and Wildlife Service, because this agency does not have jurisdiction over any of Arizona ’ s mandatory federal Class I areas. 2. ADEQ. R18-2-1604 requires ADEQ to identify stationary sources that could cause or contribute to the certified visibility impairment. Prior to this rule, this function was carried out by EPA. R18-2-1605 would require ADEQ to analyze for BART (best available retrofit technology) controls those sources identified as causing or contributing to visibility impairment. Prior to this rule, this function was carried out by EPA. The impact of this rule on ADEQ will primarily be on the Air Quality Division, Permits and Assessment sections, with a corresponding reduction of impact on EPA. 3. Stationary sources. R18-2-1605 also requires stationary sources identified in #2 to install or operate the BART asdetermined by the Director. Prior to this rule, only EPA determined and required BART. To determine impacted stationary sources, ADEQ staff reviewed Title V permits from ADEQ ’ s Air Permit files. Of the 26 industry categories listed in 40 CFR 51.301, only five categories were found to exist under ADEQ ’ s jurisdiction: steam electric plants, cement plants, primary copper smelters, lime plants, and industries using non-utility boilers. As a result, potentially 10 sources, representing 16 BART eligible units (boilers and kilns), could be affected by this rule. The combined potential to emit from these sources totaled 94,287 tons per year for NO x , 141,036 tons per year for SO 2 , and 12,146 tons per year for PM. The combined potential to emit for all pollutants for these 10 sources total approximately 250,000 tons per year. C. Probable Costs and Benefits Associated with the BART/Visibility Impairment Process 1. Direct Costs - FLMs: FLM activities to certify visibility impairment in mandatory Class I areas may involve preparation and analysis of monitoring data, emission inventories, meteorological records, etc. ADEQ estimates that this cost per certification could be as much as $50,000 if extensive analysis is conducted. These costs exist whether or not these rules became final. 2. Direct Costs - ADEQ: ADEQ costs related to identifying whether a BART eligible stationary source causes or contributes to visibility impairment in Class I areas are based on the activities identified in R18-2-1604(A). ADEQ estimates that these costs could range from $100,000

– 200,000 per attribution analysis, and be primarily borne by the ADEQ ’ s Air Quality Assessment Section. Costs related to analyzing identified sources for BART are based on the activities identified in R18-2-1605(A) and will be moderate, but less expensive than the attribution analysis. These costs will be primarily borne by ADEQ ’ s Permits Section. These costs will accrue to the state. Finally, incorporating BART into an existing state air quality permit may require additional resources from the Permits Section. However, these costs, unlike costs for the attribution and BART analysis, would be covered by permit revision fees paid by the source, and would have existed whether or not these rules became final. 3. Direct Costs - Stationary sources: If a source or small group of sources is found to cause or contribute to visibility impairment, and the BART determination requires installation of retrofit controls, the costs to sources required toinstall BART will be substantial. The total cost to install a technology similar to BART at the Navajo Generating Station was estimated by SRP to be in the hundreds of millions of dollars (51 Federal Register 50172, October 3, 1991). However, the example of the Navajo Generating Station shows costs to install technology similar to BART can result even where there is no state rule. According to EPA, “ Where a State defaults on its obligations under the visibilityVolume 9, Issue 43 Page 4544 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

regulations, EPA may act in place of the State pursuant to a FIP under section 110(c) of the Act, 42 U.S.C. 7410(c) 2

, and promulgate such limitation and measures as are required to achieve reasonable progress. ” (Ibid. at 50173, footnote not included). Although ADEQ is listing these costs for information purposes, ADEQ is not attributing any costs to install and operate BART to this rule because such requirements can be imposed by the federal government without any state rule.

Benefits. Two kinds of benefits are associated with this rule. The first benefit is derived from reduced emissions.Although, BART could be required to be installed on sources even without this state rule, it is helpful to list the emission benefits. When BART is installed, visibility is improved. Over four million recreation visits were made to Grand Canyon National Park in FY 2001. These visits generate substantial revenue in and for the state of Arizona. Other scenic resources could also be improved with the installation of BART, and, though less significant than the GrandCanyon, would enhance the tourism resources of Arizona, as well as the quality of life for Arizona citizens. In addition, reduction of visibility-impairing emissions also has health benefits.
The second benefit is through the replacement of federal regulation with state regulation. The lack of state regulationsimplementing BART results in Arizona sources being subject to federal regulation implemented by EPA from Washington and San Francisco, headquarters for EPA ’ s Region IX. These rules place the identification and analysis of BART sources with ADEQ rather than with EPA. Arizona is currently under a visibility Federal Implementation Plan (FIP), and one or two Arizona sources have considered or implemented technology similar to BART under federal rules. Because ADEQ already permits many of these sources, ADEQ will be more familiar with the various factors that go into the BART analysis. This would be a benefit to sources being regulated. ADEQ would be implementing the same BART rules that EPA does, with a resulting increase in costs for ADEQ and a decrease in costs for EPA.
This final rule further allows ADEQ to proceed with the implementation of the entire federal rule for visibility improvement. The rule addresses the requirements of 40 C.F.R. §§ 51.302

– 51.307. These sections must be satisfied before ADEQ can implement the requirements of 40 C.F.R. §§ 51.308 and 51.309. The plan to implement Section 309 must be submitted to EPA by December 31, 2003. D. Small Business Analysis

A.R.S. § 41-1055(B)(5) requires agencies to state the probable impact of a rulemaking on small businesses. A.R.S. § 41-1035 requires agencies to reduce the impact of a rule on small businesses by using certain methods when they are legal and feasible in meeting the statutory objectives for the rulemaking. These methods include: (1) exempting themfrom any or all rule requirements, (2) establishing performance standards which would replace any design or operational standards, or (3) instituting reduced compliance or reporting requirements. An agency may accomplish the third method by establishing less stringent requirements, consolidating or simplifying requirements, or setting less stringent schedules or deadlines.

“ Small business ” is defined in A.R.S. § 41-1001 as “ a concern, including its affiliates, which is independently owned and operated, which is not dominant in its field and which employs fewer than one hundred full-time employees or which had gross annual receipts of less than four million dollars in its last fiscal year. ” Interpreting this definition means that if a concern has annual gross receipts of more than four million dollars, but fewer than 100 employees, it would not be classified as a small business. ADEQ expects that none of the potential BART eligible sources will be classified as a small business. ADEQ ’ s conclusion is that this rule will not impact small business sources. However, if a BART eligible source would qualify as a small business, under federal rule, ADEQ could not establish different requirements for these small business sources. If there are any small businesses that sell, install, or maintain BART-related technology, they will benefit from this rule.
In the preliminary EIS, ADEQ requested comment and additional information relating to any of the conclusions reached above and did not receive any.

10. A description of the changes between the proposed rules, including supplemental notices, and final rules (if applicable): Changes were made with the cooperation of G.R.R.C. Staff to improve the clarity, conciseness and understandability of the rule. The changes are shown below: A new definition was placed at R18-2-101(71), to clarify a term used in the proposed definition of “ visibility impairment ” at R18-2-101(123):

71. “ Natural conditions ” includes naturally occurring phenomena that reduce visibility as measured in terms of light extinction, visual range, contrast, or coloration.
In addition, the word “ and ” was removed from the definition of “ visibility impairment, ” as shown:

123. 124. “ Visibility impairment ” means any humanly perceptible change in visibility (light extinction, visual range, contrast, and coloration) from that which would have existed under natural conditions. Both definitions are copied exactly from federal regulations at 40 CFR 51.308.Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4545 Volume 9, Issue 43 In addition, new Article 16 was amended as follows: ARTICLE 16. VISIBILITY; REGIONAL HAZE

R18-2-1601. Definitions In addition to the definitions contained in Articles 1 and 4 of this Chapter and A.R.S. § 49-401.01, the following definitions apply to this Article: 1. “ Best available retrofit technology (BART) ” means an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant that is emitted by an existing stationary facility. The emission limitation is established on a case-by-case basis in accordance with under R18-2-1605. 2. “ Existing stationary facility ” means any of the following stationary sources of air pollutants, including any reconstructed source, which was not in operation prior to before August 7, 1962, and was in existence on August 7, 1977, and has the potential to emit 250 tons per year or more of any air pollutant. In determining A person who determines potential to emit, shall count fugitive emissions, to the extent quantifiable, must be counted

. a. Fossil-fuel fired steam electric plants of more than 250 million British thermal units per hour heat input, ; b. Coal cleaning plants (thermal dryers), ; c. Kraft pulp mills, ; d. Portland cement plants, ; e. Primary zinc smelters, ; f. Iron and steel mill plants, ; g. Primary aluminum ore reduction plants, ; h. Primary copper smelters, ; i. Municipal incinerators capable of charging more than 250 tons of refuse per day, ; j. Hydrofluoric, sulfuric, and nitric acid plants, ; k. Petroleum refineries, ; l. Lime plants, ; m. Phosphate rock processing plants, ; n. Coke oven batteries, ; o. Sulfur recovery plants, ; p. Carbon black plants (furnace process), ; q. Primary lead smelters, ; r. Fuel conversion plants, ; s. Sintering plants, ; t. Secondary metal production facilities, ; u. Chemical process plants, ; v. Fossil-fuel boilers of more than 250 million British thermal units per hour heat input, ; w. Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels, ; x. Taconite ore processing facilities, ; y. Glass fiber processing plants, ; and z. Charcoal production facilities. 3. “ Federal Land Manager ” means the Secretary of the department, or the Secretary ’ s designee, with authority over the Federal Class I area. 4. “ Mandatory Federal Class I Area ” means any area identified in 40 CFR §§ 81.400-81.436. 5. “ Reasonably attributable ” means ascribable by visual observation or other techniques the Director deems appropriate described in R18-2-1604

. 6. “ Reasonably attributable visibility impairment ” means visibility impairment that is caused by the emission of air pollutants from one source, or a small group of sources.
R18-2-1602. ApplicabilityThis Article applies to any existing stationary source located in the state that may reasonably be anticipated to cause or contribute to visibility impairment in any mandatory Federal Class I area identified in 40 CFR §§ 81.401-81.436. Mandatory Federal Class I areas within Arizona are: Chiricahua National Monument Wilderness, Chiricahua Wilderness, Galiuro Wilderness, Grand Canyon National Park, Mazatzal Wilderness, Mount Baldy Wilderness, Petrified Forest National Park, Pine Mountain Wilderness, Saguaro Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore Canyon Wilderness.
R18-2-1603. Certification of Impairment A. A Federal Land Manager with authority over a mandatory Federal Class I area may certify to the Director, at any time, that there exists a reasonably attributable visibility impairment exists in the a mandatory Federal Class I area. The Director may also certify that there exists reasonably attributable visibility impairment exists in any mandatory Federal Class I area
as necessary to assure reasonable progress under section 169A(b)(2) of the Clean Air Act.Volume 9, Issue 43 Page 4546 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

B. Documentation from the affected Federal Land Manager or Director that supports the Federal Land Manager or Director ’ s certification shall include: 1. The mandatory Federal Class I area for which visibility impairment is being certified, 2. Any information documenting the basis for the certification of impairment.
R18-2-1604. Attribution Analysis; Finding A. Upon certification of reasonably attributable visibility impairment in any mandatory Federal Class I area If a mandatory Federal Class I area is certified as having reasonably attributable visibility impairment , the Director shall conduct an attribution analysis to identify each existing stationary source that may be reasonably anticipated to cause or contribute to visibility impairment. The Director shall notify the Federal Land Manager, affected source or small group of sources, and local air pollution control officer of the intent to conduct an attribution analysis. The attribution analysis shall be based o n the following: 1. Monitoring information obtained through the Arizona Class I Visibility Monitoring Network or special studies approved by ADEQ to ascertain: a. The times visibility impairment occurred, and b. The pollutants contributing to the visibility impairment. ; 2. Transport analysis or air quality modeling based upon meteorological records to ascertain whether the pollutants were transported to the mandatory Federal Class I area. ; 3. Other available studies, modeling analyses, and emissions inventories of point, area, and mobile source emissions to ascertain: a. The pollutant or pollutants causing the impairment, and b. The source, or a small group of sources, emitting the impairing pollutant; or pollutants. 4. Other relevant supporting documentation provided by the Federal Land Manager or Director used to make the draft attribution analysis finding. ; and 5. Consideration of any documentation provided by the source, or a small group of sources. , or other interested parties

. B. In conducting the attribution analysis, the Director shall use monitoring information, meteorological records, and emissions inventories that represent times and locations reasonably concurrent with the visibility impairment. C. The Director shall issue a draft attribution finding that impairment has or has not occurred, and provide public notice of the draft attribution finding. The Director shall publish notice of the draft attribution finding in a newspaper of general cir

culation in each county containing the mandatory Federal Class I area and the affected source. The Director shall provide at least 30 days from the date of the notice for public comment. Written comments to the Director shall include the name of the person and the person ’ s agent or attorney, if any, and shall clearly set forth reasons why the Director should review the draft attribution finding should be reviewed . The Director shall issue A a final attribution finding shall be issued after the public comment period. If the Director finds existing stationary sources found to cause or contribute to visibility impairment in a mandatory Federal Class I area, the source shall be subject to a BART Control Analysis under R18-2- 1605.
R18-2-1605. BART Control Analysis; Finding A. The Director shall analyze for BART controls each existing stationary source for which a final attribution finding is made under R18-2-1604(C). The Director shall consider the following factors: 1. Available control technology; 2. New source performance standards (NSPS) as adopted in Article 9; 3. Alternative control systems if retrofitting to comply with applicable NSPS standards adopted in Article 9 is found infeasible. ; 4. Cost of compliance; 5. Energy and non-air quality environmental impacts of compliance; 6. Existing pollution control technology in use at the source or small group of sources; 7. Remaining useful life of the source or small group of sources; 8. Net environmental impact associated with the proposed emission control system; 9. Economic impacts associated with installing and operating the proposed emission control system; and 10. Degree of improvement in visibility anticipated to result from application of the proposed emission control system. B. The Director shall issue a draft BART finding, and provide public notice of the draft BART finding. The Director shall publish notice of the draft BART finding in a newspaper of general circulation in each county containing the mandatoryFederal Class I area and the affected source. The Director shall provide at least 30 days from the date of the notice for public comment. Written comments to the Director shall include the name of the person and the person ’ s agent or attorney, and shall clearly set forth reasons why the Director should review the draft BART finding should be reviewed . The Director shall issue a final BART finding after the public comment period. 1. The Director shall submit each final BART finding that an existing stationary source is required to meet BART to the Administrator as a revision to the state implementation plan ( SIP)

.Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4547 Volume 9, Issue 43 2. The Director shall require that each existing stationary source meet BART as expeditiously as practicable but in no case later than five years after EPA approval of the revision to Arizona ’ s State Implementation Plan SIP revision

. C. If the Director determines that technological or economic limitations on the applicability of measurement methodology to a particular existing stationary source would make the imposition of an emission standard infeasible, the Director may, as part of the finding under subsection (B), instead prescribe a design, equipment, work practice, or other operational standard, or combination thereof of design, equipment, work practice, or operational standard . Such The standard, to the degree possible, is to shall set forth the emission reduction to be achieved by implementation of such the design, equipment, work practice, or operation, and must shall provide for compliance by means which that achieve equivalent results.
D. The Director shall make a finding that the attributable source has satisfied satisfies the BART requirement if the attributable source has : 1. Voluntarily applied applies best available retrofit technology; 2. Previously applied emission control standards equivalent to BART; or 3. Agreed Agrees to shutdown or curtail operations at the attributable source within 5 five years of the finding. An attributable source that does not shutdown or curtail operations shall proceed to meet BART as expeditiously as practicable, but in no case later than five years after EPA ’ s approval of the revision to Arizona ’ s State Implementation Plan the SIP

. E. If the Director determines that the imposition of BART or a standard pursuant to under subsection (C) of this section is not feasible infeasible at the time of the finding, the Director shall require the attributable source shall be required to install and operate BART upon a determination by the Director at a later date when the Director determines that BART or equivalent controls are now feasible.
F. The Director shall provide for a BART control analysis of any existing stationary source that might cause or contribute to impairment of visibility in any mandatory Federal Class I area identified under this Article at such times, as determined by the Administrator, determines new control technology for control of the pollutant becomes reasonably available if: 1. The pollutant is emitted by that existing stationary source, 2. Controls representing BART for the pollutant have not previously been required under this Article, and 3. The impairment of visibility in any mandatory Federal Class I area is reasonably attributable to the emissions of that pollutant.
R18-2-1606. Exemption from BART Any existing stationary source required to install, operate, and maintain BART pursuant to under this Article, may apply to the Administrator for an exemption from that requirement according to 40 CFR 51.303. by obtaining prior written concurrence from the Director according to 40 CFR 51.303. The existing stationary source shall obtain the Director ’ s written concurrence before sending the application for exemption to the Administrator. 11. A summary of the comments made regarding the rules and the agency response to them:ADEQ received one written comment. It expressed general support for the rules and for protecting visibility in Arizona ’ s Class I parks and wilderness areas.

Comment: ADEQ received an oral comment that the word “ facility ” should be replaced by “ source ” in the definitions of “ best available retrofit technology ” and “ existing stationary facility ” to be consistent with the rest of the rule.
Response: ADEQ has kept these definitions the same as the federal definitions to ensure consistency. The definitions use the term “ source ” to define the terms, and “ source ” is used thereafter in the rules. ADEQ is not aware of any inconsistency.

12. Any other matters prescribed by statute that are applicable to the specific agency or to any specific rule or class of rules: Not applicable

13. Incorporations by reference and their location in the rules: Not applicable

14. Were these rules previously adopted as emergency rules?
No

15. The full text of the rules follows:

TITLE 18. ENVIRONMENTAL QUALITY

CHAPTER 2. DEPARTMENT OF ENVIRONMENTAL QUALITY AIR POLLUTION CONTROLVolume 9, Issue 43 Page 4548 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

ARTICLE 1. GENERAL

Section R18-2-101. Definitions ARTICLE 16. VISIBILITY; REGIONAL HAZE

Section R18-2-1601 . Definitions R18-2-1602. Applicability R18-2-1603. Certification of Impairment R18-2-1604. Attribution Analysis; Finding R18-2-1605. BART Control Analysis; Finding R18-2-1606. Exemption from BART

ARTICLE 1. GENERAL

R18-2-101. Definitions In addition to the definitions prescribed in A.R.S. §§ 49-101, 49-401.01, 49-421, 49-471, and 49-541, in this Chapter, unless otherwise specified: 1. No change 2. No change a. No change b. No change c. No change d. No change e. No change 3. No change 4. No change 5. No change 6. No change 7. No change 8. No change 9. No change 10. No change a. No change b. No change c. No change d. No change e. No change f. No change 11. No change a. No change b. No change c. No change 12. No change 13. No change 14. No change a. No change b. No change 15. No change 16. No change 17. No change 18. No change 19. No change 20. No change 21. No change 22. No change 23. No change 24. No change 25. No change 26. No changeArizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4549 Volume 9, Issue 43 27. No change a. No change b. No change 28. No change 29. No change 30. No change 31. No change 32. No change 33. No change 34. No change 35. No change 36. No change 37. No change 38. No change 39. No change 40. No change 41. No change 42. No change a. No change b. No change c. No change d. No change e. No change f. No change g. No change h. No change i. No change j. No change k. No change l. No change 43. No change 44. No change a. No change b. No change c. No change d. No change 45. No change 46. No change 47. No change 48. No change 49. No change 50. No change 51. No change 52. No change 53. No change 54. No change 55. No change 56. No change 57. No change a. No change b. No change c. No change d. No change e. No change f. No change g. No change h. No change i. No change j. No changeVolume 9, Issue 43 Page 4550 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

58. No change 59. No change 60. No change 61. No change 62. No change 63. No change a. No change b. No change c. No change i. No change ii. No change iii. No change iv. No change v. No change (1) No change (2) No change vi. No change vii. No change viii. No change (1) No change (2) No change ix. No change (1) No change (2) No change x. No change xi. No change 64. No change a. No change b. No change i. No change ii. No change c. No change i. No change ii. No change iii. No change iv. No change v. No change vi. No change vii. No change viii. No change ix. No change x. No change xi. No change xii. No change xiii. No change xiv. No change xv. No change xvi. No change xvii.No change xviii.No change xix. No change xx. No change xxi. No change xxii.No change xxiii.No change xxiv.No change xxv.No change xxvi.No change xxvii.No changeArizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4551 Volume 9, Issue 43 65. No change 66. No change 67. No change 68. No change 69. No change 70. No change 71. “ Natural conditions ” includes naturally occurring phenomena that reduce visibility as measured in terms of light extinction, visual range, contrast, or coloration. 71. 72. No change 72. 73. No change a. No change i. No change ii. No change b. No change i. No change ii. No change c. No change d. No change e. No change f. No change i. No change ii. No change iii. No change iv. No change g. No change 73. 74. No change 74. 75. No change 75. 76. No change 76. 77. No change 77. 78. No change 78. 79. No change 79. 80. No change 80. 81. No change 81. 82. No change 82. 83. No change 83. 84. No change a. No change b. No change c. No change d. No change 84. 85. No change 85. 86. No change 86. 87. No change 87. 88. No change 88. 89. No change 89. 90. No change 90. 91. No change 91. 92. No change 92. 93. No change 93. 94. No change 94. 95. No change a. No change b. No change c. No change d. No change 95. 96. No change 96. 97. No change 97. 98. No change a. No changeVolume 9, Issue 43 Page 4552 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

b. No change c. No change d. No change e. No change 98. 99. No change a. No change i. No change ii. No change iii. No change iv. No change v. No change vi. No change vii. No change b. No change c. No change 99. 100. No change a. No change b. No change 100. 101. No change 101. 102. No change 102. 103. No change 103. 104. No change 104. 105. No change a. No change b. No change c. No change d. No change 105. 106. No change 106. 107. No change 107. 108. No change a. No change b. No change 108. 109. No change 109. 110. No change 110. 111. No change 111. 112. No change 112. 113. No change 113. 114. No change 114. 115. No change 115. 116. No change 116. 117. No change 117. 118. No change a. No change b. No change c. No change d. No change e. No change f. No change g. No change h. No change i. No change j. No change k. No change l. No change m. No change n. No change o. No change p. No change q. No changeArizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4553 Volume 9, Issue 43 r. No change s. No change t. No change u. No change v. No change w. No change x. No change y. No change z. No change aa. No change bb. No change cc. No change dd. No change ee. No change ff. No change gg. No change hh. No change ii. No change jj. No change kk. No change ll. No change mm.No change nn. No change oo. No change pp. No change qq. No change rr. No change ss. No change tt. No change uu. No change vv. No change ww. No change xx. No change 118. 119. No change 119. 120. No change 120. 121. No change 121. 122. No change 122. 123. No change 123. 124. “ Visibility impairment ” means any humanly perceptible change in visibility (light extinction, visual range, contrast, coloration ) from that which would have existed under natural conditions. 124. 125. No change 125. 126. No change a. No change b. No change c. No change d. No change e. No change f. No change g. No change h. No change i. No change j. No change k. No change l. No change m. No change n. No change o. No change p. No change q. No changeVolume 9, Issue 43 Page 4554 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

r. No change s. No change t. No change u. No change v. No change w. No change x. No change y. No change z. No change aa. No change bb. No change cc. No change dd. No change ee. No change ff. No change gg. No change hh. No change ii. No change jj. No change kk. No change ll. No change mm.No change nn. No change oo. No change pp. No change qq. No change rr. No change ss. No change i. No change ii. No change iii. No change iv. No change 126. 127. No change
ARTICLE 16. VISIBILITY; REGIONAL HAZE

R18-2-1601. Definitions In addition to the definitions contained in Articles 1 and 4 of this Chapter and A.R.S. § 49-401.01, the following definitions apply to this Article: 1. “ Best available retrofit technology (BART) ” means an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant emitted by an existing stationary facility. The emission limitation is established on a case-by-case basis under R18-2-1605. 2. “ Existing stationary facility ” means any of the following stationary sources of air pollutants, including any reconstructed source, which was not in operation before August 7, 1962, and was in existence on August 7, 1977, and has the potential to emit 250 tons per year or more of any air pollutant. A person who determines potential to emit shall count fugitive emissions to the extent quantifiable.

a. Fossil-fuel fired steam electric plants of more than 250 million British thermal units per hour heat input; b. Coal cleaning plants (thermal dryers);

c. Kraft pulp mills; d. Portland cement plants;

e. Primary zinc smelters; f. Iron and steel mill plants;
g. Primary aluminum ore reduction plants; h. Primary copper smelters; i. Municipal incinerators capable of charging more than 250 tons of refuse per day; j. Hydrofluoric, sulfuric, and nitric acid plants; k. Petroleum refineries; l. Lime plants;

m. Phosphate rock processing plants;

n. Coke oven batteries;Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

October 24, 2003 Page 4555 Volume 9, Issue 43 o. Sulfur recovery plants;
p. Carbon black plants (furnace process);
q. Primary lead smelters;

r. Fuel conversion plants;

s. Sintering plants;
t. Secondary metal production facilities;

u. Chemical process plants;

v. Fossil-fuel boilers of more than 250 million British thermal units per hour heat input;

w. Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels;

x. Taconite ore processing facilities;
y. Glass fiber processing plants; and

z. Charcoal production facilities. 3. “ Federal Land Manager ” means the secretary of the department, or the secretary ’ s designee, with authority over the Federal Class I area. 4. “ Mandatory Federal Class I Area ” means any area identified in 40 CFR 81.400 through 81.436. 5. “ Reasonably attributable ” means ascribable by visual observation or other techniques described in R18-2-1604. 6. “ Reasonably attributable visibility impairment ” means visibility impairment that is caused by the emission of air pollutants from one source, or a small group of sources.

R18-2-1602. ApplicabilityThis Article applies to any existing stationary source located in the state that may reasonably be anticipated to cause or contribute to visibility impairment in any mandatory Federal Class I area identified in 40 CFR 81.401 through 81.436. MandatoryFederal Class I areas within Arizona are: Chiricahua National Monument Wilderness, Chiricahua Wilderness, Galiuro Wilderness, Grand Canyon National Park, Mazatzal Wilderness, Mount Baldy Wilderness, Petrified Forest National Park, PineMountain Wilderness, Saguaro Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore Canyon Wilderness.
R18-2-1603. Certification of Impairment A. A Federal Land Manager with authority over a mandatory Federal Class I area may certify to the Director, at any time,that a reasonably attributable visibility impairment exists in a mandatory Federal Class I area. The Director may also certify that reasonably attributable visibility impairment exists in any mandatory Federal Class I area to assure reasonable progress under section 169A(b)(2) of the Clean Air Act. B. Documentation that supports the Federal Land Manager or Director ’ s certification shall include: 1. The mandatory Federal Class I area for which visibility impairment is being certified, 2. Any information documenting the basis for the certification of impairment.

R18-2-1604. Attribution Analysis; Finding A. If a mandatory Federal Class I area is certified as having reasonably attributable visibility impairment, the Director shall conduct an attribution analysis to identify each existing stationary source that may be reasonably anticipated to cause or contribute to visibility impairment. The Director shall notify the Federal Land Manager, affected source or small group of sources, and local air pollution control officer of the intent to conduct an attribution analysis. The attribution analysis sha ll be based on the following: 1. Monitoring information obtained through the Arizona Class I Visibility Monitoring Network or special studies approved by ADEQ to ascertain:

a. The times visibility impairment occurred, and b. The pollutants contributing to the visibility impairment; 2. Transport analysis or air quality modeling based upon meteorological records to ascertain whether the pollutants were transported to the mandatory Federal Class I area; 3. Other available studies, modeling analyses, and emissions inventories of point, area, and mobile source emissions to ascertain:

a. The pollutant causing the impairment, and b. The source, or a small group of sources, emitting the pollutant; 4. Other relevant supporting documentation provided by the Federal Land Manager or Director used to make the draft attribution analysis finding; and 5. Consideration of any documentation provided by the source, a small group of sources, or other interested parties. B. In conducting the attribution analysis, the Director shall use monitoring information, meteorological records, and emissions inventories that represent times and locations reasonably concurrent with the visibility impairment. C. The Director shall issue a draft attribution finding that impairment has or has not occurred, and provide public notice of the draft attribution finding. The Director shall publish notice of the draft attribution finding in a newspaper of general cir

culation in each county containing the mandatory Federal Class I area and the affected source. The Director shall provide at least 30 days from the date of the notice for public comment. Written comments to the Director shall include the nameVolume 9, Issue 43 Page 4556 October 24, 2003 Arizona Administrative Register / Secretary of State Notices of Final Rulemaking

of the person and the person ’ s agent or attorney, if any, and shall clearly set forth reasons why the Director should review the draft attribution finding. The Director shall issue a final attribution finding after the public comment period. If the Director finds existing stationary sources cause or contribute to visibility impairment in a mandatory Federal Class I area, the source shall be subject to a BART Control Analysis under R18-2-1605.

R18-2-1605. BART Control Analysis; Finding
A. The Director shall analyze for BART controls each existing stationary source for which a final attribution finding is made under R18-2-1604(C). The Director shall consider the following factors:
1. Available control technology;
2. New source performance standards (NSPS) in Article 9;
3. Alternative control systems if retrofitting to comply with applicable NSPS standards in Article 9 is infeasible;
4. Cost of compliance;
5. Energy and non-air quality environmental impacts of compliance;
6. Existing pollution control technology in use at the source or small group of sources;
7. Remaining useful life of the source or small group of sources;
8. Net environmental impact associated with the proposed emission control system;
9. Economic impacts associated with installing and operating the proposed emission control system; and
10. Degree of improvement in visibility anticipated to result from application of the proposed emission control system.
B. The Director shall issue a draft BART finding, and provide public notice of the draft BART finding. The Director shall publish notice of the draft BART finding in a newspaper of general circulation in each county containing the mandatoryFederal Class I area and the affected source. The Director shall provide at least 30 days from the date of the notice for public comment. Written comments to the Director shall include the name of the person and the person ’ s agent or attorney, and shall clearly set forth reasons why the Director should review the draft BART finding. The Director shall issue a final BART finding after the public comment period.
1. The Director shall submit each final BART finding to the Administrator as a revision to the SIP.
2. The Director shall require that each existing stationary source meet BART as expeditiously as practicable but in no case later than five years after EPA approval of the SIP revision.
C. If the Director determines that technological or economic limitations on the applicability of measurement methodology to a particular existing stationary source would make the imposition of an emission standard infeasible, the Director may, aspart of the finding under subsection (B), prescribe a design, equipment, work practice, operational standard, or combination of design, equipment, work practice, or operational standard. The standard, to the degree possible, shall set forth theemission reduction to be achieved by implementation of the design, equipment, work practice, or operation, and shall provide for compliance by means that achieve equivalent results.
D. The Director shall make a finding that the attributable source satisfies the BART requirement if the attributable source:
1. Voluntarily applies best available retrofit technology;
2. Previously applied emission control standards equivalent to BART; or
3. Agrees to shutdown or curtail operations at the attributable source within five years of the finding. An attributable source that does not shutdown or curtail operations shall meet BART as expeditiously as practicable, but in no case later than five years after EPA ’ s approval of the revision to the SIP.
E. If the Director determines that the imposition of BART or a standard under subsection (C) is infeasible at the time of the finding, the Director shall require the attributable source to install and operate BART at a later date when the Director determines that BART or equivalent controls are feasible.
F. The Director shall provide for a BART control analysis of any existing stationary source that might cause or contribute toimpairment of visibility in any mandatory Federal Class I area identified under this Article at such time as the Administrator determines new control technology for the pollutant becomes reasonably available:
1. The pollutant is emitted by that existing stationary source,
2. Controls representing BART for the pollutant have not previously been required under this Article, and
3. The impairment of visibility in any mandatory Federal Class I area is reasonably attributable to the emissions of that pollutant.

R18-2-1606. Exemption from BARTAny existing stationary source required to install, operate, and maintain BART under this Article, may apply to the Administrator for an exemption from that requirement according to 40 CFR 51.303. The existing stationary source shall obtain the Director ’ s written concurrence before sending the application for exemption to the Administrator.Appendix A-5 – Attributable Impairment Arizona Regional Haze SIP 

## Appendix A-5b. Notification letters to FLMS on contact person, and Public Comment Period3033 North Central Avenue, Phoenix, Arizona 85012, (602)207-2300 AQDPLN00:088



### ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY

Governor Jane Dee Hull Jacqueline E. Schafer, Director



### April 13, 2000

Eleanor Townes
US Forest Services 517 Gold Avenue SW Region Albuquerque, New Mexico 87105

Dear Ms. Townes:

I am writing to welcome your participation in the Arizona Department of Environmental Quality’s (ADEQ) efforts to improve visibility in our Class I areas. One of our duties under the EPA Regional Haze Regulations (64 Fed. Reg. 35,714, July 1, 1999) is to notify you of our state contact person for regional haze issues. Mike George, Assessment Section Manager, Air Quality Division, has been assigned this responsibility. He can be reached at ( 602)207-2274. General inquiries may also be directed to Corky Martinkovic of the Air Quality Planning Section at (602)207-2372.

ADEQ will also send written notices to all affected federal land managers of public hearings to be held prior to submittal of a related State Implementation Plan (SIP) to EPA. Arizona is presently under a Federal Implementation Plan (FIP) for reasonably attributable visib ility impairment, but is developing a SIP revision to replace the FIP. You will receive an official notice when the public hearing date is finalized, which is expected to be later this year. A draft SIP will be included with the notice of public hearing date for review and comment. Further, affected federal land managers will be notified of applicable rulemaking activities.

ADEQ looks forward to working with you to protect our clean air resource. If you have questions or comments, you may contact me at (602)207-2308, or M ike and Corky at the above phone
numbers.

Sincerely,

Nancy C. Wrona, Director Air Quality Division3033 North Central Avenue, Phoenix, Arizona 85012, (602)207-2300 

### cc: Mike George, ADEQ Theresa Pella, ADEQ Pete Lahm, ADEQ

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Joseph Alston, Federal Land Manager Grand Canyon National Park P.O. Box 129 Grand Canyon, AZ 86023

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Alston:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Joseph Alston

### August 22, 2003 Page 2

cc: Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Lee Baiza, Federal Land Manager Petrified Forest National Park P.O. Box 2217 Petrified Forest, AZ 86028

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Baiza:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division

### Lee Baiza August 22, 2003 Page 2

cc: Joseph Alston Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Carl Bowman, Federal Land Manager Grand Canyon National Park P.O. Box 129 Grand Canyon, AZ 86023

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Bowman:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Carl Bowman

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Ms. Sarah Craighead, Federal Land Manager Saguaro National Monument 3693 S. Old Spanish Trail Tucson, AZ 85730

Re: Arizona’s Regional Haze State Implementation Plan

Dear Ms. Craighead:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Sarah Craighead

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Harv Forsgren, Federal Land Manager U.S. Forest Service – Southwest Region 333 Broadway SE Albuquerque, NM 87102

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Forsgren:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Harv Forsgren

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Michael King Pete Lahm Neil Mangum John McGee Colleen McKaughan Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Michael King, Federal Land Manager Pine Mountain Wilderness 344 S. Cortez Street Prescott, AZ 86303

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Siderits:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Michael King

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Sideritz Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Pete Lahm, Federal Land Manager U.S. Forest Service c/o Arizona Department of Environmental Quality 1110 W. Washington Street, 3415A-3 Phoenix, AZ 85007

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Lahm:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Pete Lahm

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Neil Mangum John McGee Colleen McKaughan Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Neil Mangum, Federal Land Manager Chiricuahua National Park 13063 E. Boenito Canyon Wilcox, AZ 85643

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Mangum:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Neil Mangum

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. John McGee, Federal Land Manager Galiuro Wilderness 300 W. Congress Tucson, AZ 85701

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. McGee:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division John McGee

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Bruce Polkowsky, Federal Land Manager National Park Service P.O. Box 25287 Denver, CO 80225

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Polkowsky:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Bruce Polkowsky

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum John McGee Colleen McKaughan Joseph Mikitish Nora Rasure Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Ms. Nora Rasure, Federal Land Manager Sycamore Canyon Wilderness 2323 E. Greenlaw Lane Flagstaff, AZ 86004

Re: Arizona’s Regional Haze State Implementation Plan

Dear Ms. Rasure:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Nora Rasure

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Chris Shaver Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Ms. Chris Shaver, Federal Land Manager National Park Service P.O. Box 25287 Denver, CO 80225

Re: Arizona’s Regional Haze State Implementation Plan

Dear Ms. Shaver:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Chris Shaver

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum John McGee Colleen McKaughan Joseph Mikitish Bruce Polkowsky Nora Rasure Karl Siderits Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Karl Siderits, Federal Land Manager Sierra Ancha/Superstition/Mazatzal Wildernesses 2324 E. McDowell Road Phoenix, AZ 85006

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Siderits:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Karl Siderits

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Mike Williams Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Mr. Mike Williams, Federal Land Manager Sycamore Canyon Wilderness 800 S. 6 th 

### Street Williams, AZ 86046

Re: Arizona’s Regional Haze State Implementation Plan

Dear Mr. Williams:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Mike Williams

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Elaine Zieroth

# A RIZONA 

# D EPARTMENT
OF 

# E NVIRONMENTAL 

# Q UALITY

1110 West Washington Street y Phoenix, Arizona 85007 (602) 771-2300 y www.adeq.state.az.us Janet Napolitano Governor Stephen A. Owens Director

Northern Regional Office 1515 East Cedar Avenue y Suite F y Flagstaff, AZ 86004 (928) 779 0313 Southern Regional Office 400 West Congress Street y Suite 433 y Tucson, AZ 85701 (520) 628 6733
Printed on rec y

cled p a

p

e

r 

### August 22, 2003

Ms. Elaine Zieroth, Federal Land Manager Mt. Baldy Wilderness P.O. Box 640 Springerville, AZ 85938

Re: Arizona’s Regional Haze State Implementation Plan

Dear Ms. Zieroth:

The purpose of this letter is to provide notice to you in accord ance with 40 CFR 51.302(a)(2)(ii), regarding the availability of a draft Regional Haze State Implemen tation Plan (SIP) for Arizona. In April 2000, I sent notices to the federal land managers that Arizona was begi nning to develop a state implementation plan to address visibility impairment in the Class I areas. Arizona’s Regional Haze SIP will address visibility impair ment for the four mandatory Federal Class I areas in Arizona that are part of the Grand Canyon Visibility Transport Commission’s Colorado Plateau: Grand Canyon National Park, Petrif ied Forest National Park, Sycamore Canyon Wilderness, and Mount Baldy Wilderness.

Consultation with the federal land managers is an integral part of the regional haze regulations, and we invite you to participate in the review of the proposed SIP during the upcoming 30-day public comment period. The proposed SIP will be posted to the ADEQ Website at www.adeq.state.az.us/environ/air/plan/haze . It is ADEQ’s intent to have the Regional Haze SIP available for public comment in mid-September of this year, culminating with public hearings held throughout the state during the middle or end of October. A notice regarding the commencement of the public comme nt period and dates/locations of the public hearings will be sent separately. The SIP must be submitte d to EPA by December 31, 2003, to meet the requirements of 40 CFR 51.309.

Until further notice, I will be the contact person for regional haze at ADEQ. General inquiries may still be directed to Corky Martinkovic of the Air Quality Planning Section at (602) 771- 2372 or dam@ev.state.az.us . ADEQ looks forward to working with you to protect our national parks and wilderness areas.

Sincerely,

Nancy C. Wrona, Director Air Quality Division Elaine Zieroth

### August 22, 2003 Page 2

cc: Joseph Alston Lee Baiza Carl Bowman Sarah Craighead Harv Forsgren Michael King Pete Lahm Neil Mangum Colleen McKaughan John McGee Joseph Mikitish Bruce Polkowsky Nora Rasure Chris Shaver Karl Siderits Mike WilliamsAppendix A-5 – Attributable Impairment Arizona Regional Haze SIP 

## Appendix A-5c. Supporting Document s Related To The Promulgation Of Arizona’s RAVI Rule

# A RIZONA 

# D EPARTMENT OF 

# E NVIRONMENTAL 

# Q UALITY

Stephen A. Owens Director Janet Napolitano Governor

Northern Regional Office 1515 East Cedar Avenue • Suite F • Flagstaff, AZ 86004 (928) 779-0313 Southern Regional Office 400 West Congress Street • Suite 433 • Tucson, AZ 85701 (520) 628-6733 1110 West Washington Street • Phoenix, Arizona 85007 (602) 771-2300 • www.adeq.state.az.us

Printed on recycled paper 

### MEMORANDUM

DATE: January 7, 2003

TO: Visibility Rule Stakeholders

FROM: Nancy C. Wrona, Director Air Quality Division

SUBJECT: Preliminary Draft Notice of Proposed Rulemaking for Reasonably Attributable Visibility Impairment (RAVI) Rule

You are invited to a stakeholder meeting on Tuesday, January 14, 2003, 1:30 p.m., Room 145, ADEQ, 1110 W. Washington, Phoenix, Arizona . The purpose of this meeting is to review a draft Notice of Proposed Rulemaking (NPRM) for the Reasonably Attributable Visibility Impairment (RAVI) rule. The RAVI rule, form erly known as the “visibility rule,” has had numerous stakeholder reviews, but now contains the preamble portion required for submission to the Secretary of State. Once th e RAVI rule is submitted to the Secretary of State for publication in the Arizona Administrative Register , the rule will have a 30 day public review period, culminating in a public hearing in mid March 2003.

The proposed rule deals with stat e requirements within the federal visibility/regional haze rule 40 CFR §§51.302 - 307. Sections 302 through 307 deal with a specific type of visibility impairment caused by certain categories of exiting stationary sources operating in and near national parks and wilderness areas (federal Class I areas).

Due to the length of the draft NPRM, we will not be faxing the document with this notice. However, you can access the RAVI rule via the ADEQ Web page at www.adeq.state.az.us/envi ron/air/plan/haze.html. You can also receive a copy of the draft NPRM by contacting Corky Martinkovic at the number or e-mail shown below.

I look forward to seeing you on January 14 th 

### . If you have any questions regarding the meeting, please call me at (602) 771-2308 or Corky Ma rtinkovic at (602) 771-2372, or by e-mail at martinkovic.deborrah@ ev.state.az.us. If you are in Arizona, but out side of the Phoenix area, call 1-800-234-5677, then dial extension 771-2372. Copies of the draft NPRM w ill also be available at the January 14 th 

### meeting.

### PUBLIC NOTICE

ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY PUBLIC HEARING ON NOTICE OF PROPOSED RULEMAKING REASONABLY ATTRIBUTABLE VISIBILITY IMPAIRMENT RULE

The Arizona Department of Environmental Quality (ADEQ) will hold a public hearing to receive comments on the Notice of Proposed Rulemaking for Reasonably Attributable Visibility Impairment (RAVI) rule. This rule impacts specific stationa ry sources emitting 250 tons per year or more of visibility impairing air pollutants in or near Ariz ona’s 12 mandatory federal class I areas (national parks and wilderness areas). The rule directs the state of Arizona and the stationary sources on the actions necessary should a source or small group of sources be certified by a Federal Land Manager as possibly causing or contributing to visibility problems in any of the 12 national parks and wilderness areas.

A public hearing on the Notice of Proposed Rule making will be held on Wednesday, April 7, 2003, at the Coconino Library, 300 W. Aspe n, Flagstaff, Arizona. All interested parties will be given an opportunity at the public hearing to submit releva nt comments, data, and views, orally and in writing. Written comments must be received at ADEQ by 5:00 p.m. on Friday, April 11, 2003. ADEQ anticipates sending the proposed rule a nd any comments received to the Governor’s Regulatory Review Council on or after April 21, 2003.

All written comments should be addressed, faxed, or e-mailed to:

Deborrah “Corky” Martinkovic Air Quality Planning Section Arizona Department of Environmental Quality 1110 W. Washington Street Phoenix, AZ 85012-2905 FAX: (602) 771-2366 E-Mail: martinkovic.deborrah@ev.state.az.us

Copies of the proposal are available for review beginning Thursday, March 13 (ADEQ) and March 17 (Flagstaff), 2003, at the following locations:

Arizona Department of Environmental Quality Locally : First Floor Library Coconino Library 1110 W. Washington Street 300 W. Aspen Phoenix, Arizona 85012 Flagstaff, Arizona Lorraine Akey, (602) 771-4335 Dawn Gardner, (928) 779-7670

### PUBLIC NOTICE

ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY PUBLIC HEARING ON NOTICE OF PROPOSED RULEMAKING REASONABLY ATTRIBUTABLE VISIBILITY IMPAIRMENT RULE

The Arizona Department of Environmental Quality (ADEQ) will hold a public hearing to receive comments on the Notice of Proposed Rulemaking for Reasonably Attributable Visibility Impairment (RAVI) rule. This rule impacts specific stationa ry sources emitting 250 tons per year or more of visibility impairing air pollutants in or near Ariz ona’s 12 mandatory federal class I areas (national parks and wilderness areas). The rule directs the state of Arizona and the stationary sources on the actions necessary should a source or small group of sources be certified by a Federal Land Manager as possibly causing or contributing to visibility problems in any of the 12 national parks and wilderness areas.

A public hearing on the Notice of Proposed Rule making will be held on Wednesday, April 8, 2003, at the Arizona Department of Environmenta l Quality, 1110 W. Washington Street, Room 145, Phoenix, Arizona. All interested parties will be gi ven an opportunity at th e public hearing to submit relevant comments, data, and views, orally and in writing. Written comments must be received at ADEQ by 5:00 p.m. on Friday, April 11, 2003. ADEQ anticipates sending the proposed rule and any comments received to the Governor’s Regulatory Review Council on or after April 21, 2003.

All written comments should be addressed, faxed, or e-mailed to:

Deborrah “Corky” Martinkovic Air Quality Planning Section Arizona Department of Environmental Quality 1110 W. Washington Street Phoenix, AZ 85012-2905 FAX: (602) 771-2366 E-Mail: martinkovic.deborrah@ev.state.az.us

Copies of the proposal are available for review beginning Thursday, March 13, 2003, at the following locations:

Arizona Department of Environmental Quality Other Hearing Locations : First Floor Library 1110 W. Washington Street Flagstaff - April 7, 2003 Phoenix, Arizona 85012 Tucson - April 9, 2003 Lorraine Akey, (602) 771-4335

### PUBLIC NOTICE

ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY PUBLIC HEARING ON NOTICE OF PROPOSED RULEMAKING REASONABLY ATTRIBUTABLE VISIBILITY IMPAIRMENT RULE

The Arizona Department of Environmental Quality (ADEQ) will hold a public hearing to receive comments on the Notice of Proposed Rulemaking for Reasonably Attributable Visibility Impairment (RAVI) rule. This rule impacts specific stationa ry sources emitting 250 tons per year or more of visibility impairing air pollutants in or near Ariz ona’s 12 mandatory federal class I areas (national parks and wilderness areas). The rule directs the state of Arizona and the stationary sources on the actions necessary should a source or small group of sources be certified by a Federal Land Manager as possibly causing or contributing to visibility problems in any of the 12 national parks and wilderness areas.

A public hearing on the Notice of Proposed Rule making will be held on Wednesday, April 9, 2003, at the State Office Building, 400 W. Congress, R oom 158, Tucson, Arizona. All interested parties will be given an opportunity at the public hearing to submit relevant comments, data, and views, orally and in writing. Written comments must be received at ADEQ by 5:00 p.m. on Friday, April 11, 2003. ADEQ anticipates sending the proposed rule and any comments received to the Governor’s Regulatory Review Council on or after April 21, 2003.

All written comments should be addressed, faxed, or e-mailed to:

Deborrah “Corky” Martinkovic Air Quality Planning Section Arizona Department of Environmental Quality 1110 W. Washington Street Phoenix, AZ 85012-2905 FAX: (602) 771-2366 E-Mail: martinkovic.deborrah@ev.state.az.us

Copies of the proposal are available for review beginning Thursday, March 13 (ADEQ) and March 17 (Tucson), 2003, at the following locations:

Arizona Department of Environmental Quality Locally : First Floor Library State Office Building 1110 W. Washington Street 400 W. Congress, Room 158 Phoenix, Arizona 85012 Tucson, Arizona Lorraine Akey, (602) 771-4335 Julie Benner, (520) 628-6902ADEQ RAVI NPRM, 2/4/03 1 NOTICE OF PROPOSED RULEMAKING
TITLE 18. ENVIRONMENTAL QUALITY
CHAPTER 2. DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR POLLUTION CONTROL
ARTICLE 16. VISIBILITY; REGIONAL HAZE

PREAMBLE

1. Sections Affected Rulemaking Action

R18

- 2

- 101 Amend

R18

- 2

- 1601 New Section

R18

- 2

- 1602 New Section

R18

- 2

- 1603 New Section

R18

- 2

- 1604 New Section

R18

- 2

- 1605 New Section

R18

- 2

- 1606 New Section

2. The statutory authority for the rulemaking, including both the authorizing statute (general)

and the statutes the rules are implementing (specific) : General Authority: A.R.S. §§ 49

- 104(A)(11) and 49

- 425 Specific Authority: A.R.S. §§ 49

- 414 and 414.01

3. A list of all previous notices appearing in the Register addressing the proposed rule:

Not ice of Docket Opening: 9 A.A.R. 390, February 7, 2003

4. The name and address of agency personnel with whom persons may communicate
regarding the rulemaking

. Name: Deborrah “Corky” Martinkovic

Address: ADEQ, Air Quality Planning Section, 1110 West Was hington Street,

Phoenix, AZ 85007
Telephone: (602) 771

- 2372 (Any extension may be reached in

- state by dialing 1

-

800

- 234

- 5677, and asking for a specific number.)

Fax: (602) 771

- 2366

E

- mail: martinkovic.deborrah@ev.state.az.usADEQ RAVI NPRM, 2/4/03 2

5. An explanation of the rule, including the agency’s reasons for initiating the rule : Summary. This rule sets forth the process Arizona Department of Environmental Quality (ADEQ) will

use to determine whether Best A vailable Retrofit Technology (BART) will be required for sources
determined to be contributing to visibility impairment in a mandatory Federal Class I area. Federal
regulations allow Federal Land Managers (FLMs) to certify sources defined in 40 CFR 51.301 as potential contributors to visibility impairment in any of the Arizona mandatory Federal Class I areas
under Section 169A of the Clean Air Act (CAA).

Background. In 1977 Congress added a new section to the Clean Air Act

- Section 169A, Visibility

Prot ection for Federal Class I Areas

- which established a national goal for, “the prevention of any future,
and the remedying of any existing impairment of visibility in mandatory class I Federal areas which
impairment results from man

- made air pollution.” I n addition, the section required states to submit state
implementation plans (SIPs) requiring best available retrofit technology (BART) for certain existing
stationary sources found to cause or contribute to visibility impairment. On November 30, 1979, EP A
promulgated a list of mandatory Federal Class I Areas (Class I areas) where visibility is an important
value (44 FR 69122). There are 12 Class I areas identified in Arizona: Chiricahua National Monument
Wilderness, Chiricahua Wilderness, Galiuro Wildern ess, Grand Canyon National Park, Mazatzal
Wilderness, Mount Baldy Wilderness, Petrified Forest National Park, Pine Mountain Wilderness, Saguaro
Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore Canyon Wilderness (40
CFR 81.403).

O n December 2, 1980 (45 FR 80084), EPA defined the role of the FLMs in certifying visibility
impairment in the mandatory Federal Class I areas. On November 24, 1987 (52 FR 45132), FLMs
identified Petrified Forest National Park, Saguaro Wilderness, and Gran d Canyon National Park, as
having visibility impairment possibly attributable to stationary sources. Under the 1980 rule, if found to
cause or contribute to the impairment, certain existing stationary sources operating in or near the

identified Class I ar eas could be subject to BART (A list of sources eligible for the possible application of
BART can be found at 40 CFR 51.301). On October 3, 1991, the Navajo Generating Station (NGS) was
found by EPA to be causing or contributing to visibility impairment f or the Grand Canyon National Park
and eligible for BART (56 FR 50172). BART control analyses were subsequently performed by EPA,
and other parties through related court actions. Under the 1980 rule, the federal expectation is that actions

for determinati on of possible source attribution will be performed by the states. Therefore, Arizona needsADEQ RAVI NPRM, 2/4/03 3

to be prepared to proceed with an attribution analysis and assessment for the application of controls upon
any determination of a BART eligible source being the po ssible cause or contributor to visibility
impairment in a Class I area. This rule addresses that need.

Current Conditions. ADEQ is proposing that this rule apply to any source in existing stationary source
categories identified in 40 CFR 51.301 that are operating in or near the mandatory federal Class I areas in
Arizona. The source is an existing stationary facility that includes any reconstructed source that was not
in operation prior to August 7, 1962, and was in existence on August 7, 1977, and has t he potential to
emit 250 tons per year of any regulated pollutant. ADEQ estimates that there are potentially 10 such
sources within Arizona. “In existence” is interpreted by EPA to be consistent with the term, “commence

construction” found in Prevention o f Serious Deterioration (PSD) regulations (40 CFR 51.165(a)(1)(xvi)
and 40 CFR 52.21 (b)(9)). If construction commenced after August 7, 1977, the source would be subject
to the PSD/NSR (new source review) program (the state regulations are found at 18 A.C .C. 2, Article 4).
However, EPA also notes “that sources, are not BART eligible if the only change at the plant was the
addition of pollution controls. For example, if the only change at a copper smelter during the 1962
through 1977 time period was the a ddition of acid plants for the reduction of SO 2 emissions, these
emission controls would not themselves trigger a BART review.” 1

Under this proposed rule, ADEQ, when analyzing an attributable source for BART controls, must

consider several factors includ ing, for example, costs, remaining useful life of the source, and degree of
improvement anticipated to result from the application of the controls (the factors are detailed in R18

- 2

- 1605). Sources required by ADEQ to install and operate BART controls have a final opportunity to
request exemption from the requirement prior to the application of controls. This opportunity for a
federal exemption from BART, is contained in R18

- 2

- 1606, and 40 CFR 51.303.

Summary. This rule outlines the process through which sources eligible for the application of BART will
proceed if certified by the state of Arizona or an FLM as possibly causing or contributing to visibility
impairment due to attribution. If found to be attributable for the impairment, a BART analysis will be
performed to determine the level of controls necessary to remedy the impairment. This rule enables
Arizona to fulfill the requirements of the Clean Air Act and the goal of section 169A of the Act to return
the Nation’s federal parks and wilderness are as to natural conditions.

1 EPA proposed rule, 66 Federal Register 38119, July 20, 2001.ADEQ RAVI NPRM, 2/4/03 4

Section

- by

- section Explanation for the Proposed Rule

R18

- 2

- 1601 This section lists the definitions that apply to this rule.

R18

- 2

- 1602 This section lists the Class I areas addressed by this rule for the applicable

existing stat ionary facilities, as defined in R18

- 2

- 1601(2).

R18

- 2

- 1603 This section establishes the procedure for certification of impairment by either a

Federal Land Manager with authority over a mandatory Federal Class I area, or
the Director, should either believe there exists reasonably attributable visibility
impairment in a Federal Class I area as listed in R18

- 2

- 1602.

R18

- 2

- 1604 This section establishes the procedure for an attribution analysis after

certification of a source or group of sources as outlined in R18

- 2

- 1603. Upon
completion of the attribution analysis, the procedure for the Director to issue
draft and final attribution findings is outlined in R18

- 2

- 1604(C).

R18

- 2

- 1605 This section establishes the best available retrofit technology (BART) analysi s

procedure after a source is identified under R18

- 2

- 1604. Upon completion of the
BART analysis, the procedure for the Director to issue draft and final BART
findings, including alternatives to emission standards, is outlined in R18

- 2

- 1605(B) and (C), res pectively. The specific conditions where BART would be
satisfied due to past or planned actions by the facility are outlined in R18

- 2

- 1605(D). EPA determinations regarding new technology that might require a
BART analysis for an applicable source, regard less of a source or small group of
sources previously being certified and found attributable, are covered in R18

- 2

- 1605(E).

R18

- 2

- 1606 This section establishes the procedures for obtaining a federal exemption from a

BART requirement.

6. A reference to an y study relevant to the rule that the agency proposes to rely on in its
evaluation of or justification for the proposed rule or proposes not to rely on in its
evaluation of or justification for the rule, where the public may obtain or review each study,

al l data underlying each study, and any analysis of each study and other supporting

material: Not ApplicableADEQ RAVI NPRM, 2/4/03 5

7. A showing of good cause why the rule is necessary to promote a statewide interest if the rule
will diminish a previous grant of authority of a political subdivision of this state: Not applicable

8. The preliminary summary of the economic, small business, and consumer impact :

A. Rule Identification

These rules would amend R18

- 2

- 101 (“visibility impairment” definition) and add new sections R18

- 2

- 1601 through R18

- 2

- 1606. For sources under ADEQ jurisdiction, the rules would take the place of
federal regulations that currently govern this area.

B. Entities Directly Impacted

1. Federal Land Managers. Proposed R18

- 2

- 1603 would allow Federal Land Ma nagers (FLMs) to certify
visibility impairment in mandatory Class I areas. This is already allowed by federal rule. Under R18

- 2

- 1601 of the proposed rule, the FLMs able to certify impairment in Arizona are with the United States

Forest Service and the Na tional Park Service. There are no FLMs in Arizona from the United States Fish
and Wildlife Service, because this agency does not have jurisdiction over any of Arizona’s mandatory

federal Class I areas.

2. ADEQ. Proposed R18

- 2

- 1604 would require ADEQ to identify stationary sources that could cause or
contribute to the certified visibility impairment. This function is currently carried out by EPA. Proposed

R18

- 2

- 1605 would require ADEQ to analyze for BART (best available retrofit technology) controls th ose sources identified as causing or contributing to visibility impairment. This function is currently carried
out by EPA. The impact of this rule on ADEQ would primarily be on the Air Quality Division, Permits

and Assessment sections.

3. Stationary so

urces. Proposed R18

- 2

- 1605 would also require stationary sources identified in #2 to
install or operate the BART as determined by the Director. Currently, EPA determines and requires
BART. To determine impacted stationary sources, ADEQ staff reviewed Ti tle V permits from ADEQ’s
Air Permit files. Of the 26 industry categories listed in 40 CFR 51.301, only five categories were found
to exist under ADEQ’s jurisdiction: steam electric plants, cement plants, primary copper smelters, lime
plants, and industri es using non

- utility boilers. As a result, potentially 10 sources, representing 16 BART
eligible units (boilers and kilns), could be affected by this proposed rule. The combined potential to emitADEQ RAVI NPRM, 2/4/03 6

from these sources totaled 94,287 tons per year for NO x , 1 41,036 tons per year for SO 2 , and 12,146 tons
per year for PM. The combined potential to emit for all pollutants for these 10 sources total
approximately 250,000 tons per year.

C. Probable Costs and Benefits Associated with the BART/Visibility Impairmen t Process

1. Direct Costs

- FLMs: FLM activities to certify visibility impairment in mandatory Class I areas may
involve preparation and analysis of monitoring data, emission inventories, meteorological records, etc.
ADEQ estimates that this cost per cer tification could be as much as $50,000 if extensive analysis is
conducted. These costs exist whether or not these proposed rules become final.

2. Direct Costs

- ADEQ: ADEQ costs related to identifying whether a BART eligible stationary source

causes or c ontributes to visibility impairment in Class I areas are based on the activities identified in R18

-
2

- 1604(A). ADEQ estimates that these costs could range from $100,000

– 200,000 per attribution
analysis, and be primarily borne by the ADEQ’s Air Quality As sessment Section. Costs related to
analyzing identified sources for BART are based on the activities identified in proposed R18

- 2

- 1605(A) and will be moderate, but less expensive than the attribution analysis. These costs will be primarily born
by the Pe rmits Section. These costs would not accrue to the State unless the proposed rule becomes final.
Finally, incorporating BART into an existing State air quality permit may require additional resources
from the Permits Section. However, these costs, unlik e costs for the attribution and BART analysis,
would be covered by permit revision fees paid by the source, and would exist whether or not these
proposed rules become final.

3. Direct Costs

- Stationary sources: If a source or small group of sources is fo und to cause or contribute
to visibility impairment, and the BART determination requires installation of retrofit controls, costs to
sources required to install BART would be substantial. The total cost to install a technology similar to
BART at the Navaj o Generating Station was estimated by SRP to be in the hundreds of millions of dollars
(51 Federal Register 50172, October 3, 1991). However, the example of the Navajo Generating Station
shows costs to install technology similar to BART can result even wh ere there is no state rule. According
to EPA, “Where a State defaults on its obligations under the visibility regulations, EPA may act in place
of the State pursuant to a FIP under section 110(c) of the Act, 42 U.S.C. 7410(c) 2 , and promulgate such

limitat ion and measures as are required to achieve reasonable progress.”(Ibid. at 50173, footnote not
included). Although ADEQ is listing these costs for information purposes, ADEQ is not attributing any
costs to install and operate BART to this rule because suc h requirements can be imposed by the federal
government without any State rule.ADEQ RAVI NPRM, 2/4/03 7

Benefits. Two kinds of benefits are associated with this proposed rule. The first is reduced emissions.
Although, BART could be required to be installed on sources even wit hout this state rule, it is helpful to
list the emission benefits. When BART is installed, visibility is improved. Over 4 million recreation
visits were made to Grand Canyon National Park in FY 2001. These visits generate substantial revenue

in and for the state of Arizona. Other scenic resources that could also be improved with the installation of
BART, and, though less significant than the Grand Canyon, would enhance the tourism resources of
Arizona, as well as the quality of life for Arizona citizens . In addition, reduction of visibility

- impairing

emissions also has health benefits.

The second benefit is replacement of federal regulation with state regulation. The lack of state
regulations implementing BART results in Arizona sources being subject to federal regulation
implemented by EPA from Washington and San Francisco. These proposed rules would place the
identification and analysis of BART sources at ADEQ rather than with EPA. Arizona is currently under a
visibility Federal Implementation Plan (FIP), and one or two sources have considered or implemented
technology similar to BART under federal rules. Because ADEQ already permits many of these sources,
ADEQ is more familiar with the various factors that go into the BART analysis. This would be a benefit
to sources being regulated. ADEQ would be implementing the same BART rules that EPA does.

The rule further allows ADEQ to proceed with the implementation of the entire federal rule for visibility
improvement. The proposed rule addresses the r equirements of 40 C.F.R. §§51.302

– 307. These
sections must be satisfied before ADEQ can implement the requirements of 40 C.F.R. §§51

- 308 and 309.
The plan to implement Section 309 must be submitted to EPA by December 31, 2003.

D. Small Business Analy sis
A.R.S. §41

- 1055(B)(5) requires agencies to state the probable impact of a rulemaking on small
businesses. A.R.S. §41

- 1035 requires agencies to reduce the impact of a rule on small businesses by
using certain methods when they are legal and feasible in meeting the statutory objectives for the rule
making. These methods include: (1) exempting them from any or all rule requirements, (2) establishing
performance standards which would replace any design or operational standards, or (3) instituting reduced
compliance or reporting requirements. An agency may accomplish the third method by establishing less
stringent requirements, consolidating or simplifying requirements, or setting less stringent schedules or

deadlines.ADEQ RAVI NPRM, 2/4/03 8

"Small business" is defined in A.R. S. §41

- 1001 as “a concern, including its affiliates, which is
independently owned and operated, which is not dominant in its field and which employs fewer than one

hundred full

- time employees or which had gross annual receipts of less than four million dol lars in its last
fiscal year.” Interpreting this definition means that if a concern has annual gross receipts of more than
four million dollars, but fewer than 100 employees, it would not be classified as a small business.

ADEQ expects that none of the p otential BART eligible sources would be classified as a small business.
A preliminary conclusion is that this proposed rule will not impact other small businesses. However, if a
BART eligible source would qualify as a small business, ADEQ is unable to es tablish different
requirements for small businesses. Except for applying for an exemption, as mentioned under
“Alternative Methods,” ADEQ cannot establish less stringent requirements or exemptions for small
businesses, or any BART eligible source.

ADEQ r equests comment and additional information relating to any of the conclusions reached in this
preliminary EIS.

9. The name and address of agency personnel with whom persons may communicate regarding
the accuracy of the economic, small business, and consum er impact statement :

Name: David Lillie

Address: ADEQ, Air Quality Planning Section, 1110 West Washington, Phoenix, AZ

85007
Telephone: (602) 771

- 4461 (Any extension may be reached in

- state by dialing 1

- 800

- 234

- 5677, and asking for a specific number.)

Fax: (602) 771

- 2366

E

- mail: Lillie.David@ev.state.az.us

10. The time, place, and nature of the proceedings for the making, amendment, or repeal of the
rule or, if no proceeding is scheduled, where, when and how persons may request an oral
proceeding on the proposed rule : Date: April 7, 2003
Time: 4:30 p.m.
Location: Coconino Library, 300 W. Aspen, Flagstaff, AZ

----------------------------------------ADEQ RAVI NPRM, 2/4/03 9

Date: April 8, 2003
Time: 4:30 p.m.

L ocation: ADEQ, 1110 W. Washington St, Rm 145, Phoenix, AZ

--------------------------------------- Date: April 9, 2003
Time: 4:30 p.m.
Location: State Office Building, 400 W. Congress, Rm 158, Tucson, AZ

----------------------------------------
Nature: Oral Proceedings with opportunity for formal comments on the record

Close of Comment: 5:00 p.m., April 11, 2003

11. Any other matters prescribed by statute that are applicable to the specific agency or to any
specific rule or class of rules : Not appli cable

12. Incorporation by reference and their location in the rule : Not applicable

13. The full text of the rule follows:ADEQ RAVI NPRM, 2/4/03 10 TITLE 18. ENVIRONMENTAL QUALITY
CHAPTER 2. DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR POLLUTION CONTROL

ARTICLE 1. GENERAL

Sec tion

R18

- 2

- 101 Definition of “visibility impairment” ................................. Amend

ARTICLE 16. VISIBIL ITY; REGIONAL HAZE

Section

R18

- 2

- 1601 Definitions ............................................................... New Section

R18

- 2

- 1602 Applicability ............................................................. New Section

R18

- 2

- 1603 Cert ification of Impairment ............................................ New Section

R18

- 2

- 1604 Attribution Analysis; Finding .......................................... New Section

R18

- 2

- 1605 BART Control Analysis; Finding ..................................... New Section

R18

- 2

- 1606 Exemption from BART ................................................ New Sectio n

ARTICLE 1. GENERAL

R18

- 2

- 101. Definitions
In addition to the definitions prescribed in A.R.S. §§ 49

- 101, 49

- 401.01, 49

- 421, 49

- 471, and 49

- 541, in
this Chapter, unless otherwise specified:

1. No change

2. No change

a. No change

b. No change

c. No change

d. No change

e. No change

3. No change

4. No change

5. No change

6. No changeADEQ RAVI NPRM, 2/4/03 11

7. No change

8. No change

9. No change

10. No change

a. No change

b. No change

c. No change

d. No change

e. No change

f. No change

11. No chang e

a. No change

b. No change

c. No change

12. No change

13. No change

14. No change

a. No change

b. No change

15. No change

16. No change

17. No change

18. No change

19. No change

20. No change

21. No change

22. No change

23. No change

24. No change

25. No change

26. No change

27. No change

a. No changeADEQ RAVI NPRM, 2/4/03 12 b. No change

28. No change

29. No change

30. No change

31. No change

32. No change

33. No change

34. No change

35. No change

36. No change

37. No change

38. No change

39. No change

40. No change.

41 No change

42. No change

a. No change

b. No change

c. No change

d. No change

e. No change

f. No change

g. No change

h. No change

i. No change
j. No change

k. No change

l. No change

43. No change

44. No change

a. No change

b. No change

c. No changeADEQ RAVI NPRM, 2/4/03 13 d. No change

45. No change

46. No change

47. No change

48. No change

49. No change

50. No change

51. No change

52. No change

53. No change

54. No change

55. No change

56. No change

5 7. No change

a. No change

b. No change

c. No change

d. No change

e. No change

f. No change

g. No change

h. No change

i. No change
j. No change

58. No change

59. No change

60. No change

61. No change

62. No change

63. No change

a

. No change

b. No change

c. No changeADEQ RAVI NPRM, 2/4/03 14 i. No change

ii. No change

iii. No change

iv. No change

v. No change
(1) No change
(2) No change

vi. No change

vii. No change

viii. No change
(1) No change
(2) No change

i x. No change
(1) No change
(2) No change

x. No change

xi. No change

64. No change

a. No change

b. No change

i. No change

ii. No change

c. No change

i. No change

ii. No change

iii. No change

iv. No change

v. No chan ge

vi. No change

vii. No change

viii. No change

ix. No change

x. No changeADEQ RAVI NPRM, 2/4/03 15 xi. No change

xii. No change

xiii. No change

xiv. No change

xv. No change

xvi. No change

xvii. No change

xviii. No change

xix. No change

xx. No change

xxi. No change

xxii. No change

xxiii. No change

xxiv. No change

xxv. No change

xxvi. No change

xxvii. No change

65. No change

66. No change

67. No change

68. No change

69. No change

70. No change

71. No change

72

. No change

a. No change

i. No change

ii. No change

b. No change

i. No change

ii. No change

c. No change

d. No changeADEQ RAVI NPRM, 2/4/03 16 e. No change

f. No change

i. No change

ii. No change

iii. No change

iv. No change

g. No change

73. No change

74. No change

75. No change

76. No change

77. No change

78. No change

79. No change

80. No change

81. No change

82. No change

83. No change

a. No change

b. No change

c. No change

d. No change

84. No change

85. No change

86. N o change

87. No change

88. No change

89. No change

90. No change

91. No change

92. No change

93. No change

94. No changeADEQ RAVI NPRM, 2/4/03 17 a. No change

b. No change

c. No change

d. No change

95. No change

96. No change

97. No change

a. No change

b. No change

c. No change

d. No change

e. No change

98. No change

a. No change

i. No change

ii. No change

iii. No change

iv. No change

v. No change

vi. No change

vii. No change

b. No change

c. No change

99. No change

a. No c hange

b. No change

100. No change

101. No change

102. No change

103. No change

104. No change

a. No change

b. No changeADEQ RAVI NPRM, 2/4/03 18 c. No change

d. No change

105. No change

106. No change

107. No change

a. No change

b. No change

108. No change

109. No change

110. No change

111. No change

112. No change

113. No change

114. No change

115. No change

116. No change

117. No change

a. No change

b. No change

c. No change

d. No change

e. No change

f. No change

g. No change

h. No change

i. No change
j. No change

k. No change

l. No change

m. No change

n. No change

o. No change

p. No changeADEQ RAVI NPRM, 2/4/03 19 q. No change

r. No change

s. No change

t. No change

u. No change

v. No change

w. No change

x. No change

y. No c hange

z. No change

aa. No change

bb. No change

cc. No change

dd. No change

ee. No change

ff. No change

gg. No change

hh. No change

ii. No change
jj. No change

kk. No change

ll. No change

mm. No change

nn. No change

oo. No ch ange

pp. No change

qq. No change

rr. No change

ss. No change

tt. No change

uu. No change

vv. No change

ww. No changeADEQ RAVI NPRM, 2/4/03 20 xx. No change

118. No change

119. No change

120. No change

121. No change

122. No change

123. “Visibility impairmen t” means any humanly perceptible change in visibility ( light
extinction, visual range, contrast, and coloration ) from that which would have existed

under natural conditions.

124. No change

125. No change

a. No change

b. No change

c. No change

d. No change

e. No change

f. No change

g. No change

h. No change

i. No change
j. No change

k. No change

l. No change

m. No change

n. No change

o. No change

p. No change

q. No change

r. No change

s. No change

t. No change

u. N o change

v. No changeADEQ RAVI NPRM, 2/4/03 21 w. No change

x. No change

y. No change

z. No change

aa. No change

bb. No change

cc. No change

dd. No change

ee. No change

ff. No change

gg. No change

hh. No change

ii. No change
jj. No change

kk. No cha

nge

ll. No change

mm. No change

nn. No change

oo. No change

pp. No change

qq. No change

rr. No change

ss. No change

i. No change

ii. No change

iii. No change

iv. No change

126. No change

ARTICLE 16. VISIBILITY; REGIONAL HAZE

R18

- 2

- 1601. Definitions In addition to the definitions contained in Articles 1 and 4 of this Chapter and A.R.S. § 49

- 401.01, theADEQ RAVI NPRM, 2/4/03 22

following definitions apply to this Article:

1. “Best available retrofit technology (BART)” means an emission limitation based on the degree of
reduction achievable through the application of the best system of continuous emission reduction
for each pollutant that is emitted by an existing stationary facility. The emission limitation is

established on a case

- by

- case basis in ac cordance with R18

- 2

- 1605.

2. “Existing stationary facility” means any of the following stationary sources of air pollutants,
including any reconstructed source, which was not in operation prior to August 7, 1962, and was
in existence on August 7, 1977, and has the potential to emit 250 tons per year or more of any air
pollutant. In determining potential to emit, fugitive emissions, to the extent quantifiable, must be

counted.

a. Fossil

- fuel fired steam electric plants of more than 250 million British therm al units per
hour heat input,

b. Coal cleaning plants (thermal dryers),

c. Kraft pulp mills,

d. Portland cement plants,

e. Primary zinc smelters,

f. Iron and steel mill plants,

g. Primary aluminum ore reduction plants,

h. Primary copper smelters,

i

. Municipal incinerators capable of charging more than 250 tons of refuse per day,
j. Hydrofluoric, sulfuric, and nitric acid plants,

k. Petroleum refineries,

l. Lime plants,

m. Phosphate rock processing plants,

n. Coke oven batteries,

o. Sulfur reco very plants,

p. Carbon black plants (furnace process),

q. Primary lead smelters,

r. Fuel conversion plants,

s. Sintering plants,

t. Secondary metal production facilities,

u. Chemical process plants,

v. Fossil

- fuel boilers of more than 250 million Br itish thermal units per hour heat input,ADEQ RAVI NPRM, 2/4/03 23

w. Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels,

x. Taconite ore processing facilities,

y. Glass fiber processing plants, and

z. Charcoal production facilities.

3. “Federal Land Manager” means the Secretary of the department, or the Secretary's designee, with
authority over the Federal Class I area.

4. “Mandatory Federal Class I Area” means any area identified in 40 CFR §§81.400

- 81.436.

5. “Reasonably attributable” means ascr ibable by visual observation or other techniques the Director
deems appropriate.

6. “Reasonably attributable visibility impairment” means visibility impairment that is caused by the
emission of air pollutants from one source, or a small group of sources.

R18

- 2

- 1602. Applicability
This Article applies to any existing stationary source located in the state that may reasonably be
anticipated to cause or contribute to visibility impairment in any mandatory Federal Class I area identified
in 40 CFR §§81.401

- 81. 436. Mandatory Federal Class I areas within Arizona are: Chiricahua National
Monument Wilderness, Chiricahua Wilderness, Galiuro Wilderness, Grand Canyon National Park,
Mazatzal Wilderness, Mount Baldy Wilderness, Petrified Forest National Park, Pine Moun tain
Wilderness, Saguaro Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore
Canyon Wilderness.

R18

- 2

- 1603. Certification of Impairment

A. A Federal Land Manager with authority over a mandatory Federal Class I area may certify to th e Director, at any time, that there exists reasonably attributable visibility impairment in the
mandatory Federal Class I area. The Director may also certify that there exists reasonably
attributable visibility impairment in any mandatory Federal Class I area as necessary to assure reasonable progress under section 169A(b)(2) of the Clean Air Act.

B. Documentation from the affected Federal Land Manager or Director shall include:

1. The mandatory Federal Class I area for which visibility impairment is be ing certified,

2

. Any information documenting the basis for the certification of impairment.

R18

- 2

- 1604. Attribution Analysis; Finding

A. Upon certification of reasonably attributable visibility impairment in any mandatory FederalADEQ RAVI NPRM, 2/4/03 24

Class I area, the Dir ector shall conduct an attribution analysis to identify each existing stationary
source that may be reasonably anticipated to cause or contribute to visibility impairment. The
Director shall notify the Federal Land Manager, affected source or small group of sources, and
local air pollution control officer of the intent to conduct an attribution analysis. The attribution
analysis shall be based on the following:

1. Monitoring information obtained through the Arizona Class I Visibility Monitoring

Netwo rk or special studies approved by ADEQ to ascertain:

a. The times visibility impairment occurred, and

b. The pollutants contributing to the visibility impairment.

2. Transport analysis or air quality modeling based upon meteorological records to as certain
whether the pollutants were transported to the mandatory Federal Class I area.

3. Other available studies, modeling analysis, and emissions inventories of point, area and

mobile source emissions to ascertain:

a. The pollutant or pollu tants causing the impairment, and

b. The source, or small group of sources, emitting the impairing pollutant or
pollutants.

4. Other relevant supporting documentation provided by the Federal Land Manager or

Director used to make the draft attri bution analysis finding.

5. Consideration of any documentation provided by the source or small group of sources.

B. In conducting the attribution analysis, the Director shall use monitoring information,
meteorological records, and emissions inventories that represent times and locations reasonably
concurrent with the visibility impairment.

C. The Director shall issue a draft attribution finding that impairment has or has not occurred, and
provide public notice of the draft attribution finding. The Direc tor shall publish notice of the draft
attribution finding in a newspaper of general circulation in each county containing the mandatory
Federal Class I area and the affected source. The Director shall provide at least 30 days from the

date of the notice f

or public comment. Written comments to the Director shall include the name
of the person and the person’s agent or attorney, if any, and shall clearly set forth reasons why the
draft attribution finding should be reviewed. A final attribution finding sha ll be issued after the
public comment period. Existing stationary sources found to cause or contribute to visibility
impairment in a mandatory Federal Class I area shall be subject to a BART Control Analysis

under R18

- 2

- 1605.ADEQ RAVI NPRM, 2/4/03 25

R18

- 2

- 1605. BART Control An alysis; Finding

A. The Director shall analyze for BART controls each existing stationary source for which a final
attribution finding is made under R18

- 2

- 1604(C). The Director shall consider the following

factors:

1. Available control technology;

2. New source performance standards (NSPS) as adopted in Article 9;

3. Alternative control systems if retrofitting to comply with applicable NSPS standards
adopted in Article 9 is found infeasible.

4. Cost of compliance;

5. Energy and non

- air quality environmental impacts of compliance;

6. Existing pollution control technology in use at the source or small group of sources;

7. Remaining useful life of the source or small group of sources;

8. Net environmental impact associated with the proposed emission control system;

9. Economic impacts associated with installing and operating the proposed emission control
system; and

10. Degree of improvement in visibility anticipated to result from application of the proposed
emission control sys tem.

B. The Director shall issue a draft BART finding, and provide public notice of the draft BART
finding. The Director shall publish notice of the draft BART finding in a newspaper of general
circulation in each county containing the mandatory Federal C lass I area and the affected source.
The Director shall provide at least 30 days from the date of the notice for public comment.
Written comments to the Director shall include the name of the person and the person’s agent or
attorney, and shall clearly s et forth reasons why the draft BART finding should be reviewed. The
Director shall issue a final BART finding after the public comment period.

1. The Director shall submit each final BART finding that an existing stationary source is
required to m eet BART to the Administrator as a revision to the state implementation
plan (SIP).

2. The Director shall require that each existing stationary source meet BART
as expeditiously as practicable but in no case later than five years after EPA approv al of
the revision to Arizona’s State Implementation Plan.

C. If the Director determines that technological or economic limitations on the applicability of
measurement methodology to a particular existing stationary source would make the imposition

of an emission standard infeasible, the Director may , as part of the finding under subsection (B),ADEQ RAVI NPRM, 2/4/03 26

instead prescribe a design, equipment, work practice, or other operational standard, or
combination thereof. Such standard, to the degree possible, is to set forth the emission reduction
to be achieved by implementation of such design, equipment, work practice or operation, and
must provide for compliance by means which achieve equivalent results.

D. The Director shall make a finding that the attributable sour ce has satisfied the BART requirement

if the attributable source has:

1. Voluntarily applied best available retrofit technology;

2. Previously applied emission control standards equivalent to BART; or

3. Agreed to shutdown or curtail operations at th e attributable source within 5 years of the
finding. An attributable source that does not shutdown or curtail operations shall
proceed to meet BART as expeditiously as practicable, but in no case later than five
years after EPA’s approval of the revision to Arizona’s State Implementation Plan.

E. If the Director determines that the imposition of BART or a standard pursuant to subsection C of
this section is not feasible at the time of the finding, the attributable source shall be required to

inst all and operate BART upon a determination by the Director at a later date that BART or
equivalent controls are now feasible.

F. The Director shall provide for a BART control analysis of any existing stationary source that
might cause or contribute to impa irment of visibility in any mandatory Federal Class I area
identified under this Article at such times, as determined by the Administrator, new technology
for control of the pollutant becomes reasonably available, if:

1. The pollutant is emitted by that e xisting stationary source,

2. Controls representing BART for the pollutant have not previously been required under
this Article, and

3. The impairment of visibility in any mandatory Federal Class I area is reasonably

attributable to the emissions o f that pollutant.

R18

- 2

- 1606. Exemption from BART Any existing stationary source required to install, operate, and maintain BART pursuant to this Article,
may apply to the Administrator for an exemption from that requirement by obtaining prior written

con currence from the Director according to 40 CFR 51.303.Northern Regional Office Southern Regional Office

1515 East Cedar Avenue • Suite F • Flagstaff, AZ 86004 400 West Congress Street • Suite 433 • Tucson, AZ 85701

(928) 779-0313 (520) 628-6733 Printed on recycled paper 

# A RIZONA 

# D EPARTMENT

OF 

# E NVIRONMENTAL 

# Q UALITY

Stephen A. Owens Director Janet Napolitano Governor 1110 West Washington Street • Phoenix, Arizona 85007 (602) 771-2300 • www.adeq.state.az.us



### AIR QUALITY DIVISION

PUBLIC HEARING

on PROPOSED REASONABLY ATTRIBUTABLE VISIBILITY IMPAIRMENT RULE

PLEASE NOTE THE MEETING LOCATION AND TIME:



### Coconino Public Library 300 W. Aspen, Flagstaff, AZ Monday, April 7, 2003, 4:30 p.m.

Pursuant to ARS § 49-425 for air quality rule hearings, notice is hereby given that the above referenced meeting is open to the public. Copies of the proposal are available for review locally at the Coconino Public Library and the Arizona Department of Environmental Quality Library, 1110 W. Washington Street, Phoenix, Arizona.



### AGENDA

1. Welcome and Introductions

2. Purposes of the Oral Proceeding

3. Procedure for Making Public Comment

4. Brief Overview of the Proposed Reasonably Attributable Visibility Impairment Rule

5. Question and Answer Period

6. Oral Comment Period

7. Adjournment of Oral Proceeding

For additional information regarding the hearing, please call Corky Martinkovic, ADEQ Air Quality Division, at (602) 771- 2372] or 1-800-234-5677, Ext. 771-2372. Persons with a disability may request a reasonable accommodation, such as a sign language interpreter, by contacting Katie Huebner at (602) 771-4794 or 1-800-234-5677, Ext. 771-4794. Requests should be made as early as possible to allow sufficient time to make the arrangements for the accommodation. This document is available in alternative formats by contacting ADEQ TDD phone number at (602) 771-4829

.

### P U B L I C H E A R I N G 04 /07 /03

ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALTIY

IN THE MATTER OF ARIZONA’S PROPOSED REASONABLY ATTRIBUTABE PUBLIC HEARING VISIBILITY IMPAIRMENT RULE.

At: Flagstaff, Arizona

Date: April 7, 2003

NOTE: Due to circumstances beyond ADEQ’s control, the official transcript for this public hearing is not available. The he aring did follow verbatim the text of the public hearing officer script; therefore, that script ha s been included here along with a copy of the one comment read into the record.

## Proposed Reasonably Attributable Visibility Impairment Rule

Oral Proceeding Hearing Officer Script

April 7, 2003

I now open this oral proceeding. Good afte rnoon, thank you for coming. This oral proceeding is on the proposed Reasonably Attr ibutable Visibility Impairment Rule. This is a proposed rule to direct the State of Arizona and affected permitted stationary sources on the procedures should a Federal Land Manager certify that any one of these sources or small group of sources have emi ssions that may cause or contribute to the reduction of visibility at specific national parks or wilderness areas in Arizona or adjacent states.

It is now Monday, April 7, 2003, 4:30 [ ] p.m. The location is Coconino Library, 300 W. Aspen, Flagstaff, Arizona.

My name is Cathy O’Connell and I have b een appointed by the Director of the Arizona Department of Environmental Qu ality to preside at this proceeding.

The purposes of this proceeding are to provide the public an opportunity: (1) to hear about the substance of the proposed rule, (2) to ask questions regarding the proposed rule, and (3) to present oral ar gument, data and views regarding th e proposed rule in the form of comments on the record.

Representing the Department are myself and Ms. Corky Martinkovic of the Air Quality Planning Section.

The procedure for making a public comment on the record is straightforward. If you wish to comment, you need to fill out a speaker slip, which is ava ilable at the sign-in table, and give it to me. Using speaker slips allows everyone an opportunity to be heard and allows us to match the name on the official record with the comments.

You may also submit written comments to me today in person or by mail, e-mail, or fax to Corky Martinkovic by the end of the comment period. The end of the comment period is 5:00 p.m. on Friday, April 11, 2003. If mailed, e-mailed, or faxed, written comments must be “postmarked” no later than April 11, 2003. Submit your written
comments to:

### 2 

## Corky Martinkovic Air Quality Planning Section Arizona Department of Environmental Quality 1110 W. Washington Street Phoenix, Arizona 85007 Fax: (602) 771-2366 E-Mail: martinkovic.deborrah@ev.state.az.us

Comments made during the formal comme nt period are required by law to be considered by the Department in the prepara tion of the final rulema king. This is done through the preparation of a concise explan atory statement in which the Department responds in writing to written and oral co mments made during the formal comment period.

The agenda for this hearing is simple. Fi rst, I will present a brief overview of the proposed rule.

Next, I will conduct a question and answer period. The purpose of the question and answer period is to provide information that may help you in making comments on the rule.

Thirdly, I will conduct the oral comment peri od. At that time, I will begin to call speakers in the order that I have received speaker slips.

Please be aware that any comments you make at today's hearing that you want the Department to formally consider must be given either in writing or on the record during the oral comment period of this proceeding.

* * * * *

At this time, I [(or) ] will give a brief overview of the proposed rule.

The Reasonably Attributable Visibility Impair ment Rule, or RAVI for short, will, upon approval, become a new section in th e environmental chapter of the Arizona Administrative Code. States are required to adopt this rule under Federal regulations.

The rule addresses a specific type of air po llution that can reduce visibility in national parks and wilderness areas. This type of pollu tion is a type of air pollution that can be

### 3 

## traced to a certain type of existing stationary source. When a source has this type of air pollution traced directly to their opera tions, they are said to be “reasonably attributable” for that type of pollution.

For the purposes of this rule, this type of pollution originates from a specific type of existing stationary source operating in or near federal national parks and wilderness areas, known formally as federal mandatory Class I areas. Arizona has 12 of these Class I areas. These national parks and w ilderness areas are ma naged by Federal Land Managers. Federal Land Mana gers are able to “certify” for the national park or wilderness area for which they have jurisd iction that there exists a reduction in visibility. They can document the reduction in visibility they observe in the park or wilderness area, and then complete a formal report certifying impairment of visibility.

Once the State of Arizona r eceives a certification of visibility impairment from a Federal Land Manager, under the proposed rule, the State would determine if the source is one of the type of stationary sour ces covered by the rule. Then the State of Arizona would analyze if that source is in fact causing or contributing to the reduction in visibility, or in the words of th e rule, is “reasonably attributable.”

If the source is eligible for emission contro ls and found to be attributable for the reduction in visibility, under the proposed rule, the State of Arizona would then proceed with an analysis for the applicati on and operation of emissi on controls for that source’s air emissions. The emission controls applied under this rule are known as Best Available Retrofit Technology, or BART. BART is applied to existing stationary sources that are too old to operate unde r what is termed, New Source Performance Standards, and yet emit 250 or more tons per year of air pollutants that impair visibility.

Along with outlining the procedures for the BA RT control analysis of the attributable source, the proposed rule points to options for a source to pursue equivalent or better alternatives, or apply for a fe deral- level exemption.

This concludes the explanation period of this proceeding on the proposed rule.

* * * * *

Are there any questions before we move to the oral comment period?

[If there are questions, introduce appropriate staff as the Department's representative to respond to any questions.]

### 4 

## [or, "Hearing none, . . . ."]

This concludes the question and answer period of this proceeding on the proposed rule.

* * * * *

I now open this proceeding for oral comments.

[Call speakers in the order in which they s ubmitted their speaker's slips; if there are many speakers present, you may limit each speaker's time to speak.]

[or, “Seeing no speaker slips, ...]

This concludes the oral comment period of this proceeding.

* * * * *

I encourage everyone to submit written comments on the proposed rule. Your participation is an essential part of th e rulemaking process. Again, you may also submit written comments by mail, e-mail, or fax to Corky Martinkovic by the end of the comment period. The end of the comment period is 5:00 p.m. on Friday, April 11, 2003. If mailed, e-mailed, or faxed, writte n comments must be “postmarked” no later than April 11, 2003. Submit your written comments to:

Corky Martinkovic Air Quality Planning Section Arizona Department of Environmental Quality 1110 W. Washington Street Phoenix, Arizona 85007 Fax: (602) 771-2366 E-Mail: martinkovic.deborrah@ev.state.az.us

Thank you for attending.

The time is now __________. I now close this oral proceeding.Northern Regional Office Southern Regional Office

1515 East Cedar Avenue • Suite F • Flagstaff, AZ 86004 400 West Congress Street • Suite 433 • Tucson, AZ 85701

(928) 779-0313 (520) 628-6733 Printed on recycled paper 

# A RIZONA 

# D EPARTMENT

OF 

# E NVIRONMENTAL 

# Q UALITY

Stephen A. Owens Director Janet Napolitano Governor 1110 West Washington Street • Phoenix, Arizona 85007 (602) 771-2300 • www.adeq.state.az.us



### AIR QUALITY DIVISION

PUBLIC HEARING

on PROPOSED REASONABLY ATTRIBUTABLE VISIBILITY IMPAIRMENT RULE

PLEASE NOTE THE MEETING LOCATION AND TIME: 

### Arizona Department of Environmental Quality, Room 145 1110 W. Washington Street, Phoenix, AZ Tuesday, April 8, 2003, 4:30 p.m.

Pursuant to ARS § 49-425 for air quality rule hearings, notice is hereby given that the above referenced meeting is open to the public. Copies of the proposal are available for review at the Arizona Department of Environmental Quality Library, 1110 W. Washington Street, Phoenix, Arizona.



### AGENDA

1. Welcome and Introductions

2. Purposes of the Oral Proceeding

3. Procedure for Making Public Comment

4. Brief Overview of the Proposed Reasonably Attributable Visibility Impairment Rule

5. Question and Answer Period

6. Oral Comment Period

7. Adjournment of Oral Proceeding

For additional information regarding the hearing, please call Corky Martinkovic, ADEQ Air Quality Division, at (602) 771- 2372] or 1-800-234-5677, Ext. 771-2372. Persons with a disability may request a reasonable accommodation, such as a sign language interpreter, by contacting Katie Huebner at (602) 771-4794 or 1-800-234-5677, Ext. 771-4794. Requests should be made as early as possible to allow sufficient time to make the arrangements for the accommodation. This document is available in alternative formats by contacting ADEQ TDD phone number at (602) 771-4829

.Northern Regional Office Southern Regional Office

1515 East Cedar Avenue • Suite F • Flagstaff, AZ 86004 400 West Congress Street • Suite 433 • Tucson, AZ 85701

(928) 779-0313 (520) 628-6733 Printed on recycled paper 

# A RIZONA 

# D EPARTMENT

OF 

# E NVIRONMENTAL 

# Q UALITY

Stephen A. Owens Director Janet Napolitano Governor 1110 West Washington Street • Phoenix, Arizona 85007 (602) 771-2300 • www.adeq.state.az.us



### AIR QUALITY DIVISION

PUBLIC HEARING

on PROPOSED REASONABLY ATTRIBUTABLE VISIBILITY IMPAIRMENT RULE

PLEASE NOTE THE MEETING LOCATION AND TIME: 

### State Office Building, Room 158 400 W. Congress, Tucson, AZ Wednesday, April 9, 2003, 4:30 p.m.

Pursuant to ARS § 49-425 for air quality rule hearings, notice is hereby given that the above referenced meeting is open to the public. Copies of the proposal are available for review locally at the State Office Building and the Arizona Department of Environmental Quality Library, 1110 W. Washington Street, Phoenix, Arizona.



### AGENDA

1. Welcome and Introductions

2. Purposes of the Oral Proceeding

3. Procedure for Making Public Comment

4. Brief Overview of the Proposed Reasonably Attributable Visibility Impairment Rule

5. Question and Answer Period

6. Oral Comment Period

7. Adjournment of Oral Proceeding

For additional information regarding the hearing, please call Corky Martinkovic, ADEQ Air Quality Division, at (602) 771- 2372] or 1-800-234-5677, Ext. 771-2372. Persons with a disability may request a reasonable accommodation, such as a sign language interpreter, by contacting Katie Huebner at (602) 771-4794 or 1-800-234-5677, Ext. 771-4794. Requests should be made as early as possible to allow sufficient time to make the arrangements for the accommodation. This document is available in alternative formats by contacting ADEQ TDD phone number at (602) 771-4829

.ADEQ RAVI NFRM, 8/11/03+ 1 NOTICE OF FINAL RULEMAKING
TITLE 18. ENVIRONMENTAL QUALITY
CHAPTER 2. DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR POLLUTION CONTROL
ARTICLE 16. VISIBILITY; REGIONAL HAZE

PREAMBLE

1. Sections Affected Rulemaking Action

R18-2-101 Amend

Article 16 New Article

R18-2-1601 New Section

R18-2-1602 New Section

R18-2-1603 New Section

R18-2-1604 New Section

R18-2-1605 New Section

R18-2-1606 New Section

2. The statutory authority for the rulemaking, including both the authorizing statute (general)
and the statutes the rules are implementing (specific) : General Authority: A.R.S. §§ 49-104(A)(11) and 49-425
Specific Authority: A.R.S. §§ 49-414 and 414.01

3. The effective date of the rules:
60 days after filing with the Secretary of State

4. A list of all previous notices appearing in the Register addressing the final rules:
Notice of Docket Opening: 9 A.A.R. 390, February 7, 2003
Notice of Proposed Rulemaking: 9 A.A.R. 763, March 7, 2003

5. The name and address of agency perso nnel with whom persons may communicate
regarding the rulemaking

. Name: Deborrah “Corky” Martinkovic
Address: ADEQ, Air Quality Planning S ection, 1110 West Washington Street,ADEQ RAVI NFRM, 8/11/03+ 2 Phoenix, AZ 85007
Telephone: (602) 771-2372 (Any extension ma y be reached in-state by dialing 1-
800-234-5677, and asking for a specific number.)
Fax: (602) 771-2366

E-mail: martinkovic.deborrah@ev.state.az.us

6. An explanation of the rules, including the agency’s reasons for initiating the rules : Summary. This rule sets forth the process Arizona De partment of Environmental Quality (ADEQ) will

use to determine whether Best Available Retrofit Technology (BART) will be required for sources
determined to be contributing to visibility impairme nt in a mandatory Federal Class I area. Federal
regulations allow Federal Land Managers (FLMs) to certify sources defined in 40 CFR 51.301 as
potential contributors to visibility impairment in any of the Arizona mandatory Federal Class I areas
under Section 169A of the Clean Air Act (CAA).

Background. In 1977 Congress added a new section to th e Clean Air Act - Section 169A, Visibility

Protection for Federal Class I Areas - which established a national goal for, “the prevention of any future,
and the remedying of any existing impairment of vi sibility in mandatory class I Federal areas which
impairment results from man-made air pollution.” In addition, the section required states to submit state
implementation plans (SIPs) requiring best availa ble retrofit technology (BART) for certain existing
stationary sources found to cause or contribute to visibility impairment. On November 30, 1979, EPA
promulgated a list of mandatory Federal Class I Areas (Class I areas) where visibility is an important
value (44 FR 69122). There are 12 Class I areas identified in Arizona: Chiricahua National Monument
Wilderness, Chiricahua Wilderness, Galiuro Wilderness, Grand Canyon National Park, Mazatzal
Wilderness, Mount Baldy Wilderness, Petrified Forest National Park, Pine Mountain Wilderness, Saguaro
Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore Canyon Wilderness (40
CFR 81.403).

On December 2, 1980 (45 FR 80 084), EPA defined the role of the FLMs in certifying visibility
impairment in the mandatory Federal Class I area s. On November 24, 1987 (52 FR 45132), FLMs
identified Petrified Forest National Park, Sagua ro Wilderness, and Grand Canyon National Park, as
having visibility impairment possibly attributable to stationary sources. Under the 1980 rule, if found to
cause or contribute to the impairment, certain exis ting stationary sources operating in or near the
identified Class I areas could be subject to BART (A list of sources eligible for the possible application ofADEQ RAVI NFRM, 8/11/03+ 3 BART can be found at 40 CFR 51.301). On October 3, 1991, the Navajo Generating Station (NGS) was
found by EPA to be causing or contributing to visi bility impairment for the Grand Canyon National Park
and eligible for BART (56 FR 50172). BART contro l analyses were subsequently performed by EPA,
and other parties through related cour t actions. Under the 1980 rule, the fe deral expectation is that actions
for determination of possible source attribution will be performed by the states. Therefore, Arizona needs
to be prepared to proceed with an attribution analysis and assessment fo r the application of controls upon
any determination of a BART eligible source bein g the possible cause or contributor to visibility
impairment in a Class I area. This rule addresses that need.

Current Conditions. ADEQ has determined that this rule a pplies to any source in existing stationary
source categories identified in 40 CFR 51.301 that are operating in or near the mandatory federal Class I
areas in Arizona. The source is an existing stationary facility that includes any reconstructed source that
was not in operation prior to August 7, 1962, and was in existence on August 7, 1977, and has the
potential to emit 250 tons per year of any regulated pollutant. ADEQ estimates that there are potentially

10 such sources within Arizona. “In existence” is inte rpreted by EPA to be consistent with the term,

“commence construction” found in Prevention of Se rious Deterioration (PSD) regulations (40 CFR
51.165(a)(1)(xvi) and 40 CFR 52.21(b)(9)). If constr uction commenced after August 7, 1977, the source
would be subject to the PSD/NSR (new source revi ew) program (the state regulations are found at 18
A.C.C. 2, Article 4). However, EPA also notes “that sources, are not BART eligible if the only change at
the plant was the addition of pollution controls. Fo r example, if the only change at a copper smelter
during the 1962 through 1977 time period was the add ition of acid plants for the reduction of SO 2 emissions, these emission controls would not themselves trigger a BART review.” 1

Under this rule, ADEQ, when analyzing an attributab le source for BART controls, must consider several
factors including, for example, costs, remaining u seful life of the source, and degree of improvement
anticipated to result from the application of the contro ls (the factors are detailed in R18-2-1605). Sources
required by ADEQ to install and operate BART contro ls have a final opportunity to request exemption
from the requirement prior to the application of cont rols. This opportunity for a federal exemption from
BART, is contained in R18-2-1606, and 40 CFR 51.303.

Summary. This rule outlines the process through which s ources eligible for the application of BART will

1 EPA proposed rule, 66 Federal Register 38119, July 20, 2001.ADEQ RAVI NFRM, 8/11/03+ 4 proceed if certified by the state of Arizona or an FLM as possibly causing or contributing to visibility
impairment due to attribution. If found to be attr ibutable for the impairment , a BART analysis will be
performed to determine the level of controls necessar y to remedy the impairment. This rule enables
Arizona to fulfill the requirements of the Clean Air Ac t and the goal of section 169A of the Act to return
the Nation’s federal parks and wilderness areas to natural conditions.

Section-by-section Explanation for the Rule

R18-2-1601 This section lists the de finitions that apply to this rule.

R18-2-1602 This section lists the Class I ar eas addressed by this rule for the applicable
existing stationary facilities, as defined in R18-2-1601(2).
R18-2-1603 This section establishes the procedure for certification of impairment by either a
Federal Land Manager with authority over a mandatory Federal Class I area, or
the Director, should either believe there exists reasonably attributable visibility
impairment in a Federal Class I area as listed in R18-2-1602.
R18-2-1604 This section establishes the pro cedure for an attribution analysis after
certification of a source or group of so urces as outlined in R18-2-1603. Upon
completion of the attribution analysis, th e procedure for the Director to issue
draft and final attribution findings is outlined in R18-2-1604(C).
R18-2-1605 This section establishes the best available retrofit technology (BART) analysis
procedure after a source is identified un der R18-2-1604. Upon completion of the
BART analysis, the procedure for the Director to issue draft and final BART
findings, including alternatives to emission standards, is outlined in R18-2-
1605(B) and (C), respectively. The specific conditions where BART would be
satisfied due to past or planned actions by the facility are outlined in R18-2-
1605(D). EPA determinations regarding new technology that might require a
BART analysis for an applicable source, regardless of a source or small group of
sources previously being certified and f ound attributable, are covered in R18-2-
1605(E).
R18-2-1606 This section establishes the procedures for obtaining a federal exemption from a
BART requirement.

7. A reference to any study relevant to the rule that the agency reviewed and either relied on
in its evaluation of or justification for the rule or did not rely on in its evaluation of orADEQ RAVI NFRM, 8/11/03+ 5 justification for the rule, where the public m ay obtain or review each study, all data
underlying each study, and any analysis of each study and other supporting material:

None

8. A showing of good cause why the rules are nec essary to promote a statewide interest if the
rules will diminish a previous grant of authority of a political subdivision of this state:
Not applicable

9. The summary of the economic, small business, and consumer impact:

A. Rule Identification
These rules amend R18-2-101 (“visibility impairment ” definition) and add new sections R18-2-1601
through R18-2-1606. For sources under ADEQ jurisdiction, the rules take the place of federal regulations
that currently govern this area.

B. Entities Directly Impacted

1. Federal Land Managers. R18- 2-1603 allows Federal La nd Managers (FLMs) to certify visibility
impairment in mandatory Class I areas. This was alr eady allowed by federal ru le. Under R18-2-1601 of
the rule, the FLMs able to certify impairment in Ariz ona are with the United States Forest Service and the

National Park Service. There are no FLMs in Arizona from the United States Fish and Wildlife Service,
because this agency does not have jurisdiction over any of Arizona’s mandatory federal Class I areas.

2. ADEQ. R18-2-1604 requires ADEQ to identify stationary sources that could cause or contribute to the
certified visibility impairment. Prior to this rule , this function was carried out by EPA. R18-2-1605
would require ADEQ to analyze for BART (best ava ilable retrofit technology) controls those sources
identified as causing or contributing to visibility impairme nt. Prior to this rule, this function was carried
out by EPA. The impact of this rule on ADEQ will pr imarily be on the Air Quality Division, Permits and
Assessment sections, with a corr esponding reduction of impact on EPA.

3. Stationary sources. R18-2-1605 also requires sta tionary sources identified in #2 to install or operate
the BART as determined by the Director. Prior to this rule, only EPA determined and required BART.
To determine impacted stationary sources, ADEQ staff reviewed Title V permits from ADEQ’s Air
Permit files. Of the 26 industry categories listed in 40 CFR 51.301, only five categories were found toADEQ RAVI NFRM, 8/11/03+ 6 exist under ADEQ’s jurisdiction: steam electric plants , cement plants, primary copper smelters, lime
plants, and industries using non-utility boilers. As a r esult, potentially 10 sources, representing 16 BART
eligible units (boilers and kilns), could be affected by this rule. The combined potential to emit from
these sources totaled 94,287 tons per year for NO x , 141,036 tons per year for SO 2 , and 12,146 tons per
year for PM. The combined potential to emit for all pollutants for these 10 sources total approximately
250,000 tons per year.

C. Probable Costs and Benefits Associated with the BART/Visibility Impairment Process
1. Direct Costs - FLMs: FLM activities to certify visibility impairment in mandatory Class I areas may
involve preparation and analysis of monitoring data, emission inventories, meteor ological records, etc.
ADEQ estimates that this cost per certification coul d be as much as $50,000 if extensive analysis is

conducted. These costs exist whether or not these rules became final.

2. Direct Costs - ADEQ: ADEQ costs related to id entifying whether a BART eligible stationary source
causes or contributes to visibility impairment in Class I areas are based on the activities identified in R18-
2-1604(A). ADEQ estimates that these costs coul d range from $100,000 – 20 0,000 per attribution
analysis, and be primarily borne by the ADEQ’s Air Quality Assessment Section. Costs related to
analyzing identified sources for BART are based on th e activities identified in R18-2-1605(A) and will be
moderate, but less expensive than the attribution an alysis. These costs will be primarily borne by
ADEQ’s Permits Section. These costs will accrue to the State. Finally, incorporating BART into an
existing State air quality permit may require additiona l resources from the Permits Section. However,
these costs, unlike costs for the attribution and BART analysis, would be covered by permit revision fees
paid by the source, and would have existe d whether or not these rules became final.

3. Direct Costs - Stationary sources: If a source or small group of sources is found to cause or contribute
to visibility impairment, and the BART determination re quires installation of retrofit controls, the costs to
sources required to install BART will be substantial. The total cost to install a technology similar to
BART at the Navajo Generating Sta tion was estimated by SRP to be in the hundreds of millions of dollars
(51 Federal Register 50172, October 3, 1991). Howeve r, the example of the Navajo Generating Station
shows costs to install technology similar to BART can result even where there is no state rule. According
to EPA, “Where a State defaults on its obligations un der the visibility regulations, EPA may act in place
of the State pursuant to a FIP under section 110(c) of the Act, 42 U.S.C. 7410(c) 2 , and promulgate such
limitation and measures as are required to achieve reasonable progress.” (Ibid. at 50173, footnote notADEQ RAVI NFRM, 8/11/03+ 7 included). Although ADEQ is listing these costs for information purposes, ADEQ is not attributing any
costs to install and operate BART to this rule beca use such requirements can be imposed by the federal
government without any State rule.

Benefits. Two kinds of benefits are associated with this rule. The first benefit is derived from reduced
emissions. Although, BART could be required to be installed on sources even without this state rule, it is
helpful to list the emission benefits. When BART is installed, visibility is improved. Over 4 million
recreation visits were made to Grand Canyon National Park in FY 2001. These vis its generate substantial

revenue in and for the state of Arizona. Other scenic resources could also be improved with the
installation of BART, and, though less significant than the Grand Canyon, would enhance the tourism
resources of Arizona, as well as the quality of life fo r Arizona citizens. In addition, reduction of
visibility-impairing emissions also has health benefits.

The second benefit is through the replacement of federa l regulation with state regulation. The lack of
state regulations implementing BART results in Ar izona sources being subject to federal regulation
implemented by EPA from Washington and San Fran cisco, headquarters for EPA’s Region IX. These
rules place the identification and analysis of BART so urces with ADEQ rather than with EPA. Arizona is
currently under a visibility Federal Implementation Plan (FIP), and one or two Arizona sources have
considered or implemented technol ogy similar to BART under federal rules. Because ADEQ already
permits many of these sources, ADEQ will be more fam iliar with the various factors that go into the
BART analysis. This would be a benefit to sources being regulated. ADEQ would be implementing the
same BART rules that EPA does, with a resulting incr ease in costs for ADEQ and a decrease in costs for

EPA.

This final rule further allows ADEQ to proceed wi th the implementation of the entire federal rule for
visibility improvement. The rule addresses the re quirements of 40 C.F.R. §§51.302 – 51.307. These
sections must be satisfied before ADEQ can implem ent the requirements of 40 C.F.R. §§51.308 and
51.309. The plan to implement Section 309 mu st be submitted to EPA by December 31, 2003.

D. Small Business Analysis
A.R.S. § 41-1055(B)(5) requires agencies to state the probable impact of a rulemaking on small
businesses. A.R.S. § 41-1035 requires agencies to reduce the impact of a rule on small businesses by
using certain methods when they are legal and feasib le in meeting the statutory objectives for the ruleADEQ RAVI NFRM, 8/11/03+ 8 making. These methods include: (1) exempting them from any or all rule requirements, (2) establishing
performance standards which would replace any design or operational standards, or (3) instituting reduced
compliance or reporting requirements. An agency may accomplish the third method by establishing less
stringent requirements, consolidating or simplifying requirements, or setting less stringent schedules or

deadlines.

"Small business" is defined in A.R.S. §41-1001 as “a concern, including its affiliates, which is
independently owned and ope rated, which is not dominant in its fi eld and which employs fewer than one
hundred full-time employees or which had gross annual receipts of less than four million dollars in its last
fiscal year.” Interpreting this definition means that if a concern has annual gross receipts of more than
four million dollars, but fewer than 100 employees, it would not be classified as a small business.

ADEQ expects that none of the potential BART elig ible sources will be classified as a small business.
ADEQ’s conclusion is that this rule will not impact sm all business sources. However, if a BART eligible
source would qualify as a small business, under fe deral rule, ADEQ could not establish different
requirements for these small business sources. If ther e are any small businesses that sell, install, or
maintain BART-related technology, they will benefit from this rule.

In the preliminary EIS, ADEQ requested comment an d additional information relating to any of the
conclusions reached above and did not receive any.

10. A description of the changes between the propo sed rules, including supplemental notices, and
final rules (if applicable):
Changes were made with the cooperation of GRRC Staff to improve the clarity, conciseness and
understandability of the rule. The changes are shown below:

A new definition was placed at R18-2-101(71), to cl arify a term used in the proposed definition of
"visibility impairment" at R18-2-101(123):

71. “Natural conditions” includes naturally occurring phenomena that reduce visibility as
measured in terms of light extinction, visual range, contrast, or coloration.

In addition, the word "and" was removed from the definition of "visibility impairment", as

shown:ADEQ RAVI NFRM, 8/11/03+ 9 123 124 . “Visibility impairment” means any humanly perceptible change in visibility (light
extinction, visual range, contrast, and coloration) from that which w ould have existed under natural

conditions.
Both definitions are copied exactly from federal regulations at 40 CFR 51.308.

In addition, new Article 16 was amended as follows:
ARTICLE 16. VISIBILITY; REGIONAL HAZE

R18-2-1601. Definitions

In addition to the definitions cont ained in Articles 1 and 4 of this Chapter and A.R.S. § 49-401.01, the
following definitions apply to this Article:
1. “Best available retrofit technology (BART)” means an emission limitation based on the degree of
reduction achievable through the application of th e best system of continuous emission reduction
for each pollutant that is emitted by an existing stationary facility. The emission limitation is
established on a case-by-case basis in accordance with under R18-2-1605.
2. “Existing stationary facility” means any of th e following stationary sources of air pollutants,
including any reconstructed source, which was not in operation prior to before August 7, 1962,
and was in existence on August 7, 1977, and has th e potential to emit 250 tons per year or more
of any air pollutant. In determining A person who determines potential to emit, shall count
fugitive emissions, to the extent quantifiable, must be counted

. a. Fossil-fuel fired steam electric plants of more than 250 million British thermal units per
hour heat input, ; b. Coal cleaning plants (thermal dryers)

, ; c. Kraft pulp mills

, ; d. Portland cement plants

, ; e. Primary zinc smelters

, ; f. Iron and steel mill plants

, ; g. Primary aluminum ore reduction plants, ; h. Primary copper smelters, ; i. Municipal incinerators capable of char ging more than 250 tons of refuse per day, ; j. Hydrofluoric, sulfuric, and nitric acid plants, ; k. Petroleum refineries, ; l. Lime plants, ;ADEQ RAVI NFRM, 8/11/03+ 10 m. Phosphate rock processing plants, ; n. Coke oven batteries, ; o. Sulfur recovery plants, ; p. Carbon black plants (furnace process), ; q. Primary lead smelters, ; r. Fuel conversion plants, ; s. Sintering plants, ; t. Secondary metal production facilities, ; u. Chemical process plants, ;
v. Fossil-fuel boilers of more than 250 m illion British thermal units per hour heat input, ; w. Petroleum storage and transfer facilitie s with a capacity exceeding 300,000 barrels, ; x. Taconite ore processing facilities, ; y. Glass fiber processing plants, ; and
z. Charcoal production facilities.
3. “Federal Land Manager” means the Secretary of the department, or the Secretary's designee, with
authority over the Federal Class I area.
4. “Mandatory Federal Class I Area” means a ny area identified in 40 CFR §§81.400-81.436.
5. “Reasonably attributable” means ascribable by vi sual observation or other techniques the Director
deems appropriate described in R18-2-1604

. 6. “Reasonably attributable visibility impairment” means visibility impairment that is caused by the
emission of air pollutants from one source, or a small group of sources.

R18-2-1602. Applicability
This Article applies to any existing stationary s ource located in the state that may reasonably be
anticipated to cause or contribute to visibility impair ment in any mandatory Federal Class I area identified
in 40 CFR §§81.401-81.436. Mandatory Federal Class I areas within Arizona are: Chiricahua National
Monument Wilderness, Chiricahua Wilderness, Galiuro Wilderness, Grand Canyon National Park,
Mazatzal Wilderness, Mount Baldy Wilderness, Pe trified Forest National Park, Pine Mountain
Wilderness, Saguaro Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore
Canyon Wilderness.

R18-2-1603. Certification of Impairment

A. A Federal Land Manager with au thority over a mandatory Federal Class I area may certify to theADEQ RAVI NFRM, 8/11/03+ 11 Director, at any time, that there exists a reasonably attributable visibility impairment exists in the

a mandatory Federal Class I area. The Director may also certify that there exists reasonably
attributable visibility impairment exists in any mandatory Federal Class I area as necessary to assure reasonable progress under section 169A(b)(2) of the Clean Air Act.

B. Documentation from the affected Federal Land Manager or Director that supports the Federal
Land Manager or Director’s certification shall include:
1. The mandatory Federal Class I area for wh ich visibility impairment is being certified,
2. Any information documenting the b asis for the certification of impairment.

R18-2-1604. Attribution Analysis; Finding

A. Upon certification of reasonably attributable visibility impairment in any mandatory Federal

Class I area If a mandatory Federal Class I area is certified as having reasonably attributable
visibility impairment , the Director shall conduct an attribution analysis to identify each existing
stationary source that may be reasonably anticipated to cause or contribute to visibility
impairment. The Director shall notify the Federa l Land Manager, affected source or small group
of sources, and local air pollution control officer of the intent to conduct an attribution analysis.
The attribution analysis sha ll be based on the following:
1. Monitoring information obtained thr ough the Arizona Class I Visibility Monitoring
Network or special studies approved by ADEQ to ascertain:
a. The times visibility impairment occurred, and
b. The pollutants contributing to the visibility impairment. ; 2. Transport analysis or air quality mode ling based upon meteorological records to ascertain
whether the pollutants were transported to the mandatory Federal Class I area. ; 3. Other available studies, modeling analyses, and emissions inventories of point, area, and

mobile source emissions to ascertain:
a. The pollutant or pollutants causing the impairment, and
b. The source, or a small group of sources, emitting the impairing pollutant; or pollutants.
4. Other relevant supporting documentati on provided by the Federal Land Manager or
Director used to make the draft attribution analysis finding. ; and
5. Consideration of any documentation provided by the source, or a small group of sources.

, or other interested parties

. B. In conducting the attribution analysis, the Director shall use monitoring information,ADEQ RAVI NFRM, 8/11/03+ 12 meteorological records, and emissions inventori es that represent times and locations reasonably
concurrent with the visibility impairment.

C. The Director shall issue a draft attribution finding that impairment has or has not occurred, and
provide public notice of the draft attribution finding. The Director shall publish notice of the draft
attribution finding in a newspape r of general circulation in each county containing the mandatory

Federal Class I area and the affected source. The Director shall provide at least 30 days from the
date of the notice for public comment. Written co mments to the Director shall include the name
of the person and the person’s agent or attorney, if any, and shall clearly set forth reasons why the

Director should review the draft attribution finding should be reviewed . The Director shall issue

A a final attribution finding shall be issued after the public comment period. If the Director finds
existing stationary sources found to cause or contribute to visibility impairment in a mandatory
Federal Class I area, the source shall be subject to a BART Control Analysis under R18-2-1605.

R18-2-1605. BART Control Analysis; Finding

A. The Director shall analyze for BART controls each existing stationary source for which a final
attribution finding is made under R18-2-1604(C). The Director shall consider the following

factors:
1. Available control technology;
2. New source performance standards (NSPS) as adopted in Article 9;
3. Alternative control systems if retrofitti ng to comply with applicable NSPS standards
adopted in Article 9 is found infeasible. ; 4. Cost of compliance;
5. Energy and non-air quality environmental impacts of compliance;
6. Existing pollution control technology in use at the source or small group of sources;
7. Remaining useful life of th e source or small group of sources;
8. Net environmental impact associated with the proposed emission control system;
9. Economic impacts associated with insta lling and operating the proposed emission control
system; and
10. Degree of improvement in visibility anticipa ted to result from application of the proposed
emission control system.

B. The Director shall issue a draft BART finding, and provide public notice of the draft BART
finding. The Director shall publish notice of the draft BART finding in a newspaper of general
circulation in each county containing the mandatory Federal Class I area and the affected source.ADEQ RAVI NFRM, 8/11/03+ 13 The Director shall provide at least 30 days from the date of the notice for public comment.

Written comments to the Director shall include th e name of the person and the person’s agent or
attorney, and shall clearly set forth reasons why the Director should review the draft BART
finding should be reviewed . The Director shall issue a final BART finding after the public
comment period.

1. The Director shall submit each final BART finding that an existing stationary source is
required to meet BART to the Administrator as a revision to the state implementation
plan ( SIP)

. 2. The Director shall require that each existing stationary source meet BART
as expeditiously as practicable but in no case later than five years after EPA approval of

the revisio n to Arizona’s State Implementation Plan SIP revision

. C. If the Director determines that technological or economic limitations on the applicability of
measurement methodology to a particular existi ng stationary source would make the imposition
of an emission standard infeasible, the Director may, as part of the finding under subsection (B),

instead prescribe a design, equipment, work practice, or other operational standard, or

combination thereof of design, equipment, work practice, or operational standard . Such The
standard, to the degree possible, is to shall set forth the emission reduction to be achieved by
implementation of such the design, equipment, work practice, or operation, and must shall
provide for compliance by means which that achieve equivalent results.

D. The Director shall make a finding that the attributable source has satisfied satisfies the BART
requirement if the attributable source has : 1. Voluntarily applied applies best available retrofit technology;
2. Previously applied emission control standards equivalent to BART; or
3. Agreed Agrees to shutdown or curtail operations at the attributable source within 5 five
years of the finding. An attributable source that does not shutdown or curtail operations

shall
proceed to meet BART as expeditiously as practicable, but in no case later than five
years after EPA’s approval of the revisi on to Arizona’s State Implementation Plan the

SIP

. E. If the Director determines that the imposition of BART or a standard pursuant to under subsection
(C) of this section is not feasible infeasible at the time of the finding, the Director shall require
the attributable source shall be required to install and operate BART upon a determination by the

Director at a later date when the Director determines that BART or equivalent controls are nowADEQ RAVI NFRM, 8/11/03+ 14 feasible.

F. The Director shall provide for a BART control an alysis of any existing stationary source that
might cause or contribute to impairment of vi sibility in any mandatory Federal Class I area
identified under this Article at such times, as determined by the Administrator, determines new
control technology for control of the pollutant becomes reasonably available if:
1. The pollutant is emitted by th at existing stationary source,
2. Controls representing BART for the polluta nt have not previously been required under
this Article, and
3. The impairment of visibility in any mandatory Federal Class I area is reasonably
attributable to the emissions of that pollutant.

R18-2-1606. Exemption from BART
Any existing stationary source required to inst all, operate, and maintain BART pursuant to under this
Article, may apply to the Administrator for an ex emption from that requirement according to 40 CFR

51.303. by obtaining prior written concurrence from th e Director according to 40 CFR 51.303. The
existing stationary source shall obtain the Director’s written concurrence before sending the application
for exemption to the Administrator.

11. A summary of the comments made regardi ng the rule and the agency response to them:
ADEQ received one written comment. It expressed general support for the rule and for protecting
visibility in Arizona’s Class I parks and wilderness areas.

Comment: ADEQ received an oral comment that th e word “facility” should be replaced by

"source” in the definitions of “best available retrof it technology” and “existing stationary facility” to

be consistent with the rest of the rule.
Response: ADEQ has kept these definitions the same as the federal definitions to ensure
consistency. The definitions use the term “sour ce” to define the terms, and “source” is used
thereafter in the rules. ADEQ is not aware of any inconsistency.

12. Any other matters prescribed by statute that are applicable to the specific agency or to any
specific rule or class of rules:
Not applicableADEQ RAVI NFRM, 8/11/03+ 15 13. Incorporation by reference and their location in the rule:
Not applicable

14. Were these rules previously adopted as emergency rules?

No

15. The full text of the rule follows:ADEQ RAVI NFRM, 8/11/03+ 16 TITLE 18. ENVIRONMENTAL QUALITY
CHAPTER 2. DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR POLLUTION CONTROL

ARTICLE 1. GENERAL

Section

R18-2-101 Definitions

ARTICLE 16. VISIBILITY; REGIONAL HAZE

Section

R18-2-1601 Definitions

R18-2-1602 Applicability

R18-2-1603 Certification of Impairment

R18-2-1604 Attribution Analysis; Finding

R18-2-1605 BART Control Analysis; Finding

R18-2-1606 Exemption from BARTADEQ RAVI NFRM, 8/11/03+ 17 ARTICLE 1. GENERAL

R18-2-101. Definitions
In addition to the definitions prescribed in A.R.S. §§ 49-101, 49-401.01, 49-4 21, 49-471, and 49-541, in
this Chapter, unless otherwise specified:
1. No change
2. No change
a. No change
b. No change
c. No change
d. No change
e. No change
3. No change
4. No change
5. No change
6. No change
7. No change
8. No change
9. No change
10. No change
a. No change
b. No change
c. No change
d. No change
e. No change
f. No change
11. No change
a. No change
b. No change
c. No change
12. No change
13. No change
14. No changeADEQ RAVI NFRM, 8/11/03+ 18 a. No change
b. No change
15. No change
16. No change
17. No change
18. No change
19. No change
20. No change
21. No change
22. No change
23. No change
24. No change
25. No change
26. No change
27. No change
a. No change
b. No change
28. No change
29. No change
30. No change
31. No change
32. No change
33. No change
34. No change
35. No change
36. No change
37. No change
38. No change
39. No change
40. No change.
41 No change
42. No change
a. No changeADEQ RAVI NFRM, 8/11/03+ 19 b. No change
c. No change
d. No change
e. No change
f. No change
g. No change
h. No change
i. No change
j. No change
k. No change
l. No change
43. No change
44. No change
a. No change
b. No change
c. No change
d. No change
45. No change
46. No change
47. No change
48. No change
49. No change
50. No change
51. No change
52. No change
53. No change
54. No change
55. No change
56. No change
57. No change
a. No change
b. No change
c. No changeADEQ RAVI NFRM, 8/11/03+ 20 d. No change
e. No change
f. No change
g. No change
h. No change
i. No change
j. No change
58. No change
59. No change
60. No change
61. No change
62. No change
63. No change
a. No change
b. No change
c. No change
i. No change
ii. No change
iii. No change
iv. No change
v. No change
(1) No change
(2) No change
vi. No change
vii. No change
viii. No change
(1) No change
(2) No change
ix. No change
(1) No change
(2) No change
x. No change
xi. No changeADEQ RAVI NFRM, 8/11/03+ 21 64. No change
a. No change
b. No change
i. No change
ii. No change
c. No change
i. No change
ii. No change
iii. No change
iv. No change
v. No change
vi. No change
vii. No change
viii. No change
ix. No change
x. No change
xi. No change
xii. No change
xiii. No change
xiv. No change
xv. No change
xvi. No change
xvii. No change
xviii. No change
xix. No change
xx. No change
xxi. No change
xxii. No change
xxiii. No change
xxiv. No change
xxv. No change
xxvi. No change
xxvii. No changeADEQ RAVI NFRM, 8/11/03+ 22 65. No change
66. No change
67. No change
68. No change
69. No change
70. No change

71. “Natural conditions” includes naturally occurring phenomena that reduce visibility as
measured in terms of light extinction, visual range, contrast, or coloration.

71. 72. No change

72. 73. No change
a. No change
i. No change
ii. No change
b. No change
i. No change
ii. No change
c. No change
d. No change
e. No change
f. No change
i. No change
ii. No change
iii. No change
iv. No change
g. No change

73. 74. No change

74. 75. No change

75. 76. No change

76. 77. No change

77. 78. No change

78. 79. No change

79. 80. No change

80. 81. No changeADEQ RAVI NFRM, 8/11/03+ 23 81. 82. No change

82. 83. No change

83. 84. No change
a. No change
b. No change
c. No change
d. No change

84. 85. No change

85. 86. No change

86. 87. No change

87. 88. No change

88. 89. No change

89. 90. No change

90. 91. No change

91. 92. No change

92. 93. No change

93. 94. No change

94. 95. No change
a. No change
b. No change
c. No change
d. No change

95. 96. No change

96. 97. No change

97. 98. No change
a. No change
b. No change
c. No change
d. No change
e. No change

98. 99. No change
a. No change
i. No changeADEQ RAVI NFRM, 8/11/03+ 24 ii. No change
iii. No change
iv. No change
v. No change
vi. No change
vii. No change
b. No change
c. No change

99. 100. No change
a. No change
b. No change

100. 101. No change

101. 102. No change

102. 103. No change

103. 104. No change

104. 105. No change
a. No change
b. No change
c. No change
d. No change

105. 106. No change

106. 107. No change

107. 108. No change
a. No change
b. No change

108. 109. No change

109. 110. No change

110. 111. No change

111. 112. No change

112. 113. No change

113. 114. No change

114. 115. No change

115. 116. No changeADEQ RAVI NFRM, 8/11/03+ 25 116. 117. No change

117. 118. No change
a. No change
b. No change
c. No change
d. No change
e. No change
f. No change
g. No change
h. No change
i. No change
j. No change
k. No change
l. No change
m. No change
n. No change
o. No change
p. No change
q. No change
r. No change
s. No change
t. No change
u. No change
v. No change
w. No change
x. No change
y. No change
z. No change
aa. No change
bb. No change
cc. No change
dd. No change
ee. No changeADEQ RAVI NFRM, 8/11/03+ 26 ff. No change
gg. No change
hh. No change
ii. No change
jj. No change
kk. No change
ll. No change
mm. No change
nn. No change
oo. No change
pp. No change
qq. No change
rr. No change
ss. No change
tt. No change
uu. No change
vv. No change
ww. No change
xx. No change

118. 119. No change

119. 120. No change

120. 121. No change

121. 122. No change

122. 123. No change

123. 124. “Visibility impairment” means any human ly perceptible change in visibility
(light extinction, visual range, contrast, coloration ) from that which would have

existed under natural conditions.

124. 125. No change

125. 126. No change
a. No change
b. No change
c. No change
d. No changeADEQ RAVI NFRM, 8/11/03+ 27 e. No change
f. No change
g. No change
h. No change
i. No change
j. No change
k. No change
l. No change
m. No change
n. No change
o. No change
p. No change
q. No change
r. No change
s. No change
t. No change
u. No change
v. No change
w. No change
x. No change
y. No change
z. No change
aa. No change
bb. No change
cc. No change
dd. No change
ee. No change
ff. No change
gg. No change
hh. No change
ii. No change
jj. No change
kk. No changeADEQ RAVI NFRM, 8/11/03+ 28 ll. No change
mm. No change
nn. No change
oo. No change
pp. No change
qq. No change
rr. No change
ss. No change
i. No change
ii. No change
iii. No change
iv. No change

126. 127. No change

ARTICLE 16. VISIBILITY; REGIONAL HAZE

R18-2-1601. Definitions

In addition to the definitions cont ained in Articles 1 and 4 of this Chapter and A.R.S. § 49-401.01, the
following definitions apply to this Article:

1. “Best available retrofit technology (BART)” means an emission limitation based on the degree of
reduction achievable through the application of th e best system of continuous emission reduction
for each pollutant emitted by an existing stati onary facility. The emission limitation is
established on a case-by-case basis under R18-2-1605.

2. “Existing stationary facility” means any of the following stationary sources of air pollutants,
including any reconstructed source, which was not in operation before August 7, 1962, and was in
existence on August 7, 1977, and has the potential to emit 250 tons per year or more of any air
pollutant. A person who determines potential to em it shall count fugitive em issions to the extent
quantifiable.
a. Fossil-fuel fired steam electric plants of more than 250 million British thermal units per
hour heat input;
b. Coal cleaning plants (thermal dryers);
c. Kraft pulp mills;
d. Portland cement plants;ADEQ RAVI NFRM, 8/11/03+ 29 e. Primary zinc smelters;
f. Iron and steel mill plants;
g. Primary aluminum ore reduction plants;
h. Primary copper smelters;
i. Municipal incinerators capable of chargi ng more than 250 tons of refuse per day;
j. Hydrofluoric, sulfuric, and nitric acid plants;
k. Petroleum refineries;
l. Lime plants;
m. Phosphate rock processing plants;
n. Coke oven batteries;
o. Sulfur recovery plants;
p. Carbon black plants (furnace process);
q. Primary lead smelters;
r. Fuel conversion plants;
s. Sintering plants;
t. Secondary metal production facilities;
u. Chemical process plants;

v. Fossil-fuel boilers of more than 250 m illion British thermal units per hour heat input;
w. Petroleum storage and transfer facilitie s with a capacity exceeding 300,000 barrels;
x. Taconite ore processing facilities;
y. Glass fiber processing plants; and
z. Charcoal production facilities.

3. “Federal Land Manager” means the Secretary of the department, or the Secretary's designee, with
authority over the Federal Class I area.

4. “Mandatory Federal Class I Area” means a ny area identified in 40 CFR §§81.400-81.436.

5. “Reasonably attributable” means ascribable by visual observation or other techniques described

in R18-2-1604.

6. “Reasonably attributable visibility impairment” m eans visibility impairment that is caused by the
emission of air pollutants from one source, or a small group of sources.

R18-2-1602. Applicability
This Article applies to any existing stationary s ource located in the state that may reasonably be
anticipated to cause or contribute to visibility impair ment in any mandatory Federal Class I area identifiedADEQ RAVI NFRM, 8/11/03+ 30 in 40 CFR §§81.401-81.436. Mandatory Federal Class I areas within Arizona are: Chiricahua National
Monument Wilderness, Chiricahua Wilderness, Galiuro Wilderness, Grand Canyon National Park,
Mazatzal Wilderness, Mount Baldy Wilderness, Pe trified Forest National Park, Pine Mountain
Wilderness, Saguaro Wilderness, Sierra Ancha Wilderness, Superstition Wilderness, and Sycamore
Canyon Wilderness.

R18-2-1603. Certification of Impairment

A. A Federal Land Manager with au thority over a mandatory Federal Class I area may certify to the
Director, at any time, that a reasonably attributab le visibility impairment exists in a mandatory
Federal Class I area. The Director may also certify that reasonably attributable visibility
impairment exists in any mandatory Federa l Class I area to assure reasonable progress under
section 169A(b)(2) of the Clean Air Act.

B. Documentation that supports the Federal Land Manager or Director’s certification shall include:

1. The mandatory Federal Class I area for whic h visibility impairment is being certified,

2 . Any information documenting the basis for the certification of impairment.

R18-2-1604. Attribution Analysis; Finding

A. If a mandatory Federal Class I area is cer tified as having reasonably attributable visibility
impairment, the Director shall conduct an attribu tion analysis to identify each existing stationary
source that may be reasonably anticipated to cau se or contribute to visibility impairment. The
Director shall notify the Federal Land Manager, affected source or small group of sources, and
local air pollution control officer of the intent to conduct an attribution analysis. The attribution
analysis shall be based on the following:

1. Monitoring information obtained throu gh the Arizona Class I Visibility Monitoring
Network or special studies approved by ADEQ to ascertain:

a. The times visibility impairment occurred, and

b. The pollutants contributing to the visibility impairment;

2. Transport analysis or air quality modelin g based upon meteorological records to ascertain
whether the pollutants were transported to the mandatory Federal Class I area;

3. Other available studies, modeling analyses, and emissions inventories of point, area, and

mobile source emissions to ascertain:

a. The pollutant causing the impairment, and

b. The source, or a small group of sources, emitting the pollutant;ADEQ RAVI NFRM, 8/11/03+ 31 4. Other relevant supporting documentation provided by the Federal Land Manager or
Director used to make the draft attribution analysis finding; and

5. Consideration of any documentation provided by the source, a small group of sources; or
other interested parties.

B. In conducting the attribution analysis, the Director shall use monitoring information,
meteorological records, and emissions inventori es that represent times and locations reasonably
concurrent with the visibility impairment.

C. The Director shall issue a draft attribution finding that impairment has or has not occurred, and
provide public notice of the draft attribution finding. The Director shall publish notice of the draft
attribution finding in a newspape r of general circulation in each county containing the mandatory

Federal Class I area and the affected source. The Director shall provide at least 30 days from the
date of the notice for public comment. Written co mments to the Director shall include the name
of the person and the person’s agent or attorney, if any, and shall clearly set forth reasons why the
Director should review the draft attribution finding. The Director shall issue a final attribution
finding after the public comment period. If the Di rector finds existing stationary sources cause or
contribute to visibility impairment in a mandatory Federal Class I area, the source shall be subject
to a BART Control Analysis under R18-2-1605.

R18-2-1605. BART Control Analysis; Finding

A. The Director shall analyze for BART controls each existing stationary source for which a final
attribution finding is made under R18-2-1604(C). The Director shall consider the following

factors:

1. Available control technology;

2. New source performance standards (NSPS) in Article 9;

3. Alternative control systems if retrofitting to comply with applicable NSPS standards
in Article 9 is infeasible;

4. Cost of compliance;

5. Energy and non-air quality environmental impacts of compliance;

6. Existing pollution control technology in use at the source or small group of sources;

7. Remaining useful life of the source or small group of sources;

8. Net environmental impact associated with the proposed emission control system;

9. Economic impacts associated with installi ng and operating the proposed emission control
system; andADEQ RAVI NFRM, 8/11/03+ 32 10. Degree of improvement in visibility anticipate d to result from application of the proposed
emission control system.

B. The Director shall issue a draft BART finding, and provide public notice of the draft BART
finding. The Director shall publish notice of the draft BART finding in a newspaper of general
circulation in each county containing the mandatory Federal Class I area and the affected source.
The Director shall provide at least 30 days from the date of the notice for public comment.

Written comments to the Director shall include th e name of the person and the person’s agent or
attorney, and shall clearly set forth reasons w hy the Director should review the draft BART
finding. The Director shall issue a final BART finding after the public comment period.

1. The Director shall submit each final BART finding to the Administrator as a revision to

the SIP.

2. The Director shall require that each existing stationary source meet BART
as expeditiously as practicable but in no case later than five years after EPA approval of

the SIP revision.

C. If the Director determines that technological or economic limitations on the applicability of
measurement methodology to a particular existi ng stationary source would make the imposition
of an emission standard infeasible, the Director may, as part of the finding under subsection (B),
prescribe a design, equipment, work practice, operational standard, or combination of design,
equipment, work practice, or operational standard. The standard, to the degree possible, shall set
forth the emission reduction to be achieved by im plementation of the design, equipment, work
practice, or operation, and shall provide for comp liance by means that achieve equivalent results.

D. The Director shall make a finding that the a ttributable source satisfies the BART requirement if

the attributable source:

1. Voluntarily applies best available retrofit technology;

2. Previously applied emission control standards equivalent to BART; or

3. Agrees to shutdown or curtail operations at the attributable source within five years of the
finding. An attributable source that does not shutdown or curtail operations shall
meet BART as expeditiously as practicable, but in no case later than five years after
EPA’s approval of the revision to the SIP.

E. If the Director determines that the imposition of BART or a standard under subsection (C) is
infeasible at the time of the finding, the Director sh all require the attributable source to install and
operate BART at a later date when the Director determines that BART or equivalent controls are

feasible.ADEQ RAVI NFRM, 8/11/03+ 33 F. The Director shall provide for a BART control an alysis of any existing stationary source that
might cause or contribute to impairment of vi sibility in any mandatory Federal Class I area

identified under this Article at such time as th e Administrator determines new control technology
for the pollutant becomes reasonably available:

1. The pollutant is emitted by that existing stationary source,

2. Controls representing BART for the pollutant have not previously been required under
this Article, and

3. The impairment of visibility in any mandatory Federal Class I area is reasonably
attributable to the emissions of that pollutant.

R18-2-1606. Exemption from BART
Any existing stationary source required to install, operate, and maintain BART under this Article, may
apply to the Administrator for an exemption from that requirement according to 40 CFR 51.303. The
existing stationary source shall obtain the Director’s written concurrence before sending the application
for exemption to the Administrator.Appendix A-5 – Attributable Impairment Arizona Regional Haze SIP 

## Appendix A-5d. New source review rule - R18-2-410R18-2-410. Visibility Protection A. For any new major source or major modification subjec t to the provisions of this Chapter, no permit or permit revision under this Article shall be i ssued to a person proposing to construct or modify the source unless the applicant has provided: 1. An analysis of the anticipated impacts of the proposed source on visibility in any Class I areas which may be affected by the emissions from that source; and 2. Results of monitoring of visibility in any area near the proposed source for such pur poses and by such means as the Director determines is necessary and appropriate. B. A determination of an adverse impact on visibility shal l be made based on consideration of all of the following factors: 1. The times of visitor use of the area; 2. The frequency and timing of natural cond itions in the area that reduce visibility; 3. All of the following visibili ty impairment characteristics: a. Geographic extent, b. Intensity, c. Duration, d. Frequency, e. Time of day; 4. The correlation between the characteristics listed in subsection (B)(3) and the factors described in subsections (B)(1) and (2). C. The Director shall not issue a permit or permit revision pursuant to this Article or Article 3 of this Chapter for any new major source or major modificati on subject to this Chapter unless the following requirements have been met: 1. The Director shall notify the individuals identified in subsection (C)(2) within 30 days of receipt of any advance notification of any such permit or pe rmit revision under this Article. 2. Within 30 days of receipt of an application for a permit or permit revision under this Article for a source whose emissions may affect a Class I area, the Director shall provide written notification of the application to the Federal Land Manager and the federal official charged with direct responsibility for management of any lands within any such area. The notice shall: a. Include a copy of all information relevant to the permit or permit revision under this Article, b. Include an analysis of the anti cipated impacts of the proposed source on visibility in any area which may be affected by emissions from the source, and c. Provide for no less than a 30-day period within which written comments may be submitted. 3. The Director shall consider any analysis provided by the Federal Land Manager that is received within the comment period provided in subsection (C)(2). a. Where the Director finds that the analysis provide d by the Federal Land Manager does not demonstrate to the satisfaction of the Director that an adverse impact on visibility will result in the area, the Director shall, within the public notice required under R18-2-330, either explain the decision or specify where the explanation can be obtained. b. When the Director finds that the analysis provi ded by the Federal Land Mana ger demonstrates to the satisfaction of the Director that an adverse impact on visibility will result in the area, the Director shall not issue a permit or permit revision under this Ar ticle for the proposed major new source or major modification. 4. When the proposed permit decision is made, pursuant to R18-2-304(J), and available for public review, the Director shall provide the individuals identified in subsection (C)(2) with a copy of the proposed permit decision and shall make available to them any materials used in making that determination.

Historical Note Adopted effective May 14, 1979 (Supp. 79-1). Former S ection R9-3-410 renumbered w ithout change as Section R18-2-410 (Supp. 87-3). Section R18-2-410 renumbered to R18-2-610, new Section R18-2-410 adopted effective November 15, 1993 (Supp. 93-4).Appendix A-6 – Clean Air Corridor Arizona Regional Haze SIP 

## APPENDIX A-6. CLEAN AIR CORRIDOR

This appendix contains work products a nd references relied u pon by Arizona in the development of Chapter 6 of the Regional Haze SIP.Appendix A-6 – Clean Air Corridor Arizona Regional Haze SIP 

## Appendix A-6a. WRAP Policy on Clean Air Corridors

## WRAP Policy on Clean Air Corridors

Approved by WRAP Board November 13, 2002

I. Summary of WRAP Policy

1. Pursuant to 40 CFR 51.309(d)(3), the WRAP directs its Technical Oversight Committee (TOC) to track emissions and to describe the tracking process in such a way that can be included in state and tribal implementation plans. At a minimum, using the most recent state emission inventories available, the TOC should produce a report for each five-year implementation plan revision on the current and projected emissions in the clean air corridor and in areas outside the corridor and compare these emissions to a 1996 baseline for purposes of this section.

2. Pursuant to 40 CFR 51.309(d)(3)(i), the WRAP identifies one clean air corridor as shown in Figure 1 . The counties within the corridor are listed in Table 1 . For ease of administration, the corridor’s boundary follows county lines.

3. Pursuant to 40 CFR 51.309(d)(3)(ii), the WRAP has examined patterns of growth in the corridor and finds that they are not causing significant emission increases that could have or are having visibility impacts at one or more of the 16 Class I areas. Nor, at this time, are such emission increases expected during the first planning period (2003-2018). Analyses performed by the Grand Canyon Visibility Transport Commission found that an increase of 25% in weighted emissions would result in a 0.7 dv reduction in visibility, whereas the weighted emission increase expected by 2018 is only 4%.

4. Pursuant to 40 CFR 51.309(d)(3)(iii), the WRAP has examined emissions growth in areas outside the corridor and finds that significant emissions growth is not occurring that could begin or is beginning to impair the quality of the air in the corridor and thereby lead to visibility degradation for the least impaired days in one or more of the 16 Class I areas.

5. Since impairment of air quality in clean air corridors has not been identified pursuant to 40 CFR 51.309(d)(3)(ii) and (iii), the WRAP finds no requirement under 40 CFR 51.309(d)(3)(iv) for further visibility impact analysis or additional emission reduction measures until at least the next SIP revision (2008). However, the WRAP encourages its appropriate technical activities – such as the Causes of Haze report – to take into account the assessment and protection of clean air corridors.

6. Pursuant to 40 CFR 51.309(d)(3)(v), the WRAP finds no other clean air corridors beyond the corridor identified in Figure 1

.

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 2

II. Clean Air Corridors, The Clean Air Act, And The Regional Haze Rule

The Clean Air Act Amendments of 1990 specifically require that visibility transport commissions, including the Grand Canyon Visibility Transport Commission (“Commission”), address “the establishment of clean air corridors, in which additional restrictions on increases in emissions may be appropriate to protect visibility in affected class I areas.” 1 

### The Clean Air Act also requires protection of clean air corridors in a less direct way. The Act establishes as a national goal the prevention of any future impairment of visibility in mandatory Class I areas. As a measure of progress towards this goal, the U.S. Environmental Protection Agency (EPA) has established a criteria of no degradation on the 20% cleanest days. Such days on the Colorado Plateau are usually dominated by northwest winds, hence defining a corridor to the northwest that must be protected to meet the broader visibility goal of the Clean Air Act.

In its regional haze rule, the EPA provides more specificity on the requirements to protect clean air corridors, based largely on the recommendations of the Commission. The preamble of the rule defines a clean air corridor as “a region that generally brings clean air to a receptor region” The preamble also says, “the requirement to track emissions will enable states to quickly determine if changes in patterns of emissions will reduce the number of clean air days (defined as the average of the 20% clearest days) in any of the 16 Class I areas.” The actual requirements of the rule are found in 40 CFR 51.309(d)(3):

The [state implementation] plan must describe and provide for implementation of comprehensive emission tracking strategies for clean-air corridors to ensure that the visibility does not degrade on the least-impaired days at any of the 16 Class I areas. The strategy must include:

(i) An identification of clean-air corridors. The EPA will evaluate the State’s identification of such corridors based upon the reports of the Commission’s Meteorology Subcommittee and any future updates by a successor organization.

(ii) Within areas that are clean-air corridors, an identification of patterns of growth or specific sites of growth that could cause, or are causing, significant emissions increases that could have, or are having, visibility impairment at one or more of the 16 Class I

areas.

(iii) In areas outside of clean-air corridors, an identification of significant emissions growth that could begin, or is beginning, to impair the quality of air in the corridor and thereby lead to visibility degradation for the least-impaired days in one or more of the 16 Class I areas.

(iv) If impairment of air quality in clean air corridors is identified pursuant to §§51.309(d)(3)(ii) and (iii), an analysis of the effects of increased emissions, including provisions for the identification of the need for additional emission reductions measures, and implementation of the additional measures where necessary.

1 42 U.S.C. 2169B(d)(2)(A).

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 3

(v) A determination of whether other clean air corridors exist for any of the 16 Class I areas. For any such clean air corridors, an identification of the necessary measures to protect against future degradation of air quality in any of the 16 Class I areas.

These requirements do not apply to states submitting state implementation plans (SIPs) under §308 of the rule. However, such states should provide the data necessary for other states to comply and should make a good faith effort to protect the integrity of clean air corridors.

III. The Commission’s Findings and Recommendations

The Commission found that clean air corridors exist and that, generally, clean air comes to the Colorado Plateau from the northwest. 2 

### The Commission determined that one such corridor covers southern Utah, eastern Oregon, southwestern Idaho, and major portions of Nevada. This corridor was identified by the Commission’s Meteorology Subcommittee, which examined the size and boundaries of the corridor under varying assumptions about the number of days defined as clean and the amount of protection to be afforded. 3



### Related work by Green et. al. 4 

### identifies three factors that explain why air from the northwest is clean when it arrives at the Colorado Plateau: low emissions of air pollutants, enhanced dispersion of the air pollutants due to higher average ventilation (wind speed multiplied by mixing depth), and increased removal of pollutants due to precipitation. Although the corridor is mostly arid, the cleanest days occur most frequently in the winter, when there is more precipitation than average. Green et al., nonetheless, conclude that the most important factor at the south rim of the Grand Canyon for most weather conditions is the low emissions of pollutants in the area to the northwest.

In addition to identifying a clean air corridor, the Commission projected emissions growth within the corridor through 2040 and found that growth is not expected to have a perceptible negative impact on the cleanest days on the Colorado Plateau. Specifically, a working group within the Meteorology Subcommittee used results from the IAS model (the model used to project visibility impacts in other Commission work) to estimate the emissions increase from 1990 that would be necessary to cause a perceptible decrease in visibility on the Plateau. 5 

### The working group found that increasing emissions by 25% within the corridor would result in an average change of 0.7 deciviews (dv), which would be imperceptible to most people under most conditions, while a 100% increase in emissions within the corridor would result in a change of 2.5 dv. 6 

### This

2 Grand Canyon Visibility Transport Commission. Recommendations for Improving Western Vistas. Western

Governors’ Association. Denver, CO. June 1996.
3 Meteorological Subcommittee, Grand Canyon Visibility Transport Commission. Clean Air Corridors: A

Framework for Identifying Regions that Influence Clean Air on the Colorado Plateau. Denver, CO. August 1995.
4 Green, M. C.; Pitchford, M. L.; and Ashbaugh, L.L. Identification of Candidate Clean Air Corridors for the

Colorado Plateau. J. Air & Waste Manage. Assoc. 1996. 46(5), 446.
5 Marc Pitchford. Oral communication. October 3, 2002. Participants on the working group included Dr. Pitchford,

Dr. William Malm, and Dr. Ivar Tombach.

6 BBC Research & Consulting, Inc., for the Operations Committee of the Grand Canyon Visibility Transport

Commission. Clean Air Corridor: An Economic Perspective. Denver, CO. November 1995. Page III-2:6.

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 4

estimate was not based on a specific boundary for the corridor but rather on the general understanding of a corridor to the northwest of the Plateau. The implication, nonetheless, is that a 25% increase in emissions within the corridor could be considered a level of growth that would not impact visibility.

Using one of the proposed corridor alignments examined by the Meteorology Subcommittee – a corridor that would protect the 30% cleanest days on the Colorado Plateau, adjusted to account for emissions density and IAS region boundaries – BBC Research & Consulting conducted an economic and demographic assessment of the corridor to determine whether emissions would increase 25% by 2040. The assessment found that emissions are not expected to increase 25% by 2040. 7 

### Specifically, BBC used a weighting scheme defined in the IAS model to account for the varying effects of different pollutants on visibility. Total weighted emissions of elemental carbon, nitrogen oxides, organic carbon, particulate matter, reactive organic gases, and sulfur oxides in 1990 were 52,073 VEEU tons. 8 

### A 25% increase would yield 65,092 VEEU tons. BBC projected that emissions in the corridor would increase to 55,047 VEEU tons by 2040, thus leaving an ample margin of safety of 10,054 VEEU tons. 9



### As a result of these analyses, the Commission recommended that no targeted policies or regulatory programs to control emissions growth were needed at that time, but that a regional tracking and accounting system be implemented to make sure that the frequency of clear days does not decrease at the 16 Class I areas and that the Commission’s assumptions about increased emissions are proven reliable. The Commission recommended that, within areas that are sources of clean air, the tracking and accounting system should identify patterns of growth that have a negative impact on visibility and that, in areas outside the clean air corridors, the tracking and accounting system should identify significant emissions growth that begins to impair the quality of air in the corridor.

IV. WRAP Policy

A. E MISSIONS 

### T RACKING 

### – §309(d)(3)

The WRAP directs its Technical Oversight Committee (TOC) to track emissions and to describe the tracking process in such a way that can be included in state and tribal implementation plans. At a minimum, using the most recent state emission inventories available, the TOC should produce a report for each five-year implementation plan revision on the current and projected emissions in the clean air corridor and in areas outside the corridor and compare these emissions to a 1996 baseline for purposes of this section.

The tracking described above is intended to ensure that any unexpected changes are identified. This tracking would coincide with the periodic SIP revisions required in 2008, 2013, and 2018. States and tribes already prepare inventories at least every three years to meet federal

7 BBC report, page III-5
8 Visibility Equivalency Emission Units
9 BBC report, page III-6.

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 5

requirements and will prepare detailed inventories annually for sources of sulfur dioxide of 100 tons per year or greater for compliance with the stationary source provisions of §309. 10 

### The WRAP will use these state and tribal data for tracking emissions in general and can summarize emissions for the counties and tribal lands within the corridor and for areas outside the corridor for use by states and tribes as they revise their regional haze SIPs every five years. Further information on tracking point sources and area sources is provided below.

P OINT 

### S OURCES 

### . Any new, large source will be required to undergo a Prevention of Significant Deterioration review and an Air Quality Related Values analysis before receiving an air quality permit and will also be subject to New Source Performance Standards and other requirements, giving the public, states, tribes, and federal land managers ample opportunity to evaluate any possible visibility impacts on the 16 Class I areas. Thus, it is unlikely that point sources will lead to a 25% increase and even less likely that a trend in that direction would go unnoticed.

A REA 

### A ND 

### M OBILE 

### S OURCES 

### . Population and economic growth is expected to be slow in the corridor, holding down emissions from area and mobile sources within the corridor. Federal standards recently promulgated for on-road sources and additional ones pending for non-road sources are expected to reduce emissions from both of these source categories during the first planning period of the implementation plans (2018). However, emissions from prescribed burning are expected to increase and, depending on the location of the burns, could affect visibility in the 16 Class I areas. It is hard to predict how great the effect will be on clean days, but it is not expected to be severe. For one, prescribed fires generally occur in the spring and fall, whereas most clear days occur in the winter. In addition, prescribed fires are much less intense than wild fires. Nonetheless, careful fire emissions tracking is warranted and is being developed under separate WRAP policy and technical efforts.

B. B OUNDARY 

### O F 

### T HE 

### C LEAN 

### A IR 

### C ORRIDOR 

### – §309(d)(3)(i)

The WRAP identifies one clean air corridor as shown in Figure 1 . The counties within the corridor are listed in Table 1 . For ease of administration, the corridor’s boundary follows county lines.

The WRAP adopts this boundary based on a balancing of demographic, economic, and airquality impact analyses performed on this corridor and their subsequent review and consensusbased approval by the Commission. The boundary identified is a slight modification of the boundary defined in the BBC report described above. The grid cells in the air quality analyses did not follow state or county boundaries, and for ease of administration the WRAP has removed small areas of southern Washington and southwestern Montana from the corridor. These small areas are far from the Colorado Plateau and unlikely to affect the Class I areas on the Plateau. In contrast, counties have been added to the corridor that were not originally included in the boundary defined in the BBC report. These include Box Elder, Tooele, and Grand Counties in Utah, Wasco and Sherman Counties in Oregon, and Cassia and Lemhi Counties in Idaho.

10 Also see Western Regional Air Partnership. Voluntary Emissions Reduction Program for Major Industrial

Sources of Sulfur Dioxide in Nine Western States and a Backstop Market Trading Program, An Annex to the Report of the Grand Canyon Visibility Transport Commission. Denver, CO. September 29, 2000.

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 6

C. I DENTIFICATION 

### O F 

### E MISSIONS 

### I NCREASES 

### – §309(d)(3)(ii) and (iii)

Pursuant to 40 CFR 51.309(d)(3)(ii), the WRAP has examined patterns of growth in the corridor and finds that they are not causing significant emission increases that could have or are having visibility impacts at one or more of the 16 Class I areas. Nor, at this time, are such emission increases expected during the first planning period (2003-2018). Analyses performed by the Grand Canyon Visibility Transport Commission found that an increase of 25% in weighted emissions would result in a 0.7 dv reduction in visibility, whereas the weighted emission increase expected by 2018 is only 4%.

Patterns of growth in the corridor are first examined by comparing 1990 emissions (those used in the Commission’s final report) to 1996 emissions (the most recent comprehensive data set). This comparison is not easily made because emissions were aggregated into different categories. Nonetheless, it appears that emissions in 1996 were only slightly higher than in 1990. In the clean air corridor 73,637 tons of SO 2 

### were emitted in 1990 and 73,756 were emitted in 1996; 232,704 tons of NO x 

### were emitted in 1990 and 256,762 were emitted in 1996. In addition, the WRAP examined data from IMPROVE monitors and found that none of the seven long-term sites showed any significant decrease in visibility on the cleanest days for the period from 1988 through 1998. 11



### The WRAP is recommending, as part of this policy, that future clean air corridor analyses use a baseline year of 1996 to quantify emission increases. The first reason for this recommendation is that the 1996 inventory has been more carefully assembled than the 1990 inventory. The second reason is that future inventories are more likely to be structured like the 1996 inventory, thereby facilitating comparison. In addition, the most recent and comprehensive projection of emissions (discussed below) is based on the 1996 inventory, not the 1990 inventory.

The WRAP also examined emission projections. These are used as a means to identify potential future increases that should be more carefully tracked and to identify preventive measures that could be implemented in a timely fashion. Table 2 summarizes the projected change in emissions between 1996 and 2018. PM 10 

### and PM 2.5 

### emissions are expected to increase about 7% and 18%, respectively. NOx and VOC emissions, however, are expected to decrease about 15% and 26%, respectively. SO 2 

### emissions are expected to increase about 5% within the corridor, even with the declining milestones of the backstop emissions trading program. Overall, SO 2 

### emissions are expected to decline by 17% in the 13-state contiguous WRAP region by 2018, 12 

### and the fact that the projections show a 5% increase in SO 2 

### within the clean air corridor is a result of non-road mobile sources using high-sulfur diesel fuel. This source of sulfur dioxide is expected to be drastically reduced (e.g., from a fuel sulfur content of 3,000 ppm to 15 ppm) before 2018 according to announcements by EPA to develop new engine certification and fuel standards for non-road vehicles and equipment. Thus, 5% should be viewed as an upper bound on the possible increase of SO 2


### .

11 EPA. Visibility in Mandatory Federal Class I Areas (1994-1998), A Report to Congress. EPA-452/R-01-008.
12 WRAP Emissions Inventory Forum. 2018-1996 Difference: Actual to Control Spreadsheet. WRAP Web Site. September 25, 2002.

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 7

Since different pollutants have different impacts on visibility, the WRAP estimated a weighted emissions increase according to the VEEU system used by the Commission. As shown in Table 3 , the weighted increase is expected to be 4%, substantially less than the 25% increase thought to be necessary to achieve an impact that may be perceptible. It is also worth noting the safety margins included within this analysis – the fact that the BBC corridor protects 30% of the clean days, not 20%; the benefits of new non-road mobile source standards; and the uncertainty in where additional electricity generating capacity will be located.

Pursuant to 40 CFR 51.309(d)(3)(iii), the WRAP has examined emissions growth in areas outside the corridor and finds that significant emissions growth is not occurring that could begin or is beginning to impair the quality of the air in the corridor and thereby lead to visibility degradation for the least impaired days in one or more of the 16 Class I

areas.

The WRAP sees two purposes for emissions tracking in areas outside the corridor: first, to determine if such emissions are degrading visibility in the corridor, which may potentially affect one or more of the 16 Class I areas; and second, to compensate for any uncertainties in establishing the boundary of the corridor, such as those relating to computed airmass trajectories or introduced by aligning the corridor with county boundaries. Again, SO 2 

### emissions are expected to decline throughout the WRAP region. Emissions of other pollutants are also expected to decline. All visibility-impairing pollutants from on-road mobile sources, with the exception of some minor ammonia emissions, are expected to decline substantially. And all visibility impairing pollutants from non-road mobile sources are expected to decline, especially in areas upwind of the corridor. This decline would be greatly enhanced if the EPA promulgates stricter standards for non-road engines and fuel, as it has announced to do. Also, NOx and PM from existing stationary sources remains to be addressed in future implementation plans by 2008 under Sections 308 and 309 of the regional haze rule. Finally, all states will have to implement measures to achieve reasonable progress in other Class I areas by 2008. Such measures are likely to “overlap” the clean air corridor and areas outside the corridor in such a way that provide further protection to the 16 Class I areas on the 20% cleanest days.

D. I F 

### I MPAIRMENT 

### O F 

### A IR 

### Q UALITY 

### I N 

### T HE 

### C ORRIDOR 

### I S 

### I DENTIFIED 

### – §309(d)(3)(iv)

Since impairment of air quality in clean air corridors has not been identified pursuant to 40 CFR 51.309(d)(3)(ii) and (iii), the WRAP finds no requirement under 40 CFR 51.309(d)(3)(iv) for further visibility impact analysis or additional emission reduction measures until at least the next SIP revision (2008). However, the WRAP encourages its appropriate technical activities – such as the Causes of Haze report – to take into account the assessment and protection of clean air corridors.

The rule specifies that if impairment of air quality in the clean air corridor is identified, the plan must include "an analysis of the effects of increased emissions, including provisions for the identification of the need for additional emission reduction measures, and implementation of the

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 8

additional measures if necessary." For reasons stated above, the WRAP finds no need at this time for additional emission reduction measures.

The periodic WRAP inventories to be produced by the TOC, as instructed above, will identify growth in emissions, and the periodic updates to the WRAP Causes of Haze report will help identify any effect on visibility that may result from such emissions increases. Should any effects be identified, the WRAP will conduct an analysis to determine the sources of impairment within six months of completion of the inventory indicating the increase. Additional control measures that may be warranted would be developed within another six months. The criteria the states and tribes would follow in making this determination are (a) the location of the significant emissions growth, (b) type of source activity causing the emissions growth, and (c) the appropriate control measure for the source(s) based on feasibility, cost, and anticipated visibility benefits. Any necessary additional control measures would be added in the next five-year SIP revision.

E. D O 

### O THER 

### C ORRIDORS 

### E XIST 

### ? – §309(d)(3)(v)

The WRAP finds no other clean air corridors beyond the corridor identified in Figure 1

.
The regional haze rule requires that implementation plans identify whether any other clean air corridors exist for any of the 16 Class I areas. The WRAP finds no such areas other than the corridor to the northwest of the Colorado Plateau identified in Figure 1 . The WRAP recognizes, however, that additional work to identify clean air corridors may be needed. For example, several monitors have recently been installed at Class I areas on the Plateau which were not previously monitored. These may generate a slightly different set of 20% cleanest days and a slightly different set of back trajectories on those days, especially at sites furthest to the north and east. This may result in a broader or separate corridor. Such analysis should be performed when sufficient data are available. Adequate monitoring data could be available by 2004, and analysis of those data could be published by the WRAP as part of its Causes of Haze report.

V. Conclusion

The bottom line is that, while the area to the northwest of the Colorado Plateau delivers clean air to the Plateau on the cleanest days, emissions from throughout much of the region affect the Class I areas on the Plateau. Thus, emissions throughout the WRAP region will be tracked carefully. Ongoing WRAP efforts to improve the quality of inventories and the models used to make projections, and to produce a periodic Causes of Haze report, will bring increased understanding of the role that clean air corridors play in protecting the cleanest days. In the final analysis, the indicator of success or failure will be whether the measured light extinction at the Class I areas on the Colorado Plateau improves or declines on the cleanest days. Any indication of deterioration on the cleanest days should trigger an immediate investigation of the cause, as well as efforts to correct the problem.

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 9

Figure 1. Clean Air Corridor Endorsed by the WRAP.

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 10

Table 1. Counties Within the Clean Air Corridor Endorsed by the WRAP.

State County State County Idaho Ada Oregon Grant Idaho Adams Oregon Harney Idaho Blaine Oregon Jefferson Idaho Boise Oregon Lake Idaho Butte Oregon Malheur Idaho Camas Oregon Morrow Idaho Canyon Oregon Sherman Idaho Cassia Oregon Umatilla Idaho Custer Oregon Union Idaho Elmore Oregon Wallowa Idaho Gem Oregon Wasco Idaho Gooding Oregon Wheeler Idaho Idaho Utah Beaver Idaho Jerome Utah Box Elder Idaho Lemhi Utah Carbon Idaho Lincoln Utah Emery Idaho Minidoka Utah Garfield Idaho Owyhee Utah Grand Idaho Payette Utah Iron Idaho Twin Falls Utah Juab Idaho Valley Utah Kane Idaho Washington Utah Millard Nevada Churchill Utah Piute Nevada Douglas Utah San Juan Nevada Elko Utah Sanpete Nevada Esmeralda Utah Sevier Nevada Eureka Utah Tooele Nevada Humboldt Utah Washington Nevada Lander Utah Wayne Nevada Lincoln Nevada Lyon Nevada Mineral Nevada Nye Nevada Pershing Nevada Storey Nevada Washoe Nevada White Pine Nevada Carson City Oregon Baker Oregon Crook Oregon Deschutes Oregon Gilliam

### WRAP Policy on Clean Air Corridors Submitted for Board Approval, 11/13/02 11

Table 2. Changes in Clean Air Corridor Emissions (Assuming SO 2 

### Milestones Are Met).

Point Area On Road Non Road Paved Unpaved Total SO 2 

### 1996 51,413 9,260 2,065 10,838 0 0 73,576 2018 45,330 10,614 413 21,596 0 0 77,954 2018-1996 -6,082 1,354 -1,652 10,758 0 0 4,378

NOx 1996 85,782 12,935 93,581 64,462 0 0 256,762 2018 109,863 17,576 28,692 62,557 0 0 218,689 2018-1996 24,080 4,641 -64,889 -1,905 0 0 -38,072

PM 10 

### 1996 27,055 142,776 3,872 5,952 5,740 47,733 233,128 2018 32,748 154,966 2,640 6,763 12,402 38,828 248,347 2018-1996 5,692 12,190 -1,232 811 6,662 -8,904 15,219

PM 2.5 

### 1996 11,987 41,595 3,495 5,487 1,435 7,160 71,160 2018 14,583 52,069 2,058 6,228 3,101 5,824 83,863 2018-1996 2,595 10,474 -1,438 740 1,665 -1,336 12,702

VOC 1996 5,993 95,921 69,899 38,535 0 0 210,349 2018 7,921 95,515 22,651 29,233 0 0 155,321 2018-1996 1,927 -406 -47,248 -9,301 0 0 -55,029

Table 3. Total Change in Emissions Weighted to Reflect Relative Impact on Visibility.

SO2 NOx PM10 PM2.5 VOC EC* OC* Total Change 1996 VEEU 5,445 1,746 1,958 932 294 902 856 12,133 -- 2018 VEEU 5,769 1,487 2,086 1,099 217 985 935 12,578 4%

* Estimates of elemental and organic carbon, EC and OC, were not available to the CAC Work Group for the 1996 and 2018 emission inventories. Values for this analysis were derived from the estimates of EC and OC for the 1990 inventory of the 9 GCVTC states. The method used was to take the proportion of EC to fine and coarse particulates (PM2.5 + PM10) in the 1990 inventory and use that same proportion to calculate an EC value for the 1996, 2018, and 2018 milestone inventories. The same method was used for OC.

** VEEU – Visibility Equivalency Emission Units (Used in the GCVTC IAS Model.) VEEU weights PM2.5 PM10 NOx VOC SO2 EC OC 0.0131 0.0084 0.0068 0.0014 0.0740 0.6497 0.2466 Each category in the inventory is multiplied by these factors to create the VEEU-weighted inventory.Appendix A-6 – Clean Air Corridor Arizona Regional Haze SIP 

## Appendix A-6b. WRAP Emission Tracking System and Assessment Process for the Clean Air Corridor

## FINAL

NEEDS ASSESSMENT FOR EVALUATION AND DESIGN OF AN EMISSIONS DATA REPORTING, MANAGEMENT, AND TRACKING SYSTEM

Prepared for

Western Governor’s Association Western Regional Air Partnership 1515 Cleveland Place Suite 200 Denver, Colorado 80202

Prepared by

EA Engineering, Science, and Technology 15 Loveton Circle Sparks, MD 21152

July 25, 2003

## NEEDS ASSESSMENT FOR EVALUATION AND DESIGN OF AN EMISSIONS DATA REPORTING, MANAGEMENT, AND TRACKING SYSTEM

Prepared for

Western Governor’s Association Western Regional Air Partnership 1515 Cleveland Place Suite 200 Denver, Colorado 80202

Prepared by

EA Engineering, Science, and Technology 15 Loveton Circle Sparks, MD 21152

July 25, 2003

EA Project No: 1406601EA Engineering, Science, and Technology FINAL TECHNICAL REPORT



### ii CONTENTS

1.0 INTRODUCTION............................................................................................................... 1 1.1 Regional Haze......................................................................................................... 1 1.2 Consolidated Emission Reporting Rule (CERR).................................................... 1 1.3 RPO Data Excha nge Protocol................................................................................. 2 1.4 Western Air Partnership (WRAP) .......................................................................... 2 1.5 Regulatory Framework for Tribal Visibility Implementation Plans....................... 2 1.6 Objectives ............................................................................................................... 3
2.0 WORKSHOPS AND QUESTIONNAIRE FINDINGS ................................................... 5 2.1 Description of Workshops ...................................................................................... 5 2.2 Description of Questionnaire .................................................................................. 5 2.3 Findings................................................................................................................... 5

3.0 COMPARATIVE ANALYSIS........................................................................................... 9 3.1 Conceptual WRAP EDMS...................................................................................... 9 3.2 Comparison........................................................................................................... 10 3.3 Existing EDMS ..................................................................................................... 10

4.0 RECOMMENDATIONS.................................................................................................. 16

4.1 Flow Chart of the WRAP EDMS.......................................................................... 16 4.2 Point Source Module............................................................................................. 16 4.3 Area Source Module ............................................................................................. 17 4.4 Mobile source Module .......................................................................................... 18 4.5 Biogenic source Module ....................................................................................... 20 4.6 Windblown Dust Source Module.......................................................................... 20 4.7 Fire Source Module............................................................................................... 21 4.8 Standard Reports and Queries............................................................................... 22 4.9 Special Section 309 Tracking ............................................................................... 23 4.10 GIS Module........................................................................................................... 27 4.11 DBA Module......................................................................................................... 28 4.12 QA/QC Module..................................................................................................... 29

5.0 CONCLUSIONS ............................................................................................................... 3 1

6.0 REFERENCES................................................................................................................. . 32

APPENDIX A1: FIRST WORKSHOP PRESENTATION APPENDIX A2: FIRST WORKSHOP DISCUSSION SUMMARY APPENDIX A3: FIRST WORKSHOP PARTICIPANTS APPENDIX B1: SECOND WORKSHOP PRESENTATION APPENDIX B2: SECOND WORKSHOP DISCUSSION SUMMARY APPENDIX B3: SECOND WORKSHOP PARTICIPANTSEA Engineering, Science, and Technology FINAL TECHNICAL REPORT



### iii APPENDIX C: QUESTIONNAIRE RESULTS AND OTHER CORRESPONDENCES APPENDIX D: CONCEPTUAL WRAP AND SELECTED EDMS COMPARISON APPENDIX E: NEI DATA SUBMISSION FORMAT APPENDIX F: NEI QA/QC PROCESS APPENDIX G: WRAP EDMS FLOW CHART APPENDIX H: CAC BONDARIESEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

1 

### 1.0 INTRODUCTION

1.1 Regional Haze

Regional haze is defined as air pollution that is transported long distances and reduces visibility in national parks and wilderness areas . The pollutants that create this haze are sulfates, nitrates, organic carbon, elemental carbon, and soil dust. Hu man-caused haze sources include industry, motor vehicles, agricultural and forestry bur ning, and windblown dust from roads and farming practices.

In 1999, the US Environmental Protection Agency (EPA) issued regulations that address regional haze in one hundred fifty six (156) national parks and wild erness areas across the country. The goal of the Regional Haze Rule (RHR) is to eliminate human-caused visibility impairment in national parks and wilderness areas acr oss the country. It contains strategies to improve visibility over the next sixty (60) years, and requires states to adopt implementation plans.

The RHR provides two paths to address regional haze. One is 40 CFR 51.308 (Section 308), and requires most states to develop long-term strategi es out to the year 2064. These strategies must be shown to make “reasonable progress” in improving visibility in Class I areas inside the state and in neighboring jurisdictions. The other is 40 CFR 51.309 (Section 309), and is an option for nine states - Arizona, California, Colorado, Idaho, Nevada, New Mexi co, Oregon, Utah, and Wyoming - and the two hundred eleven (211) Trib es located within those States to adopt regional haze strategies for the period from 2003 to 2018. These strategies are based on recommendations from the Grand Canyon Visibility Transport Commission (GCVTC), for protecting the sixteen (16) Class I areas in th e Colorado Plateau area (GCTVC, 1996). Adopting these strategies constitutes reasonable progress until 2018. These same strategies can also be used by the nine western states and tribes to protect the other Class I areas within their own jurisdiction.

The RHR specifically requires comprehensive emissions tracking and reporting for clean air corridors (CAC), sulfur dioxide (SO 2 

### ) stationary sources, fire sources, mobile sources, and windblown dust sources among other requirements.

1.2 Consolidated Emissi on Reporting Rule

One of the recent EPA’s rules that will affect the data submission requirements of the RHR is the Consolidated Emission Reporting Rule (CERR) (67 FR 39602-39616) issued in 2002. The CERR will simplify and consolidate emissions inventory reporting requirements to a single location within the CFR and establish new reporting requirements related to particulate matter with aerodynamic size less than 2.5 μm (PM 2.5 

### ), regional haze, and statewide reporting of area and mobile source emissions. In fact, new inventories will add PM 2.5 

### and ammonia (NH 3 

### ). Currently area and mobile sources are repor ted by nonattainment area, and under the CERR, inventories will include all sources statewide by county. Moreover, there will be an option to report smaller point sources once every three y ears or one-third of the sources every year.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

2 

### 1.3 RPO Data Exchange Protocol

The RPO data exchange protocol will also affect the data submission and reporting requirements. The goal of the RPO data exchange protocol is to facilitate the sharing of databases for emissions modeling in a regionally consiste nt and model-indepe ndent nature. Therefore, it seeks to develop data exchange formats a nd naming conventions so that emissions modelers from the five RPOs and states and tribes ha ve common datasets from which to pursue regulatory modeling of ozone (O 3 

### ), regional haze, and PM. It in cludes nine different protocols:

Industrial point source protocol

Area source protocol

Temporal allocation and prof ile assignment protocol

On-road mobile sources protocol

Off-road mobile sources protocol

Continuous emissions monitoring and day-specific protocol

Spatial surroga te protocol

Speciation profile protocol

Growth and control factors protocol

The data sources, data formats, and issues associated with each of these protocols are further detailed in the Midwest RPO’s Draft RPO Data Exchange Protocol (Pechan, 2003).

1.4 Western Regional Air Partnership

The Western Regional Air Partnership (WRAP) is a regional planning organization (RPO) that was established in 1997 as the successor organization of the GCVTC. The WRAP is a collaborative effort of tribal governments, stat e governments, and various federal agencies to implement the recommendations of the GCVTC a nd to develop the technical and policy tools needed by western states and tribes to comply with the RHR. The WRAP Emissions Forum (EF) oversees the development of a comprehensive em issions tracking and forecasting system which can be utilized by the WRAP or its member entities to monitor the trends in actual emissions, and forecast the anticipated emissions which will result from current regulatory requirements and alternative control strategies. In addition, this forum is responsible for the oversight of the assembly and quality assurance of the emissions inventories and forecasts to be utilized by the WRAP forums.

1.5. Regulatory Framework for Tribal Visibility Implementation Plans

The RHR explicitly recognizes the authority of tribes to implement the provisions of the rule, in accordance with principles of federal Indian law, and as provided by the Clean Air Act (CAA) Section 301(d) and the tribal authority rule (TAR) (40 CFR 49.1–11). Those provisions create the following framework:

Absent special circumstances, reservation lands are not s ubject to state jurisdiction.

Federally recognized tribes may apply for a nd receive delegation of federal authority to implement CAA programs, including visibilit y regulation, or "reasonably severable"EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

3 

### elements of such programs (40 CFR 49.3, 49.7). The mechanism for this delegation is a tribal implementation plan (TIP). A reasona bly severable element is one that is not integrally related to program elements that are not included in the plan submittal, and is consistent with applicable statut ory and regulatory requirements.

The RHR expressly provides that tribal visibility programs are “not dependent on the strategies selected by the st ate or states in which the tribe is located” (64 FR 35756), and that the authority to implement Section 309 TI Ps extends to all tribes within the GCVTC region (40 CFR 51.309(d)(12)).

The EPA has indicated that under the TAR, tr ibes are not required to submit Section 309 TIPs by the end of 2003. Rather, they may choose to opt-in to Section 309 programs at a later date (67 FR 30439).

Where a tribe does not seek delegation through a TIP, EPA, as necessary and appropriate, will promulgate a federal implementation plan (FIP) within reasonable timeframes to protect air quality in Indian country ( 40 CFR 49.11). EPA is committed to consulting with tribes on a government-to-government basi s in developing tribe- specific or generally applicable TIPs where necessary (63 FR 7263-64).

The amount of modification, if an y, needed for this report to fulfill tribal needs may vary considerably from tribe to tribe. The authors have striven to ensure that all references to tribes in the document are consistent with principles of tr ibal 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.

Tribes, along with states and federal agencies , are full partners in the WRAP, having equal representation on the WRAP Board as states. Whether Board members or not, it must be remembered that all tribes are governments, as distinguished from the “stakeholders” (private interest) which participate on Forums and Committees but are not eligible for the Board. Despite this equality of representation on the Board, tribes ar e very differently situated than states. There are over four hundred (400) federally recognized tr ibes in the WRAP region, including Alaska. The sheer number of tribes makes full participati on 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, how ever important its goals may be. These factors necessarily limit the level of tribal input into and endorsement of WRAP products.

The tribal participants in the WRAP, including Board members, Forum and Committee members, and co-chairs, make th eir best effort to ensure that WRAP products are in the best interest of the tribes, the environment, and the public. One interest is to ensure that WRAP policies, as implemented by states and tribes, will not constrain the future options of tribes who are not involved in the WRAP. With these considerations and limita tions in mind, it is anticipated that the tribal participants will join th e state, federal, and private stakeholder interests in approving this report as a consensus document.

1.6 Objectives

The EF is currently seeking to implement a comprehensive internet web-based air pollution emissions data reporting, management, and tracking system to support state and tribal regionalEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

4 

### haze implementation plan (SIP/TIP) development. The system is to be capable of receiving and storing emissions data in EPA-compliant emissi ons reporting formats commonly used by various agencies and sources with little or no additi onal effort, producing user-specified reports, performing user-selected quality c ontrol and assurance tests, allo wing data queries and graphic display, and presenting this information in geographic information system (GIS) format.

The EF contracted with EA Engineering, Scienc e, and Technology, Inc (EA) to assess the needs of the WRAP emissions database management system (WRAP EDMS). The overall approach of this needs assessment consists of the following tasks.

Task 1: Determine the emissions data to be reported, managed and tracked.

Task 2: Conduct a comparative analysis of existing emissions data management systems approved and in use by EPA and state air quality agencies.

Task 3: Prepare a report addressing issues associated with developing a new system, long-term system maintenance and operati on of the recommended data management system, by integrating information gathered in Tasks 1 and 2.

This report presents the results of Task 3 and repr esents the final technical report of the project. It provides the documentation from the two work shops and questionnaires, the findings based on the input received from the two workshops and qu estionnaires, an evaluation of existing EDMS, and the system recommendations.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

5 

### 2.0 WORKSHOP AND QUESTIONNAIRE FINDINGS

2.1 Description of the Workshops

The WRAP EDMS needs assessment survey consis ted of two interview workshops. The first workshop took place in Santa Fe, New Mexico, on March 20 th 

### , 2003. It was intended for members of the WRAP Forums. Thirty-five ( 35) people attended the meeting. The workshop lasted approximately three hours, and included a presentation by the EA team covering the project overview and timeline, the goals and roles of the WRAP EDMS, a comparative summary of existing systems, a straw man presentati on of the conceptual WRAP EDMS, and the conceptual timeline of the development and popul ation of the WRAP EDMS. The presentation was followed by specific discussions on the WRAP EDMS needs. Appendices A1, A2, and A3 present the EA presentation, a summary of the discussion points, and the list of the workshop participants respectively.

The second workshop took place in Denver, Colorado, on May 7 th 

### , 2003 and was planned in order to provide an opportunity for state, tribe, and local (STL) air po llution control agencies staff and other stakeholders to participate in th e project. Prospective attendees were notified by email several weeks prior to the meeting, and vi a an online questionnaire. Thirteen (13) people attended this day long workshop. The session in cluded a presentation by the EA team that covered the project overview and timeline, the goals and roles of the WRAP EDMS, a summary of the RHR and CERR, a comparative summary of existing systems, a straw man presentation of the conceptual WRAP EDMS, the conceptual time line of the development and population of the WRAP EDMS, and the summary of the Santa Fe workshop. This was followed by an oral presentation of the special needs of the Fi re Emission Joint Forum (FEJF) and specific discussions on the WRAP EDMS needs were br ought up during and after the presentations. Appendices B1, B2, and B3 present the EA pres entation, a summary of the discussion points, and the list of the workshop participants respectively.

2.2 Description of Questionnaire

As mentioned above, in addition to the inte rview workshop, a web-based questionnaire was posted on http://wrap.eaest.com for a period of th ree months. All potential users of the WRAP EDMS, stakeholders, and intere sted parties were invited to fill it out. The questionnaire comprised thirty-four (34) questions designed to collect ideas on all the possible needs of the WRAP EDMS. Overall, twenty (20) peoples responded to the web-based questionnaire. Appendix C shows the results of this questionnaire. Furthermor e, one person responded to this questionnaire via email before it was posted on the internet. Appendix C also shows these
responses.

2.3 Findings

The workshop interviews and questionnaire results underscored the emerging project consensus that the WRAP EDMS needs to be different from any of the other existing systems (including the national emissions inventory (NEI)) because of its architecture, technical capabilities, and contents. The system needs to be developed with all possible users in mind, and with the intentEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

6 

### to accommodate several distinct user groups. Th e WRAP EDMS will not only be a repository of the WRAP regional emissions invent ories but will also be able to be used to implement the emissions tracking and reporting re quirements of the RHR. The WRAP EDMS would be located either at the WRAP regional modeling center (RMC) or at a universit y center as is the monitoring database. Moreover, it will be made publicly accessibl e through the internet and will contain online training manuals.

The WRAP EDMS will track all the visibility-imp airing pollutants: volatile organic compounds (VOC), nitrogen oxides (NOx), SO 2 

### , PM 10 

### , PM 2.5 

### , elemental carbon (EC), organic carbon (OC), carbon monoxide (CO), and NH 3 

### and all the necessary activity data for all the sources and emission factors needed to calculate their emissions.

A metadata describing and characterizing all of the emissions data will be developed. Furthermore, The WRAP EDMS will be linked to other related external databases. These databases will contain related surrogate and activity data used to estimate some of the emissions such as mobile, biogenic, and windblown dust s ources emissions as well as speciation profiles for VOC and PM data. The WRAP EDMS will also adopt the RPO data exchange protocol in order to capture all the necessary external data.

The emissions data will primarily be submitted by STL agencies. Emissions from mobile, biogenic, and windblown dust sources may be es timated through modeling using activity data submitted by STL agencies and other surrogate data. The estimated emissions will be sent to STL agencies for review and approval before in clusion in the final database. Fire source emissions data that are not generated by STL agencies will be estimated by the WRAP EDMS based on fire activity data submitted by STL agencies, federal agencies, private entities, or generated by WRAP. Some STL agencies may estimate fire emissions themselves. These emissions would be submitted by the STL agencies along with all the activity and surrogate data used for the estimation. WRAP will obtain and process the international (Canada and Mexico) data.

The large majority of participants in both workshops felt that the WRAP EDMS should be developed and populated in two phase s. In Phase I, the system will include the core database architecture, including all of the functioning modules and all of th e reporting and queries capabilities (see Section 4). It will be used primarily to store emissions data that will be used to implement the tracking and repor ting requirements of both Sections 308 and 309. The focus will be on the implementation of the emissions trackin g and reporting requirements of the CAC, fire sources, stationary SO 2 

### sources, and mobile sources. The minimum spatial resolutions of the emissions data will be the count y and reservation levels. The submittal temporal resolution of the activity data would be variable (i.e. hourly , daily, seasonal, and annual) depending on the source category. However, the emissions will be reported and tracked on an annual resolution basis.

In Phase II, the system could be expanded to in corporate new and updated technical functionality that would allow for storage, tracking, and re porting of hourly, daily, seasonal, and annual emissions data as necessary. The system woul d include others pollutants (e.g. methane (CH 4 

### ), mercury (Hg), etc) and their emi ssions data. It may be used to track other RHR requirementsEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

7 

### (e.g. annual emission goals) and other regulations (e.g. Clear Skies, Greenhouse Gas, etc) requirements.

There was general agreement that the WRAP ED MS will be built and test ed by the end of 2003 and will be live on the web in early 2004. This first version of the WRAP EDMS will be populated with the 2002 comprehensive emissions data. The collection, processing, and quality assurance/quality control (QA/QC) of these data from the STL agencies will start in early 2004 and will continue throughout 2004. At the same time, the 2002 base and 2018 projection years’ emissions files that will be used by RMC will be produced. The system will also produce the emission reports as needed fo r both Sections 308 and 309. From 2005 to 2007, annual emissions will be generated from the 2002 comprehensive emissi ons data in order to satisfy the tracking and reporting requirements of the RHR. At the same time, refined emissions inventories representing the effect of control strate gies in 2018 will be developed, and the 2005 comprehensive emissions data will be collected from STL agencies, processed, and QA/QC’d. It should be noted that the emissions data submitte d by tribal agencies may be from any given inventory year. Moreover, wherever tribal emissi ons data are available, the state should adjust its inventory taking into account these tribal da ta. The conceptual development timeline of the WRAP EDMS is as follow.

Mid 2003: finish needs assessment project

Late 2003: 1. WRAP contractor builds and alpha tests Phase I of WRAP EDMS 2. Beta test of the WRAP EDMS

Early 2004: 1. Initiate live Phase I of the WRAP EDMS on the web 2. Provide training and user support

Throughout 2004: begin collection, processi ng, and QA/QC of 2002 emissions from STL agencies

Late 2004: 1. Implement Phase II of the WRAP EDMS 2. Provide training and user support 3. Produce emissions reports as needed for Section 308 and 309 requirements 4. Prepare 2002 base and 2018 projection y ears' emissions files for use by RMC

2005-2007: ongoing operation of the WRAP EDMS 1. Track emissions as needed for Section 308 and 309 2. Develop refined emissions inve ntories representing the effect of control strategies in 2018 3. Provide training and user support 4. Populate the WRAP EDMS with annual emi ssions data to meet Section 308 and 309 regulatory requirements 5. Collection, processing, and QA/QC of 2005 emissions from STL agencies

There was also consensus that the WRAP EDMS should be built in a modular fashion, to allow for easy expansion and improvement. It will incl ude six major modules representing the sources (point, area, fire, mobile, windblown dust, and bi ogenic) in addition to the GIS, QA/QC, and database administrator (DBA) modules. The sub mission formats will be similar to that of theEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

8 

### NEI format (NIF) and the minimum submission cycle would coincide with the submission cycle of the NEI (annual and triennial cycles). Ho wever, the WRAP EDMS will have an open submittal process, where STL agencies’ emissions data will be submitted at different times. Currently, state submit the NIF in several file formats including ASCII Text (Text), Microsoft Access database (MS Access), a nd eXtended Markup Language (XML). The results of the questionnaire indicated that, across the WRAP re gion, states are using Text, MS Access, inhouse developed systems, and other systems (i.e. AMS Tempo) that need to be converted to the NIF. Therefore, the WRAP EDMS will accept al l the file formats already accepted by NEI.

The WRAP EDMS will be managed by a DBA whose functions could include QA/QC, some emission calculations, data gap filling, data archiving, and data version management among others.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

9 

### 3.0 COMPARATIVE ANALYSIS

3.1 Conceptual WRAP EDMS

The conceptual WRAP EDMS was developed base d on the findings of the interview workshops and the web-based questionnaire.

3.1.1 Data Tracking

The WRAP EDMS should contain all vi sibility-impairing pollutants: VOC, NO x 

### , SO 2 

### , PM 10 

### , PM 2.5 

### , EC, OC, CO, and NH 3 

### . The WRAP EDMS should also tr ack all necessary activity data for all the sources and emission factors needed to calculate emissions. These pollutants and related activity data should be tracked for the following sources: point, area, mobile, biogenic, windblown dust, and fire sources. The data will be tracked at the county and reservation level for all sources and also individually for point and fire sources. The emissions data will be submitted to the WRAP EDMS by STL agencies , except for biogenic, mobile, windblown dust, and certain fire sources emissions data that will be calculated by WRAP using emissions estimation models. The submissions will be in a standard format similar to the NIF and done at the NEI minimum cycle but STL agencies may submit emissions data frequently.

3.1.2 Data QA/QC

The WRAP EDMS should include a QA/QC module to perform two levels of QA/QC. The first level of QA/QC should include a va lidation of the format of the s ubmitted data file s. This will ensure that the submitting entity supply all data to WRAP in the expected format and also identify any errors. The submittal check will be at the point of entry to the WRAP EDMS in order to minimize the DBA work and encourage ST L agencies to submit clean data. The second level of QA/QC should consist of checks of the data that is submitted to WRAP, and include checking reference values and acceptable data rang es for specific data points. The data should also be checked for completeness, ensuring that all data exists for all sources and geographic

areas.

3.1.3 Data Reporting

The WRAP EDMS should include a series of st andard summary reports broken down by source type, geographic location, and pollu tant. It should also include a series of reports designed specifically to meet the RHR emissions trackin g and reporting requirement s. The RHR reports will include special reports for CAC, pre-trigger SO 2 

### stationary sources, mobile sources, fire sources, and windblown dust sources. The WRAP ED MS should also include a series of data export formats for inclusion in external systems including emissions modeling programs such as SMOKE (MCNC, 1999).

3.1.4 GIS Components

The WRAP EDMS should include a fully functioning GIS module that provides multiple tools to display data over the internet. The inclusion of a GIS module will provide a means for users toEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

10 

### select data that is of importance to them a nd display the data in a fashion that is easily understood. The WRAP EDMS should include th e following GIS functionality: pan, zoom, query layer information, ability to add/remove mu ltiple layers of data, point and click, measure distances, buffer, print multiple sizes of maps, and select map features by line, rectangle, or polygon.

The WRAP EDMS GIS module shoul d include the following layers of data: county, state and country polygons, tribal reservation polygons , roadways and railroad line features, CAC polygons, international polygons, metropolitan statistical areas polygons, nonattainment area polygons, class I areas polygons, bodies of water polygons, census data polygons, other federal land polygons (i.e. national parks, monuments , forest, and refuges), and WRAP modeling domain grid system. It should have the ability to select and display emissions sources and associated emissions data by geographical area.

3.1.5 User Access and Preferences

All reporting features of the WRAP EDMS should be available to the public via the internet. STL agencies will have a separa te, non-public interface for sub mitting their data to a central submission area. The user interface for the WR AP EDMS should be easy and intuitive to use while providing all ne cessary functionality.

3.2 Comparison

Five existing EDMS were evaluated and compared each to the conceptual WRAP EDMS. Each system was evaluated in terms of meeting the design and functionality requirements of the conceptual WRAP EDMS. As expected, none of the individual systems included all of the required elements for the conceptual WRAP EDMS. This was due in part to the fact that none of the systems tracked all of the required pollutants or included e missions data from all of the required, individual sources. In some instances, individual systems included most or all of the required functionality, such as a GIS module or the ability to export data, but did not track emissions data for all of the re quired pollutants or sources. W ithout all of the required data available, the output of these systems will be incomplete. Appendix D illustrates the overall comparison between the conceptual WRAP EDMS and the selected existing systems and Section 3.3 below describes these systems further.

3.3 Existing EDMS

This section lists each of the selected five existing database management systems, provides a brief description and background information for each, and highlights any elements from each system that could be utilized by the WRAP EDMS.

3.3.1 National Emissions Inventory – NEI

The EPA’s Emission Factor and Inventory Gr oup (EFIG) maintains a national emissions inventory containing information on air emissions and their sources for each state in the U.S., the U.S. Virgin Islands, Puerto Rico and the Distri ct of Columbia. The NEI has a public websiteEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

11 

### (http://www.epa.gov/air/data/index.html) where us ers can query the emissions database and produce reports based on their specific needs.

3.3.1.1 System Details

The NEI tracks seven pollutants: VOC, NO x 

### , SO 2 

### , PM 10 

### , PM 2.5 

### , CO, and NH 3 

### . The pollutants are tracked for four source types: point, area, mobi le, and biogenic sources. All data is tracked at the county level for all sources, and also individua lly for point sources. The data is submitted on an annual and triennial basis to EPA by state and tribal agencies. The data is submitted in the EPA’s standard submission format, the NIF.

The NEI includes a QA/QC process that performs multiple levels of QA/QC checks. The first level consists of a validation of the format of the submitted data files, which ensures that the submitting entity supplied all data to NEI, in the expected format, and also identifies any errors with the submitted format. The second level of QA /QC checks includes checks of the data that is submitted to NEI. Reference values are checked against standard lists and data points are checked against acceptable data ranges. The data is also checked for completeness, ensuring that all data exists for all sources and geographic areas. If data points are missing, the NEI will replace the missing values with national averages or previous year data for the particular data point.

The NEI includes a series of standard summa ry reports broken down by source category, geographic location, and pollutant. The NEI also in cludes a data export feat ure to allow data to be extracted from the NEI database for inclusion in external systems.

The NEI includes a basic mapping capability to display emissions data over the internet. The NEI mapping functionality includes the ability to pan, zoom, and displays county, state and country boundaries.

All reporting features of the NEI are available to the public via the internet. The NEI user interface is easy to use and navi gate to reach the desired data.

3.3.1.2 Key System Elements

The NEI has three key elements that should be utilized in the WRAP EDMS. First, the NEI requires a standard submission format (NIF) for all data submitted to the system. The WRAP EDMS could utilize this same submission format fo r all data sources, except for fire sources. The submission format captures th e required emissions and activity data for all pollutants except OC and EC, which can be calculated by the WRAP system, based on the PM 2.5 

### data. Also, since STL agencies are already required to submit their data in the NIF format, no additional work will be necessary on their part to create submissions for the WRAP EDMS. See Appendix E for the recent version of the NIF submission formats.

Second, the NEI has a well-established and defi ned QA/QC process for all submitted emissions data. This process does a thorough analysis of the submission format and data content to identify all possible issues before the data is included in the system. The WR AP EDMS could adopt aEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

12 

### modified version of this QA/QC Process to ensure that all data submitted to the WRAP EDMS is accurate. However, instead of automatically replacing missing or erroneous data with a default set of data, WRAP coul d make recommendations for replacin g missing data or supplementing existing data to STL agencies while leaving the final approval for all data included in the WRAP EDMS with them. See Appendix F for a deta iled explanation of the NEI QA/QC process.

Finally, the NEI includes an adequate set of standard reports for users to utilize when accessing the NEI database. The set of reports is not ex haustive, but does provide an excellent basis for data reporting and gathering to serve the public’s data needs. The NEI report interface is also very easy to use and intuitive, making the data gathering process easy for the user. The WRAP EDMS could adopt this report functionality and design for th e general data gathering and reporting capabilities of its system.

3.3.2 Tribal Emissions Inventory Software Solution – TEISS

Northern Arizona University is currently devel oping an air emissions inventory for all western region tribes. The Tribal Emissions Inventory Software Solution (TEISS) will be a desktop application where users can query the emissions database and produce reports based on their specific needs.

3.3.2.1 System Details

The TEISS tracks seven pollutants: VOC, NO x 

### , SO 2 

### , PM 10 

### , PM 2.5 

### , CO, and NH 3 

### . The pollutants are tracked for three source types: point, area, a nd mobile sources. All data is tracked at the reservation level for all sources, and also individually for point s ources. The data is collected from the tribes on a continuing basis. The data is submitted in multiple formats and can also be hand-entered through data entry screens.

The TEISS includes a series of standard repor ts broken down by source category, geographic location, and pollutant. The TEISS also includes a data export feature to allow data to be extracted from the TEISS database for inclusion in external systems, including the NEI and modeling programs such as SMOKE.

The TEISS includes a fully functioning GIS module that provides multiple tools to display data geographically. The TEISS incl udes several advanced GIS featur es including: pan, zoom, query layer information, ability to add/re move multiple layers of data, measure distances, buffer, print multiple sizes of maps, and select map features by line, rectangle, or polygon. The TEISS GIS module includes several static laye rs of data, such as county, state and country, and tribal reservation boundaries, and the ability to select and display emissions sources and associated emissions levels by geographical area.

The TEISS utilizes an advanced user interface, since it is a desktop application and not accessible via the internet.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

13 

### 3.3.2.2 Key System Elements

The TEISS has two key elements that should be utilized in the WRAP EDMS. First, the TEISS has a fully functioning GIS module embedded in th e system. This allows TEISS users to display map features in conjunction with relevant emissions and activity data on a real-time basis. The TEISS GIS module includes a full set of tools for manipulation of any map created in the system. The WRAP EDMS could include a majority of this functionality in its GIS module to provide its users a complete internet GIS capability. However, since current web GIS capabilities are limited compared to desktop capabilities, the WRAP EDMS will not be able to implement all of the features of the TEISS GIS module.

Second, the TEISS has a flexible set of exportin g functions to allow fo r multiple data export formats. The WRAP EDMS c ould include a comparable set of exporting features to accommodate the need of multiple fo rmats for the system’s users.

3.3.3 California Air Resources Board Emissions Inventory – CARBEI

The California Air Resources Board maintains an emissions inventory (CARBEI) containing information on air emissions and their sources fo r the state of California. The CARBEI has a public website (http://www.arb.ca.gov/emisinv/ei b.htm) where users can query the emissions database and produce reports ba sed on their specific needs.

3.3.3.1 System Details

The CARBEI tracks five pollutants: NO x 

### , SO 2 

### , PM 10 

### , PM 2.5 

### , and CO. The pollutants are tracked for three sources types: point, area, and mobile so urces. All data is trac ked at the county level for all sources, and also individually for point sources. The data is submitted by local agencies in the California Air Resources Board’s standa rd submission format, the California Emission Inventory Development and Reporting System (CEIDARS).

The CARBEI includes a QA/QC process that performs multiple levels of QA/QC checks. The first level consists of a validation of the format of the submitted data files, which ensures that the submitting entity supplied all data to CARBEI, in the expected format, and also identifies any errors with the submitted format. The second leve l of QA/QC checks includes checks of the data that is submitted to CARBEI. Data points are checked against acceptable data ranges to ensure the submitted data are accurate and reasonable.

The CARBEI includes standard summary repor ts broken down by source category, geographic location, and pollutant. The CARBEI also include s a data export feature to allow data to be extracted from the CARBEI database for inclusion in external systems.

All reporting features of the CARBEI are available to the public via the internet. The CARBEI user interface is easy to use and navigate for the user to reach the desired data.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

14 

### 3.3.3.2 Key System Elements

The CARBEI has one key element that should be utilized in the WRAP EDMS. The CARBEI report interface is very easy to use and intuitive, making the data gathering process easy for the user. The WRAP EDMS could adopt this report functionality and design for the general data gathering capabilities of its system.

3.3.4 Colorado Department of Health Air Pollution Inventory – CAPI

The Colorado Department of Health maintains an Air Pollution Inventory (CAPI) containing information on air emissions and their sources fo r the state of Colorado. The CAPI has a public website (http://emaps.dphe.s tate.co.us/APInv/viewer.htm) where users can query the emissions database and produce report s based on their specific needs. It should be noted that CAPI is not the Colorado primary emissions inventory system. It is included in this analysis because of its internet capabilities.

3.3.4.1 System Details

The CAPI tracks five pollutants: VOC, NO x 

### , SO 2 

### , PM 10 

### , and CO. The pollutants are tracked for three source types: point, area, and mobile sources. All data is tracked at the county level for all sources, and also individually for point sources. The data is submitted by local agencies on a continuing basis.

The CAPI includes standard summary reports broken down by source category, geographic location, and pollutant.

The CAPI includes a fully functioning GIS modul e that provides multiple tools to visually display data. The CAPI include s several advanced GIS featur es including: pan, zoom, query layer information, ability to add/re move multiple layers of data, measure distances, buffer, print, and select map features by line, rectangle, or polygon. The CAPI GIS module includes several static layers of data, such as county and stat e boundaries, and various a ttainment area boundaries.

All reporting features of the CAPI are available to the public via the internet. The CAPI user interface is easy to use and navigate for the user to reach the desired data.

3.3.4.2 Key System Elements

The CAPI includes a functioning, internet-based GIS module. The CAPI GIS module includes a full set of tools for manipulation of any map creat ed in the system. Although the CAPI does not have the capability of mapping data from th e emissions database, it does represent a good example of internet-based GIS functionality. The WRAP EDMS could in clude this functionality in its GIS module to provide its users internet-based GIS capability.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

15 

### 3.3.5 Delaware Environmental Navigator – DEN

The Delaware Department of Natural Resources and Environmental Control maintains a database of information for all aspects of environmental monitori ng and control. The Delaware Environmental Navigator (DEN) has a public website (http://www.dnrec.state.de.us/dnreceis/) where users can query the database and produ ce reports based on their specific needs.

3.3.5.1 System Details

At the air emissions level, the DE N tracks five pollutants: VOC, NO x 

### , SO 2 

### , PM 10 

### , and CO. The pollutants are tracked for three source types: point, area, and mobile sources. All data is tracked at the county level for all sources, and also indi vidually for point sources. The data is submitted by local agencies on a continuing basis.

The DEN includes a limited QA/QC process that performs quality checks of all submitted data.

The DEN includes standard summary reports broken down by source category, geographic location, and pollutant.

The DEN includes a fully functioning GIS module that provides multiple tools to display data geographically. The DEN includes several adva nced GIS features including: pan, zoom, query layer information, ability to add/remove multiple layers of data, measure distances, print, and select map features by line, rectangle or pol ygon. The DEN GIS module includes several static layers of data, such as county, state and country boundaries, interstate and highway line features, and the ability to select and display data by geographical area.

All reporting features of the DEN are available to the public via the internet. The DEN user interface is easy to use and navi gate to reach the desired data.

3.3.5.2 Key System Elements

The DEN has a fully functioning, internet-based GIS module included in the system. This allows DEN users to display map features in c onjunction with relevant emissions and activity data on a real-time basis. The DEN GIS module includes a full set of tools for manipulation of any map created in the system. The DEN was incl uded in this comparison due to its advanced internet-based GIS functionality and its ability to map user defined data queried from the DEN database on a real time basis. The WRAP EDMS could include this functionality in its GIS module to provide its users internet-based GIS capability.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

16 

### 4.0 RECOMMENDATIONS

4.1 Flow Chart of the WRAP EDMS

Appendix G presents the flow chart of the WRAP EDMS that shows the information needs, from the emissions data submission to the report generations, data que ries, graphic display, and GIS presentation. The sections below explain th e different parts of this flow chart.

4.2 Point Source Module

For point sources, at a minimum, the emissions data listed below shoul d be submitted, stored, and tracked for each inventory. The data file s hould be organized into records for the submitting format. In the NIF Version 3, the point source file contains eight records with specific key fields represented by these emissions data (see Appendix E).

1) Inventory year 2) Inventory start date 3) Inventory end date 4) Inventory type 5) Country code 6) State and county FIPS code 7) Tribal code 8) Facility ID code 9) Point ID code 10) Process ID code 11) Stack ID code 12) Site name 13) Physical address 14) SCC code 15) Heat content (fuel) (annual average) 16) Ash content (fuel) (annual average) 17) Sulfur content (fuel) (annual average) 18) Pollutant code 19) Activity/throughput (annual) 20) Activity/throughput (daily) 21) Work weekday emissions 22) Annual emissions 23) Emission factor 24) Winter throughput (%) 25) Spring throughput (%) 26) Summer throughput (%) 27) Fall throughput (%) 28) Hours/day in operation 29) Start time (hour) 30) Day/week in operation 31) Weeks/year in operationEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

17 

### 32) X stack coordinate (latitude) 33) Y stack coordinate (longitude) 34) Stack height 35) Stack diameter 36) Exit gas temperature 37) Exit gas velocity 38) Exit gas flow rate 39) SIC code 40) Design capacity 41) Maximum nameplate capacity 42) Primary control efficiency (%) 43) Secondary control efficiency (%) 44) Control device type 45) Rule effectiveness (%)

Emissions from point sources will be estimated by STL agencies using emission factors published in AP-42 (EPA, 1998) or from stack test data and submitted at the individual source level on an annual temporal re solution basis. According to the CERR, the minimum point source reporting thresholds are 100 tons per year (tpy) for VOC, NOx, SO 2 

### , PM 10 

### , PM 2.5 

### , and NH 3 

### and 1000 tpy for CO. Many states have differen t reporting thresholds tied to other state environmental regulations and would like to be able to retrieve data from the EDMS as they are submitted. Therefore, the WRAP EDMS will allow different point source cutoff level submissions and will check for these discrepanc ies in order to avoid double counting emissions.

4.3 Area Source Module

Based on input and discussion, it appears that area sources represent all ot her stationary sources not included in the point source category, excl uding fire and windblown dust sources. These sources also include open burning activities on resi dential, commercial, an d industrial properties.

For area sources, at a minimum, the emissions da ta listed below should be submitted, stored, and tracked for each inventory. Similar to the point sources, the data file should be organized into records. The area source file contains five records in the NIF version 3 (see Appendix E).

1) Inventory year 2) Inventory start date 3) Inventory end date, 4) Inventory type 5) Country code 6) State and county FIPS code 7) Tribal code 8) SCC code 9) Emission factor 10) Activity/throug hput level (annual) 11) Total capture/control efficiency (%) 12) Rule effectiveness (%)EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

18 

### 13) Rule penetration (%) 14) Pollutant code 15) Summer/winter work weekday emissions 16) Annual emissions 17) Winter throughput (%) 18) Spring throughput (%) 19) Summer throughput (%) 20) Fall throughput (%) 21) Hours/day in operation 22) Days/week in operation 23) Weeks/year in operation

Emissions from area sources will be estimated by STL agencies using mostly emission factors published in AP-42 (EPA, 1998) and submitted at the county le vel on an annual temporal resolution basis. The area source definitions are different from STL to STL. For example, some STL define gas stations or dry cleaners as point sources while others do as area sources. Therefore, the WRAP EDMS will allow different source category submissions and will check for these discrepancies in order to avoid double counting emissions.

4.4 Mobile Source Module

Mobile sources are divided into two main cat egories: onroad and nonroad mobile sources. Onroad mobile sources are motor vehicles lic ensed for use on highways or roadways (i.e. automobiles, trucks, etc). Onroad mobile sour ce emissions are the product of emission factors obtained through the execution of the latest EPA’s MOBILE model (EPA, 2002) or the California EMFAC model (CARB, 2002) and activity levels repr esented by the vehicle mile traveled (VMT). Dust from paved and unpave d roads may be estimated by using either the method in AP-42, Section 11 (EPA, 1998) or the EPA’s PART5 model (EPA, 1995).

Nonroad mobile sources are the other mobile s ources represented for instance by construction equipment, lawn and garden equipment, snowm obiles, boats, trains, and airplanes. Their emissions can be estimated using the EPA’s NONROAD model (EPA, 2000) and/or published emission factors, especially for boats and trains . Emissions of airplanes and associated ground support equipment and auxiliary power units are estimated using the Federal Aviation Administration (FAA) Emission and dispersion Mode ling System model (FAA, 2002). It is not anticipated that the WRAP EDMS will contain these models.

Most mobile emissions will be submitted at the county level on an annual temporal resolution basis. However, many mobile source emissions data are seasonal in nature. Therefore, the WRAP EDMS may store applicable seasonal mob ile emissions data as well. For unsubmitted and/or missing mobile source emissions data for a given area, the WRAP EDMS DBA will estimate the inventories using available mobile emissions models and area-specific data or national average data. These inventories will be submitted to STL agencies for review and approval before inclusion in the final database.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

19 

### For mobile sources, the emissions data listed below should be submitted, stored, and tracked for each inventory. Similar to the point sources, the da ta file should be organized into records. The onroad and nonroad mobile source f iles contain three and five r ecords respectively in the NIF version 3 (see Appendix E).

For on-road mobile sources,

1) Inventory year 2) Inventory start date 3) Inventory end date 4) Inventory type 5) Country code 6) State and county FIPS code 7) Tribal code 8) SCC code 9) Emission factor 10) Activity (VMT by roadway class) 11) Pollutant code 12) Summer/winter work weekday emissions 13) Annual emission 14) Refueling emissi ons classification

For non-road mobile sources,

1) Inventory year 2) Inventory start date 3) Inventory end date 4) Inventory type 5) Country code 6) State and county FIPS code 7) Tribal code 8) SCC code 9) Emission factor 10) Activity/throug hput level (annual) 11) Total capture/control efficiency (%) 12) Rule effectiveness (%) 13) Rule penetration (%) 14) Pollutant code 15) Summer/winter work weekday emissions 16) Annual emissions 17) Winter throughput (%) 18) Spring throughput (%) 19) Summer throughput (%) 20) Fall throughput (%) 21) Hours/day in operation 22) Days/week in operationEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

20 

### 23) Weeks/year in operation

4.5 Biogenic Source Module

The latest EPA’s Biogenic Emissions Inventory System (BEIS) model (EPA, 1998) will be used to generate the region-wide biogenic emissions using activity data submitted by STL agencies and other surrogate land use and meteorological data. The emission inventories will then be submitted to STL agencies for review and approval before inclusion in the final database. The reporting spatial resoluti on will be the county level and the te mporal resolution will be annual for the biogenic emissions data in Phase I. In phase II, hourly, daily, or seasonal temporal resolutions may be tracked. The biogenic emi ssions are currently being generated at RMC on a 36-km grid system for each hour. Therefore, they will need to be converted to a county level and aggregate on an annual temporal resolution basis before being sent to STL agencies for review and subsequent inclusion in the WRAP EDMS.

For biogenic sources, at a minimum, the emission s data listed below shoul d be submitted, stored, and tracked for each inventory. Similar to the poi nt sources, the data file should be organized into records. The biogenic source file contai ns two records in the NIF version 3 (see Appendix E).

1) Inventory year 2) Inventory start date 3) Inventory end date 4) Inventory type 5) Country code 6) State and county FIPS code 7) Tribal code 8) SCC code 9) Pollutant code 10) Summer/winter work weekday emissions 11) Annual emissions

4.6 Windblown Dust Source Module

Windblown dust emissions will be generated re gion-wide through modeling. The emission inventories will then be submitted to STL agencies for review and approval before inclusion in the final database. The spatia l resolution will be the county le vel and the temporal resolution will be annual for the windblown dust source data in Phase I. In phase II, hourly, daily, or seasonal temporal resolutions may be tracked. The dust emissions (PM 10 

### and PM 2.5 

### ) are currently being estimated using wind data as emissions per grid square. Therefore they will need to be converted to a county leve l before being sent to STL agencies for review and subsequent inclusion in the WRAP EDMS.

For windblown dust sources, at a minimum, the e missions data listed be low should be submitted, stored, and tracked for each inventory. Windblow n dust source is not included in the NEI as aEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

21 

### separate source category. Therefore, the data f ile needs to be created and the records defined. A definition based on the NIF biogenic source file should suffice.

1) Inventory year 2) Inventory start date 3) Inventory end date 4) Inventory type 5) Country code 6) State and county FIPS code 7) Tribal code 8) SCC code 9) Pollutant code 10) Summer/winter work weekday emissions 11) Annual emissions 12) Natural or anthr opogenic classification

4.7 Fire Source Module

There are four types of fire emissions sources - wildfire, prescribed fire, wildland fire use, and agricultural burning - that will be included in the fire source module of the WRAP EDMS. It should be noted that wildfire, pr escribed fire, wildland fire use include rangeland. Fire sources such as open burning activities on residential, commercial, a nd industrial prope rties will be included in the area source module. The WRAP Fire Tracking System (FTS) (WRAP, 2001) identified seven essential data (9 – 17) that will provide the basis for calculating the emissions for fire through the use of an emissions calculation mechanism, such as the WRAP emissions inventory system, to integrate the appropria te emissions factors and emission calculation techniques. The FTS also identified optional da ta (18 – 21) that are equally important in calculating fire emissions. Note that for fire sources, the WRAP EDMS will calculate the emissions. However, some STL agencies may estimate fire emissions themselves. These emissions will be submitted by the STL agencies with all the activity and surrogate data used for the estimation.

For fire sources, at a minimum, the emissions data listed below shoul d be submitted, stored, tracked, and also used to calculate fire emissions when necessary. In the NEI, fire sources are contained in the area source category. Therefore, a data file which records are similar to the NIF area source file may define the fire source file.

1) Inventory year 2) Inventory start date 3) Inventory end date 4) Inventory type 5) County code 6) State and county FIPS code 7) Tribal code 8) SCC code 9) Date of burnEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

22 

### 10) Duration of burn 11) Burn location latitude 12) Burn location longitude 13) Area of burn 14) Fuel type 15) Pre-burn fuel loading 16) Type of burn 17) Anthropogenic or natural classification 18) Daily tracking components 19) Fuel consumption 20) Non-burning techniques 21) Additional fire tracking information 22) Pollutant code 23) Emission factor 24) Daily emissions 25) Annual emissions

4.8. Standard Reports and Queries

The EDMS should have the capability to produce th e following standard reports in tabular and simple plots (i.e. bar graph and pie chart) form ats and allow queries of the same information including presentation in GIS format.

A summary report of the annual WRAP emissi on inventory, compiled at the county and reservation levels and totaled for each st ate, tribe, and the WRAP region, for all pollutants, broken down by point, area, mob ile, fire, biogenic, and windblown dust source categories, and by summed total emissions for all six source categories.

A summary report of the annual WRAP emissi ons from the stationary point sources in each county and reservation and the stationary point sources for each state, tribe and the entire region (broken down by plant name), for each pollutant.

A summary report of the annual WRAP emissi ons from the stationary point sources in each county and reservation and the stationary point sources for each state, tribe and the entire region (broken down by SCC code), for each pollutant.

A summary report of the annual WRAP emissions from the area sources in each county and reservation and the area sources for each state, tribe and the entire region (broken down by SCC code), for each pollutant.

A summary report of the annual WRAP emi ssions from the “Top 10” stationary point sources in each county and reservation and th e “Top 10” stationary point sources for each state, tribe and the entire region (broken down by plant name), for each pollutant.

A summary report of the annual WRAP emi ssions from the “Top 10” stationary point sources in each county and reservation and th e “Top 10” stationary point sources for each state, tribe and the entire region (broken down by SCC code), for each pollutant.

A summary report of the annual WRAP emi ssions from the “Top 10” area sources in each county and reservation and the “Top 10” ar ea sources for each state, tribe and the entire region (broken down by SCC code), for each pollutant.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

23

### A summary report of the annual WRAP emissi ons from on-road mobile sources in each county and reservation and on-road mobile s ources for each state, tribe and the entire region (broken down by the sixteen (16) mobile source categories), for each pollutant and dust from paved and unpaved road.

A summary report of the annual WRAP emissi ons from non-road mobile sources in each county and reservation and non-road mobile s ources for each state, tribe, and the entire region (broken down by SCC code), for each pollutant.

A summary report of the annual WRAP emissi ons from fire sources in each county and reservation and fire sources for each state, tribe, and the entire region (broken down by the 3 fire categories (wildfire, prescribed wild land burning, and agricultural burning activities), for each pollutant.

A summary report of the annual WRAP emi ssions from biogenic sources in each county and reservation and biogenic sources for each state, tribe, and the entire region (broken down by emission source name).

Data reports in the NEI Input Format Vers ion 3.0 (NIF V3.0) for submittal to the EPA under the CERR.

For stationary point sources, data reports for all emission points on site by text description name and by Stack ID, for NE I file format stack parameters (STKHGT, STKDIAM, STKTEMP, STKFLOW, STKVEL), production rates (BOILCAP, CAP_UNITS, THRUPUT, MAXRATE, N ETDC), fuel parameters (HEATCON, SULFCON, ASHCON), standard industrial cla ssification code (SIC), location (LATC, LONG), and emission controls ("pollutant"_CE , "pollutant"_CPRI, "pollutant"_CSEC).

For stationary point sources, data reports for all emission points on site by text description name and by Stack ID, for actua l emission rates of each pollutant, on an annual (tpy) and on a short term (pounds per hou r) basis. This e mission data will be summed for a cumulative total of emissions from each stationary point source.

In addition to these standard reports, the EDMS will produce regional emission model (SMOKE)-ready emissions input files for th e regional visibility modeling efforts.

4.9. Special Section 309 Tracking

Section 309 of the RHR requires that the firs t SIP be submitted by December 31, 2003 and that SIP must be effective until December 2018. Section 309 also specifically requires comprehensive emissions tracking and reporting fo r the clean air corridors (CAC), stationary SO 2 

### sources, mobile sources, fire sources, a nd windblown dust based on annual emissions.

4.9.1 Clean Air Corridors (CAC)

The preamble of the RHR defines a CAC as “a regi on that generally brings clean air to a receptor region”. The preamble also says, “the requirement to track emissions will enable states to quickly determine if changes in patterns of emissions will reduce the number of clean air days (defined as the average of the 20% clearest days) in any of the 16 Class I areas.” The actual requirements state that the Sec tion 309 SIP/TIP must describe a nd provide for implementation of comprehensive emission tracking strategies for CAC to ensure that the visibility does not degrade on the least-impaired days at any of the 16 Class I areas. The strategy must include:EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

24

### An identification of CAC.

Within areas that are CAC, an identification of patterns of growth or specific sites of growth that could cause, or are causing, sign ificant emissions increases that could have, or are having, visibility impairment at one or more of the 16 Class I areas.

In areas outside of CAC, an identification of significant emissions growth that could begin, or is beginning, to impair the quality of air in the corridor and thereby lead to visibility degradation for the least-impaired days in one or more of the 16 Class I areas.

If impairment of air quality in CAC is identified, an analysis of the effects of increased emissions, including provisions for the identif ication of the need for additional emission reduction measures, and implementation of the additional measures where necessary.

A determination of whether other clean air corridors exist for any of the 16 Class I areas. For any such CAC, an identification of the necessary measures to protect against future degradation of air quality in any of the 16 Class I areas.

WRAP identified one CAC as shown in Appendix H. Using the most recent state emission inventories available through the WRAP EDMS, WRAP will produce a report for each five-year implementation plan revision (2008, 2013, and 2018) on the current and projected emissions in the CAC and in areas outside the corridor a nd compare these emissions to a 1996 baseline emissions.

WRAP has examined patterns of growth in the CAC and found that they are not causing significant emission increases that could have or are having visibility impacts at one or more of the 16 Class I areas. Nor, at this time, are such emission increases expected during the first planning period (2003-2018). WRAP also has exa mined emissions growth in areas outside the corridor and found that significant emissions grow th is not occurring that could begin or is beginning to impair the quality of the air in the corridor and thereby lead to visibility degradation for the least impaired days in one or more of the 16 Class I areas.

Since impairment of air quality in clean air co rridors has not been identified, WRAP finds no requirement under for further visibility impact analysis or additional emission reduction measures until at least the next SIP revision ( 2008). WRAP finds no ot her clean air corridors beyond the corridor identified in Appendix H.

Consequently, the EDMS should have the capabilit y to produce the following special reports in tabular and simple plots (i.e. ba r graph and pie chart) formats and allow queries of the same information including presentation in GIS fo rmat, in addition to the standard reports.

A summary report of the annua l summed total emissions for all six source categories and all of the pollutants by county/state and tribal lands, as well as for the entire CAC.

A summary report of the annua l summed total emissions for all six source categories and all of the pollutants for the same types of political boundaries surrounding the CAC.

A summary report of the comparison of the annual summed total emissions for all six source categories and all of the pollutants fo r the same types of political boundaries, as well as the entire CAC and the corresponding base year total emissions.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

25 

### 4.9.2 Pre-Trigger SO 2 

### Annex

The SO 2 

### Annex program, as proposed by WRAP and a dopted by EPA, requires the tracking of SO 2 

### emissions from eligible stationary sources within states or tribal reservations participating in Section 309, to determine if the regional SO 2 

### emissions cap has been exceeded. This is known as “pre-trigger” tracking. Beginning with th e 2003 calendar year and continuing through 2018, each state and tribe participating in the program will submit an annual SO 2 

### emissions report to the WRAP EDMS for the sources covered by the program. These annual reports will contain the following information:

Identification and explana tion for new/additional SO 2 

### sources which emissions are greater than100 tpy that were not contained in the previous year’s emissions report.

Explanation for sources shut down or removed from the previous year’s emissions report.

Explanation for emissions vari ations at any covered source that exceeds +/- 20% from the previous year.

Identification and explanati on of new emissions reporting methods at any source.

WRAP will compile the annual emi ssions reports submitted by the st ates and tribes participating in the program into a regional emission report for SO 2 

### using the WRAP EDMS. By December 31 of the year following the applicable compliance year, WRAP will prepare a regional emission report that will include the following information:

Summary of regional SO 2 

### emissions (tpy).

Identification of any paper emission increase s and decreases that have occurred due to changes in emission inventory techniques since the last SIP revision for the regional haze SIP. The report will contain a running regional total, as well as supporting documentation identifying the specific changes that have occurred at individual sources.

Average emissions for the last three years (if applicable) for comparison to the regional milestone.

Regional milestone for the compliance period.

Draft determination that the mile stone has either been met, or has been exceeded thereby triggering the backstop trading program.

Consequently, The EDMS should have the capabilit y to produce the following special reports in tabular and simple plots (i.e. ba r graph and pie chart) formats and allow queries of the same information including presentation in GIS fo rmat, in addition to the standard reports.

A summary report of the annual WRAP emi ssions from the stationary sources emitting more than 100 tpy of SO 2 

### in the base year for each state, tribe and the entire region.

A summary report of the new stationary sources emitting more than 100 tpy of SO 2 

### that were not contained in the previous year’s i nventory for each state, tribe and the entire region.

A summary report of the stationary so urces emitting more than 100 tpy of SO 2 

### that are retired compared to the previous year’s inventory for each state, tribe and the entire region.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

26

### A summary report of the regional average SO 2 

### emissions from stationary sources emitting more than 100 tpy of SO 2 

### for the last three years and comparison to the regional milestone for the compliance period.

A summary report of the stationary so urces emitting more than 100 tpy of SO 2 

### which emissions exceed +/- 20% compared to the prev ious year’s inventory for each state, tribe and the entire region.

A summary report identifying all the stati onary sources emitting more than 100 tpy of SO 2 

### that choose to opt in the program for each state, tribe and the entire region.

A summary report identifying all the stati onary sources emitting more than 100 tpy of SO 2 

### that were not included in the base year for each state, tribe and the entire region.

4.9.3 Mobile Emissions

For mobile sources, the SIP/TIP submissions must provide for statewide inventories of on-road and non-road mobile source emissions of VOC, NO X 

### , SO 2 

### , PM 2.5 

### , EC, OC, and paved and unpaved road dust for the years 2003, 2008, 2013, and 2018. The inventories must demonstrate a continuous decline in total mobile source emissions for the aforementioned pollutants, evaluated separately. This means that the statewide mobile source emissions of each pollutant in 2008, 2013, and 2018 must be less than the estimated emissions of that pollutant for the previous period.

Consequently, the EDMS should have the capabilit y to produce the following special report in tabular and simple plots (i.e. ba r graph and pie chart) formats and allow queries of the same information including presentation in GIS fo rmat, in addition to the standard reports.

A summary report of the comparison of annu al WRAP total (on-road plus nonroad) emissions from the mobile sources (VOC, NOx, SO 2 

### , PM 2.5 

### , EC, OC, and paved and unpaved road dust) for each state, tribe a nd the entire region and the corresponding previous period total emissions, for each pollutant.

4.9.3 Fire Emissions

For fire emissions, Section 309 of the RHR speci fically calls for a statewide inventory and emissions tracking system (spa tial and temporal) of VOC, NO X 

### , EC, OC, and PM 2.5 

### emissions from fire. The WRAP inventory will add SO 2 

### , PM 10 

### , CO, and NH 3 

### emissions.

Under Section 309, states and tribes must identif y a method or a timeline to develop a method to track fire activity data and calculate the resulting required emissions inventory in their SIP/TIP. Tracking of fire activity data and calculation of the resulting emissions through the WRAP EDMS will provide information critical to the successful implementation of other requirements under Section, including the development, adop tion, and implementation of enhanced smoke management programs, the establis hment of annual emission goals, and future projections of fire emissions.

The WRAP EDMS will track activity data as reported by states and tribes participating in Section 309, as well as the same ty pe of data provided by other WRAP region state, tribal, andEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

27 

### local air agencies, and federal/state/private sour ces using prescribed and/or agricultural burning techniques. The WRAP EDMS will calculate the resulting emissions for fire source types including prescribed fire, wildfire, wild land fire use, and agricultural burning.

The EDMS should have the capability to produce a sp ecial report in tabular and simple plots (i.e. bar graph and pie chart) formats and allow queries of the same information including presentation in GIS format in the standard repor t style presented in Section 3.8 of this report.

4.10 GIS Module

GIS provides users with the ability to display and analyze data that is related to a geographic location. GIS provides a means for an organizati on to display data that is easily read and understood. The WRAP EDMS should include a fully functioning GIS module that provides multiple tools to display data over the internet. The inclusion of a GIS module will provide a means for users to select data that is of importanc e to them and display the data in a fashion that is easily understood.

During Phase I of development, the WRAP EDMS should include the following GIS Functionality.

Pan and zoom

Query layer information

Ability to add/remove multiple layers of data

Point and click

Measure distances

Buffer

Print – multiple sizes of maps

Select map features by line, rectangle or polygon

Phase II development of the WRAP EDMS coul d include some of the following additional functionality.

Export selected maps shape files

Generate polygons/layers from coordinates stored in the WRAP EDMS (e.g. create polygons for fire burn areas)

The WRAP EDMS GIS module should include th e following layers of data for Phase I development.

Static layers

County, state and country polygons

Tribal reservation polygons

Metropolitan statistical areas polygons

Nonattainment area polygons

Class I areas polygonsEA Engineering, Science, and Technology FINAL TECHNICAL REPORT

28

### Interstate and highway line features

Other roadways and railroad line features

Bodies of water polygons

Census data polygons

Other federal land polygons (i .e. national parks, monumen ts, forest, and refuges)

CAC polygons

International area polygons

WRAP modeling domain grid system

Dynamic/Data driven layers

Select and display emissions sources and a ssociated emissions levels by geographical

area.

4.11 DBA Module

All major applications and systems include an ad ministrative section or module that allows the application administrator(s) to perform general system maintenance as well as application specific system maintenance. These maintenance routines consist of tasks that are routinely performed by the application or system administr ator(s) and can easily be automated through a graphical user interface. Often times there are ta sks that administrators need to perform that cannot easily be automated, due to the complexity or changing nature of the task, and would not be included in the administrative module of the application.

The WRAP EDMS will require a DBA Module, wh ich will provide the ne cessary functionality required to perform several administrative tasks. During Phase I of development, the WRAP EDMS should include the following DBA Functionality.

User account maintenance – ma intain the list and permissions for users of the WRAP EDMS.

Lookup table maintenance (unit conversions, threshold values, etc.) – maintain the multiple lookup tables and associated data that will be included in the WRAP EDMS.

Versioning/maintenance of submitted data – ability to version submitted data and determine current vers ion of all data.

Data gap filling triggered from a QA/QC chec k, following specific methods that will be developed by WRAP.

International data maintenance – maintain the tables and data for all international data necessary for the WRAP EDMS.

Opt-in options for individual states, tribes, and sources – maintain list of states and tribes with associated emissions sources that decide to opt-in for Sections 308 and 309 tracking, after 2003.

Others – other DBA module functionality requirements as determined necessary.

During Phase II development, the WRAP EDMS should include the following DBA Functionality.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

29

### Data warehousing/archiving – ability to move historical data out of the production database and into a WR AP data warehouse.

Historical data retrieval – ability to generate reports and data sets from the WRAP data warehouse.

4.12 QA/QC Module

The WRAP EDMS will include a QA/QC module to perform two le vels of QA/QC. The QA/QC protocol will be similar to that of NEI with some modifications (see Appendix F for the NEI QA/QC process). The first level of QA/QC shoul d include a validation of the format of the submitted data files at the submission point of entry. This would ensure that the submitting entity supplied all data to the WRAP EDMS in the expected format and also identify any errors. The second level of QA/QC should consist of chec ks of the data that was submitted to WRAP. This should include checking reference values and acceptable data ranges for specific data points.

The WRAP EDMS QA/QC module should perform the following types of format checks.

Does the file conform to the format specification? - The initial checks performed on each submitted data set will verify that the file format is correct, and therefore readable for further processing (e.g., field widt hs, begin/end pos ition, data types).

Are mandatory data elements reported? - Th e presence or absence of mandatory data elements will be confirmed. Some of the mandatory data fields are the primary keys (i.e. FIPS codes and SCC Codes) in each record that help relate and maintain the individual records together in a file for subsequent processing.

Does the data set contain what the STL agency said they are submitting? - The data in the file will be compared to the Inventory Submittal Form (ISF) that was provided with the file to verify the noted and intended cove rage for geographic area, pollutants, source categories, and temporal information.

WRAP will keep a log of errors and problems en countered with each of the data submissions, and will provide those to the STL agency when communicating with the agency.

The WRAP EDMS QA/QC for data content will consist of two areas of QA/QC. First, the data will be checked for completeness, ensuring that all data exists for all sources and geographic areas. Second, the data integrity will be checke d, ensuring that supplied values are within acceptable ranges and all codes are valid. The QA/QC module should perform the following types of data content checks for completeness.

Add records to fill in missing facilities or source categories, or to fill in for missing geographic areas (e.g., where data were not reported for entire counties).

Add, or solve for, data elements missing in existing records.

Additionally, the QA/QC module will perform th e following data augmentation processes:

Calculate EC and OC emissions.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

30

### Aggregate dust and biogenic source data from the supplied grid and hourly levels to county/reservation and annual levels.

Modify county data to exclude sources and e missions from tribal reservations that are within the county’s boundaries.

The QA/QC module should perform the follo wing types of data integrity checks.

Conditional fields - fields required by other fields in the sa me table. For example, if there is a PCT Capture Efficiency in the Control E quipment (CE) table, then there should also be a Primary Device Type in the CE Table.

Acceptable codes - the Pollutant Code (and a ll acceptable codes) should be consistent.

Numeric values in acceptable range - For exam ple, the annual average days per week in the Emission Point (EP) table should be less than seven.

Inter-File Format - fields required by other fields in different tables. If there is an Emission Record in the Emission (EM) table, then there should be an associated activity record in the Activity Code (AC) table.

Inter-source relationships

Inter-pollutant relationships

Advance point source diagnostic – check of la rgest sources, out of range stacks, stack location.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

31 

### 5.0 CONCLUSIONS

Under contract with the WRAP EF, EA performed an EDMS needs assessment that included two interview workshops, a web-based que stionnaire, and an evaluation of selected existing systems. Five existing database management systems were evaluated and compared to the conceptual WRAP EDMS developed from the findings of the workshops and web-based questionnaire.

The workshops and questionnaire re sults indicated that the WRAP EDMS should be used as the repository of WRAP regional emissi ons data, and as a tool that can help in the implementation of the emissions tracking and reporting requirements of the RHR. The WRAP EDMS will be able to track all the visibility-impairing pollutants. The emissions data will primarily be submitted by STL agencies in an EPA-compliant format according to an open submittal process. Furthermore, the WRAP EDMS will contain six major sources representing the emissions sources: point, area, mobile, fire, biogenic, and windblown dust sour ces in addition to a QA/QC module, a GIS module, and a DBA module. Finally, the WRAP EDMS will produce user-specified standard and RHR-special reports and will allow data queries and graphical display, and presentation of this information in GIS format.

The results of the comparative analysis showed that the conceptual WRAP EDMS has a unique set of requirements that are not fully implemented in any existing EDMS. Therefore, a new individual EDMS needs to be de veloped to meet the requireme nts for the conceptual WRAP EDMS. Also, this new system could utilize some of the features incorporated in several of the existing systems to accomplish some of the WRAP EDMS requirements.EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

32 

### 6.0 REFERENCES

California Air Resources Board (CARB) , EMFAC 2002 Vehicle Emission Model, 2002.

Code of Federal Regulation (CFR), Chapter 40, Part 51.

Code of Federal Regulation (CFR), Chapter 40, Part 49.

Federal Aviation Administration (FAA), Emi ssion and Dispersion Modeling System (EDMS) Version 4.1, 2002.

Federal Register (FR), Volume 64, PP 35756.

Federal Register (FR), Volume 67, PP 30439.

Federal Register (FR), Volume 67, PP 7263-64.

Federal Register (FR), Volume 67, PP 39602-16.

Grand Canyon Visibility Transport Commission (GCVTC), Recommendations for Improving Western Vistas, Report to the EPA, June 10, 1996.

MCNC, Sparse Matrix Operator Kernel Emissions (SMOKE) Modeling System, 1999

Pechan, Draft RPO Data Exchange Protocol, 2003.

US Environmental Protection Agency (EPA), Us er’s Guide to Mobile6.1 and Mobile6.2: Mobile source Emission Factor Model, 2002.

US Environmental Protection Agency (EPA), Dr aft User’s Guide to PART5: A Program for Calculating Partic le Emissions from Motor Vehicles, 1995.

US Environmental Protection Agency (E PA), Draft NONROAD Model for 2007 HD Highway Rulemaking, June 2000.

US Environmental Protection Agency (EPA), Bi ogenic Emission Inventory System Version 2.3, 1998.

US Environmental Protection Agency (EPA), Co mpilation of Air Pollutant Emission Factors, AP-42, Fifth Edition, Volume I : Stationary Point and Area Sources, 1998.

Western Regional Air Partnership (WRAP) , WRAP Policy Fire Tracking System, 2002.Appendix A-7 – Stationary Sources Arizona Regional Haze SIP 

## APPENDIX A-7. STATIONARY SOURCES

This appendix contains work products a nd references relied u pon by Arizona in the development of Chapter 7 of the Regional Haze SIP.Appendix A-7 – Stationary Sources Arizona Regional Haze SIP 

## Appendix A-7a. Arizona Draft Western Backstop SO 2 

## Trading Program Rule

## DRAFT RULE

NOTE : This draft rule has been included in Arizona’s Regional Haze State Implementation
Plan in order to give the reader an opportuni ty to see how Arizona has currently interpreted
the Model Rule for state-specifi c rulemaking. This draft rule will go through revisions prior
to its submission to Arizona’s Secretary of State, after the public comment period, and is
subject to the final review of the G overnors’ Regulatory Review Council.

TITLE 18. ENVIRONMENTAL QUALITY
CHAPTER 2. DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR POLLUTION CONTROL

ARTICLE 16. VISIBILITY; REGIONAL HAZE

Section R18-2-1610 Western Backstop SO 2 Trading Program; Definitions ......... New Section
R18-2-1611 Pre-trigger Applicability; Monitoring, Recordkeeping
and Reporting ........................................................ New Section
R18-2-1612 WEB Trading Program Trigger ............................ ......... New Section
R18-2-1613 WEB Trading Program Applicability .............................. New Section
R18-2-1614 Account Representative fo r WEB Sources ........................ New Section
R18-2-1615 Registration ............... ............................................. New Section

R18-2-1616 Allowance Allocations .............................................. New Section

R18-2-1617 Establishment of A ccounts ......................................... New Section
R18-2-1618 Monitoring, Recordkeep ing and Reporting ..................... New Section

R18-2-1619 Allowance Transfers ................................................ New Section

R18-2-1620 Use of Allowances from a Previous Year ........................ New Section
R18-2-1621 Compliance ............................................................ New Section
R18-2-1622 Special Penalty Provisions fo r the 2018 Milestone ............... New Section

ARTICLE 16. VISIBILITY; REGIONAL HAZE

R18-2-1607. Reserved

R18-2-1608. ReservedR18-2-1609. Reserved

R18-2-1610. Western Backstop SO 2 Trading Program; Definitions

A. This rule implements the Western Backstop SO 2 Trading Program (“WEB Trading
Program”) provisions required under the fede ral Regional Haze Rule, 40 CFR 51.309, and

the SO 2 Milestones and Backstop Trading Program.
1. All applicable sources as described in Sections 1611 and 1613 of this Rule shall
meet the pre-trigger monitoring, recordkeeping and reporting requirements as

outlined in Section 1611 of this Rule.
2. Nothing in this Rule waives any requir ement otherwise in effect or subsequently
required under another program, in cluding rules governing new sources.

B. The definitions in this part apply only to this Rule.
1. “Account Certificate of Representation” means the completed and signed
submission required to designate an Account Representative for a WEB source or
an Account Representative for a general account.
2. “Account Representative” means the individual who is authorized through an
Account Certificate of Representation to represent owners and operators of the
WEB source with regard to matters under the WEB Trading Program or, for a
general account, who is authorized through an Account Certificate of
Representation to represent the persons having an ownership interest in
allowances in the general account with re gard to matters concerning the general

account.
3. “Act” means the federal Clean Air Act, as amended, 42 U.S.C. 7401, et seq.

4. “Actual Emissions” means total annual sulfur dioxide emissions determined in

accordance with Section 1618 of this Ru le, or determined in accordance with
[refer to state or tribal inventory rule] for sources that are not subject to Section

1618 of this Rule.
5. “Allocate” means to assign allowances to a WEB source.

6. “Allowance” means the limited aut horization under the WEB Trading Program to

emit one ton of SO 2 during a specified control period or any control period
thereafter subject to the terms and cond itions for use of unused allowances as
established by this Rule.
7. “Allowance limitation” means the tonnage of SO 2 emissions authorized by the
allowances available for compliance deduction for a WEB source for a control
period under Section 1621(A) of this Rule on the allowance transfer deadline for
that control period.8. “Allowance Tracking System” means the system developed by the Director where
allowances under the WEB Trading Program are recorded, held, transferred and

deducted.
9. “Allowance Tracking System” account means an account in the Allowance
Tracking System established for purposes of recording, holding, transferring, and
deducting allowances.

10. “Allowance transfer deadline” means the deadline established in Section 1619(B)

of this Rule when allowances must be submitted for recording in a WEB source’s
compliance account in order to demonstrate compliance for that control period.
11. “Compliance account” means an account established in the Allowance Tracking
System under Section 1617(A) of this Rule for the purpose of recording
allowances that a WEB source might hold to demonstrate compliance with its

allowance limitation.
12. “Compliance certification” means a submission to the Director by the Account
Representative as required under Section 1621(B) of this Rule to report a WEB
source’s compliance or noncom pliance with this Rule.
13. “Control period” means the period begi nning January 1 of each year and ending
on December 31 of the same year, inclusive.
14. “Emissions tracking database” means the central database where SO 2 emissions
for WEB sources as recorded and reporte d in accordance with this Rule are
tracked to determine compliance with allowance limitations.
15. “Emission unit” means any part of a stationary source that emits or would have
the potential to emit any pollutant submitte d to regulations under the Clean Air

Act.
16. “Existing source” means a stationary source that commenced operation before the
Program Trigger Date.

17. “Fugitive emissions” means those emissions that could not reasonably pass
through a stack, chimney, vent, or othe r functionally equivalent opening.

18. “General account” means an account established in the Allowance Tracking
System under Section 1617 of this Rule for the purpose of recording allowances
held by a person that are not to be used to show compliance with an allowance

limitation.
19. “Milestone” means the maximum level of stationary source regional sulfur
dioxide emissions for each year from 2003 to 2018.
20. “New WEB Source” means a WEB source that commenced operation on or after
the Program Trigger Date.21. “New Source Set-aside” means a pool of allowances that are available for

allocation to new sources.
22. “Owner or operator” m eans any person who is an owne r or who operates, controls
or supervises a WEB source, and includes but is not be limited to any holding
company, utility system or plant manager.
23. “Potential to emit” means the maximum capacity of a stationary source to emit
any air pollutant under its physical and operational design. Any physical or
operational limitation on the capacity of a source to emit an air pollutant,
including air pollution control equipment and restrictions on hours of operation or
on the type or amount of material combusted, stored or processed, shall be treated
as part of its design if the limitation is enforceable by the EPA Administrator.
24. “Program trigger date” means the date that the Director determines that the WEB
Trading Program has been triggered.
25. “Program trigger years” means the year s for the applicable milestone if the WEB
Trading Program is triggered.
26. “Renewable Energy Resource” means a resource that generates electricity by nonnuclear and non-fossil technologies that results in low or no air emissions. The
term includes electricity generated by wind energy technologies; solar
photovoltaic and solar thermal tec hnologies; geothermal technologies;
technologies based on landfill gas and biomass sources, and new low-impact
hydropower that meets the Low-Impact Hydropower Institute criteria. Biomass
includes agricultural, food and wood wastes. The term does not include pumped
storage or biomass from municipal solid waste, black liquor, or treated wood.

27. “Retired source” means a WEB source that has received a retired source
exemption as provided in Section 1613(C) of this Rule. Any retired source
resuming operations under Section 1613(C )(4) of this Rule, must submit its
exemption as part of its registration materials.
28. “Serial number” means, when referri ng to allowances, the unique identification
number assigned to each allowance by the Tracking Systems Administrator, in
accordance with Section 1616(B) of this Rule.

29. “SO 2 emitting unit” means any equipment that is located at a WEB source and

that emits SO 2 . 30. “Stationary source” means any building, structure, facility or installation that
emits or may emit any air pollutant subjec t to regulation under the Clean Air Act.
31. “Submit” means sent to the appropriate authority under the signature of the
Account Representative. For purposes of determining when something issubmitted, an official U.S. Postal Service postmark, or equivalent electronic time
stamp, shall establish the date of submittal.
32. “Ton” means 2000 pounds and, for an y control period, any fraction of a ton
equaling 1000 pounds or more shall be tr eated as one ton and any fraction of a ton
equaling less than 1000 pounds shall be treated as zero tons.
33. “Tracking System Administrator” means the person designated by the Director as
the administrator of the Allowance Tracking System and the emissions tracking

database.
34. “WEB source” means a stationary s ource that meets the applicability requirements

of Section 1613 of this Rule.
35. “Western Backstop SO 2 Trading Program (“WEB Trading Program”)” means in
reference to this Rule, the program triggered as a backstop, if necessary, to ensure
that regional SO 2 emissions are reduced.

R18-2-1611. Pre-trigger Applicability; Monitoring, Recordkeeping and Reporting

A. Applicable sources are described in Section 1613 of this Rule.

B. All applicable sources shall follow the pr ovisions for monitoring, recordkeeping and
reporting as outlined in R18-2-304, R18-2-306, R18-2-327, or R18- 2-715.01, and, in
addition, shall:
1. Submit an annual inventory of SO 2 emissions, beginning with the 2003 emission
inventory.
a. A source that emits 100 tons per year or more of SO 2 in a later year shall

continue to submit an SO 2 inventory for tracking compliance with the
regional SO 2 milestones until 2018 or until the WEB Trading Program
has been fully implemented and emissions tracking is occurring,

whichever is earlier.

b. Smelters shall submit an annual re port of sulfur input in tons per year
with the submission of the annual emissions inventory.
2. Utilize appropriate emission factors a nd estimating techniques, and document the
emissions monitoring or estimation methodology used.
3. Include emissions from start up, shut down, and upset cond itions in the annual
total inventory.
4. Utilize, if subject to the federal acid rain program, methods from 40 CFR Part 75
to report emissions from all sources.
5. Include the rate and period of emi ssions, the specific installation that is the
sources of the air pollution, composition of air contaminant, type and efficiency ofthe air pollution control equipment, a nd other information necessary to quantify
operation and emissions, and to evaluate pollution control.
6. Retain records for a minimum of 10 years from the date of creation, or if the
record was the basis for an adjustment to a milestone, 5 years from the date of a
state implementation plan revision, whichever is longer.

R18-2-1612. WEB Trading Program Trigger

A. Except as provided in 1612(B), Sections 1613 through 1621 of this Rule shall become
effective on the program trigger date that is established in accordance with the procedures
outlined in the 40 CFR 51.309(4)(h).

B. Section 1622 of this Rule, Special Penalty Provisions for Year 2018, shall become
effective on January 1, 2018 and shall remain effective until the provisions of Section
1622 of this Rule have been fully implemented.

R18-2-1613. WEB Tradin g Program Applicability

A. General Applicability. This Rule applies to any stationary source or group of stationary
sources that are located on one or more contiguous or adjacent properties and which are
under the control of the same person or pers ons under common control, belonging to the
same industrial grouping, and that are describ ed in paragraphs (1) through (4) of this
subsection. A stationary source or group of sta tionary sources shall be considered part of a
single industrial grouping if all of the polluta nt emitting activities at such source or group
of sources on contiguous or adjacent proper ties belong to the same Major Group (i.e., all
have the same two-digit code) as described in the Standard Industrial Classification
Manual, 1987.

B. The following are WEB sources:
1. All BART-eligible sources as defined in 40 CFR 51.301 that are BART-eligible

due to SO 2 emissions.
2. All stationary sources not meeting the crite ria of 1613(A) of this Rule that have

actual SO 2 emissions of 100 tons or more per year in the Program Trigger Years
or any subsequent year. The fugitive emissi ons of a stationary source shall not be
considered in determining whether it is a WEB source unless the source belongs
to one of the following categories of stationary source:
a. Coal cleaning plants (with thermal dryers);
b. Kraft pulp mills;
c. Portland cement plants;
d. Primary zinc smelters;e. Iron and steel mills;
f. Primary aluminum ore reduction plants;
g. Primary copper smelters;
h. Municipal incinerators capable of charging more than 250 tons of refuse
per day;
i. Hydrofluoric, sulfuric, or nitric acid plants;
j. Petroleum refineries;
k. Lime plants;
l. Phosphate rock processing plants;
m. Coke oven batteries;
n. Sulfur recovery plants;
o. Carbon black plants (furnace process);
p. Primary lead smelters;
q. Fuel conversion plants;
r. Sintering plants;
s. Secondary metal production plants;
t. Chemical process plants;
u. Fossil-fuel boilers (or combina tion thereof) totaling more than 250
million British thermal units per hour heat input;
v. Petroleum storage and transfer units with a total storage capacity
exceeding 300,000 barrels;
x. Taconite ore processing plants;
y. Glass fiber processing plants;
z. Charcoal production plants;
aa. Fossil-fuel-fired steam electric plants of more than 250 million British
thermal units per hour heat input; or
bb. Any other stationary source categor y, which as of August 7, 1980 is being
regulated under Section 111 or 112 of the Act.
3. A new source that begins operation after the Program Trigger Date and has the
potential to emit 100 tons or more of SO 2 per year. 4. The Director may determine on a case-by-case basis, with concurrence from the
EPA Administrator, that a source defined in Section 1613(B)(2) of this Rule is not

a WEB source if the source:
a. In each of the previous five years had actual SO 2 emissions of less than
100 tons per year; and

b. Had actual SO 2 emissions of 100 tons or more in a single year due to atemporary emission increase that was caused by a sudden, infrequent and
not reasonably preventable failure of air pollution control equipment,
failure of process equipment, or a failu re to operate in a normal or usual

manner; c. Took timely and reasonable action to minimize the temporary emission
increase; and

d. Has corrected the failure of air pollution control equipment, process
equipment, or process by the time of the Director’s determination under
this section; or
e. Had to switch fuels or feedstocks on a temporary basis and as a result of
an emergency situation or unique a nd unusual circumstances besides cost

of such fuels or feedstocks.
f. A temporary emission increase due to poor maintenance or careless
operation does not meet the criteria of this section.

C. Duration of Program Participation. Except as provided for in Section 1613(D) of this
Rule, once a source is subject to the WEB Trading Program, it will remain in the program
every year thereafter.

D. Application for Retired Source Exemption. Any WEB that is retired shall apply for a
retired source exemption. The WEB source ma y only be considered retired if all SO 2 emitting units at the source are retired. The application shall contain the following

information:
1. Identification of the WEB source, in cluding plant name and an appropriate
identification code in a format specified by the Director.
2. Name of Account Representative.
3. Description of the status of the WEB source, including the date that the WEB

source was retired.
4. Signed certification that the WEB sour ce is retired and will comply with the
requirements of Sections 1613(D) through (H) of this Rule.

5. Verification that the WEB source has a general account where any unused

allowances or future allocations will be recorded.

E. Notice of Retired Source Exemption. The retired source exemption becomes effective
When the Director, or control officer with jurisdiction over the source, notifies the source

that the retired source exem ption has been granted.

F. Responsibilities of Retired Sources:1. A retired source shall be exempt from Sections 1618 and 1621 of this Rule, except
as provided below.
2. A retired source shall not emit any SO 2 after the date the retired source exemption

is effective.

3. A source shall submit SO 2 emissions reports, as required by Section 1618(H) of
this Rule for any time period the source w as operating prior to the effective date
of the retired source exemption. The retired source shall be subject to the
compliance provisions of Section 1621 of this Rule, including the requirement to
hold allowances in the source’s compliance account to cover all SO 2 emissions
prior to the date the source was permanently retired.

4. A retired source that is sti ll in existence but no longer emitting SO 2 shall, for a
period of five years from the date th e records are created, retain records
demonstrating the effective date of the retired source exemption for purposes of

this Rule.

G. Resumption of Operations. Should a retired source desire to resume operation, the retired
source must submit registration materials as follows:
1. If the source is required to obtain a ne w source review permit or operating permit
under [refer to applicable new source pe rmitting rule] prior to resuming operation,
then registration information as described in Section 1615(A) of this Rule and a
copy of the retired source exemption must be submitted with the application
required under [refer to applicable new source permitting rule];
2. If the source is not required to obtai n a new source review permit or operating
permit under [refer to applicable new source permitting rule] prior to resuming
operation, then registration information as described in Section 1615(A) of this
Rule and a copy of the retired source exemption must be submitted to the Director
at least ninety days prior to resumption of operation.
3. The retired source exemption shall au tomatically expire on the day the source
resumes operation.

H. Loss of Future Allowances.

1. A WEB source that is retired and that does not apply to the Director for a retired
source exemption within ninety days of th e date that the source is retired shall
forfeit any unused and future allowanc es. The abandoned allowances shall be
retired by the Tracking System Administrator.

Note to Reviewer: This is not intended to be a punitive action, but a
method to correct the number of allow ances being tracked by the state.The Director will need to establish due process procedures for forfeiting

these “abandoned” allowances in a manner that is consistent with the
administrative procedures process. Th is provision is intended to address
sources that go out of business, leave no forwarding address, and truly

abandon their allowances. It is assumed that the Director will have a
process to notify sources that their a llowances may be forfeited so this
provision does not lead to forfeiture ju st because the deadline was missed
Arizona will draft the appropriate noti fication language for this section.

R18-2-1614. Account Representative for WEB Sources

A. Each WEB source must identify one Account Representative and may also identify an
alternate Account Representative who may act on behalf of the Account Representative.
Any representation, action, inaction or submission by the alternate Account
Representative will be deemed to be a represen tation, action, inaction or submission by
the Account Representative.

B. Identification and Certificati on of an Account Representative.
1. The Account Representative and any A lternate Account Representative shall be
appointed by an agreement that makes the representations, actions, inactions or
submissions of the Account Representative and any alternate binding on the
owners and operators of the WEB source.
2. The Account Representative shall submit to the Director and the Tracking System
Administrator a signed and dated Account Certificate of Representation
(Certificate) that contains the following elements:
a. Identification of the WEB source by plant name, state and an appropriate
identification code in a format specified by the Director;
b. The name, address, e-mail (if available), telephone and facsimile number
of the Account Representative and any alternate;
c. A list of owners and operators of the WEB source;
d. Information to be part of th e emission tracking system database in
accordance with the Implementation Pl an. The specific data elements
shall be as specified by the Director to be consistent with the data system
structure, and may include basic facility information that may appear in
other reports and notices submitted by the WEB source, such as county
location, industrial classification codes, and similar general facility

information.
e. The following certification statement:“I certify that I was selected as th e Account Representative or alternate
Account Representative, as applicable , by an agreement binding on the
owners and operators of the WEB source. I certify that I have all the
necessary authority to carry out my duties and responsibilities under the
WEB Trading Program on behalf of the owners and operators of the WEB
source and that each such owner and operator shall be fully bound by my
representations, actions, inactions, or submissions and by any decision or
order issued to me by the Director regarding the WEB Trading
Program.”
3. Upon receipt by the Director of the complete Certificate, the Account
Representative and any alternate Account Re presentative represents and, by his or
her representations, actions, inactions, or submissions, legally binds each owner
and operator of the WEB source in all matters pertaining to the WEB Trading
Program. The owners and operators shal l be bound by any decision or order
issued by the Director regarding the WEB Trading Program.
4. No WEB Allowance Tracking System account shall be established for the WEB
source until the Tracking System Administrator has received a complete

Certificate. Once the account is establis hed, the Account Representative shall
make all submissions concerning the account, including the deduction or transfer

of allowances.

C. Requirements and Responsibilities of the Account Representative.
1. The responsibilities of the Account Representative include, but are not limited to,
the transferring of allowances, and the submission of monitoring plans,
registrations, certification applications, SO 2 emissions data and compliance
reports as required by this Rule, and representing the source in all matters
pertaining to the WEB Trading Program.
2. Each submission under this program shall be signed and certified by the Account
Representative for the WEB source. Each submission shall include the following
truth and accuracy certification statement by the Account Representative:
“I am authorized to make this submission on behalf of the owners and operators
of the WEB source for which the subm ission is made. I certify under penalty of
law that I have personally examined, and am familiar with, the statements and
information submitted in this documen t and all its attachments Based on my
inquiry of those individuals with primary responsibility for obtaining the
information, I certify that the statements and information are to the best of my
knowledge and belief true , accurate, and complete. I amaware that there aresignificant penalties for submitting false statements and information or omitting
required statements and information, including the possibility of fine or
imprisonment.”

D. Changes to the Account Represen tative; Owners and Operators.
1. Changes to the Account Representative or the alternate Account Representative.
a. The Account Representative or alternate Account Representative may be
changed at any time by sending a complete superseding Certificate to the
Director and the Tracking System Administrator under Section 1614(B)
of this Rule, with the change taking effect upon receipt of such Certificate
by the Director.
b. Notwithstanding any such change , all representations, actions, inactions,
and submissions by the previous Account Representative or alternate
prior to the time and date when the Tracking System Administrator
receives the superseding Certificate shall be binding on the new Account
Representative and the owners and operators of the WEB source.
2. Changes in Owners and Operators.
a. Within thirty days of any change in the owners and operators of the WEB
source, including the addition of a new owner or operator, the Account
Representative shall submit a revised Certificate amending the list of
owners and operators to include such change.
b. In the event a new owner or operator of a WEB source is not included in
the list of owners and operators subm itted in the Certificate, such new
owner or operator shall be deemed to be subject to and bound by the
Certificate, the representations, actions , inactions, and submissions of the
Account Representative of the WEB s ource, and the decisions, orders,
actions, and inactions of the Director as if the new owner or operator were

included in such list.

R18-2-1615. Registration

A. Deadlines.
1. Each source that is a WEB source on or before the Program Trigger Date shall
register by submitting the initial Certificat e required in Section 1614(B) of this
Rule to the Director no later than 180 days after the Program Trigger Date.
2. Any existing source that becomes a WEB source after the Program Trigger Date
shall register by submitting the initial Certificate required in Section 1614(B) of
this Rule to the Director by September 30 of the year following the inventory yearin which the source exceeded the emission threshold.
3. Any new WEB source shall register by submitting the initial Certificate required
in Section 1614(B) of this Rule to th e Director prior to the commencement of
operation.

B. Integration into Permits
1. Any allocation, transfer or deduction of allowance to or from the compliance
account of a WEB source shall not require revision of the WEB source’s
operating permit.
2. Any WEB source that is not required to have a permit under [s tate’s New Source
Review Rule] at any time after this Rule becomes effective must at all times
possess a permit that includes the requireme nts of this Rule. If it does not possess
a Title V permit under [state’s Title V rule], it may do so by obtaining or
modifying a permit under [state or tribe’s New Source Review Rule] to
incorporate the requirements of this Rule. The source must at all times possess a
permit that includes these requirements.

R18-2-1616. Allowance Allocations

A. The Tracking System Administrator will record the allowances for each WEB source in
the compliance account for a WEB source once the allowances are allocated by the
Director. If applicable, the Tracking System Administrator will record a portion of the

SO 2 allowances for a WEB source in a special reserve account assigned to the Director to
account for any allowances to be held by the Director in accordance with Section
1618(A)(2) of this Rule.

B. The Tracking System Administrator will assign a serial number to each allowance.

C. All allowances shall be allocated, recorded, transferred, or used as whole allowances. To
determine the number of whole allowances, the number of allowances shall be rounded
down for decimals less than 0.50 and rounded up for decimals of 0.50 or greater.

D. An allowance is not a property right, and is a limited authorization to emit one ton of SO 2 valid only for the purpose of meeting the require ments of this Rule. No provision of this
WEB Trading Program or other law should be construed to limit the authority of the

Director to terminate or limit such authorization.

E. Early Reduction Bonus Allocation.
1. Any WEB source that reduces permitted annual SO 2 emissions to a level that is

below the floor level allocation establishe d for that source between 2003 and the
program trigger year may apply to the Director for an early reduction bonus

allocation.2. The application must be submitted no later than ninety days after the Program
Trigger Date. Any WEB source that applies and receives early reduction bonus

allocations must retain the records refere nced below for a minimum of five years
after the early reduction bonus allowance is certified.
3. The application for an early reducti on bonus allocation must contain the following

information:
a. Copies of all permits or other en forceable documents that include annual

SO 2 emissions limits for the WEB source during the period the WEB
source was generating the early reductio ns. Such permits or enforceable
documents require monitoring for SO 2 emissions that meets the
requirements in Sections 1618(A)(1) and 1618(A)(3) of this Rule.

Note to reviewer: The early reduction bonus allocation needs to address

sources that are not using Part 75 e quipment monitoring. This is under

discussion.

b. Copies of emissions monitoring reports, for the period the WEB source was
generating the early reductions, that documents the actual annual SO 2 emissions

and demonstrates that the actual annual SO 2 emissions were below the floor level

allocation established for that source.

c. Demonstration that the floor level est ablished for the source was calculated using

data consistent with the new m onitoring methodology. If new monitoring
techniques change the floor level for th e source, then a demonstration of the new
floor level based on new monitoring techniques should be included in the
application.

F. Request for allowances for new WEB sources or modified WEB Sources.
1. A new WEB source or an existing WEB source that has increased production
capacity through a permitted change in operations [refer to state’s NSR Rules]
may apply to the Director for an allocation from the new source set-aside.
a. A new WEB source is eligible to apply for an annual allocation equal to
the permitted annual SO 2 emission limit for that source after the source
has commenced operation.
b. An existing WEB source is eligib le to apply for an annual allocation equal
to the permitted annual SO 2 emission limit for that source that is
attributable to any amount of production capacity that is greater than the
permitted production capacity for that source as of January 1, 2003.c. A source that has received a retired source exemption under Section
1613)D of this Rule is not eligible to apply for an allocation from the new

source set-aside.
2. The application for an allocation from the new source set-aside must contain the
following information:

a. Demonstration that shows th e permitted production capacity of the source
before and after the new permit;
b. For new WEB sources, documentation of the actual date of the
commencement of operation and a copy of the permit.

R18-2-1617. Establishment of Accounts

A. Allowance Tracking System Accounts.
1. All WEB sources are required to ope n a compliance account. Any person may
open a general account for holding and tr ansferring allowances. To open either
type of account, an application that co ntains the following information shall be

submitted:
a. The name, mailing address, e-ma il address, telephone number, facsimile
number of the Account Representative. For a compliance account, include
a copy of the Account Certificate of Representation of the Account
Representative and any alternate as requi red in Section 1614(B)(2) of this
Rule. For a general account, include the Account Certificate of
Representation of the Account Repr esentative and any alternate as
required in Section 1617(C)(2) of this Rule.
b. The WEB source or organization name;
c. The type of account to be opened; and
d. A signed certification of truth and accuracy by the Account
Representative according to Section 1614(C) of this Rule for compliance
accounts and for general accounts, certif ication of truth and accuracy by
the Account Representative according to Section 1617(D) of this Rule.

B. Account Representative for General Accounts.
1. For a general account, one Account Representative must be identified and an
alternate Account Representative may be id entified and may act on behalf of the
Account Representative. Any representation, action, inaction or submission by the
alternate Account Representative will be de emed to be a representation, action,
inaction or submission by the Account Representative.

C. Identification and Certification of an A ccount Representative for General Accounts.1. The Account Representative shall be a ppointed by an agreement that makes the
representations, actions, inactions or su bmissions of the Account Representative
binding on all persons who have an owners hip interest with respect to allowances
held in the general account.
2. The Account Representative shall submit to the Director and the Tracking System
Administrator a signed and dated Account Certificate of Representation
(Certificate) that contains the following elements:
a. The name, address, e-mail (if available), telephone and facsimile number
of the Account Representative and any alternate;
b. The organization name;
c. The following certification statement:
“I certify that I was selected as th e Account Representative or alternate
Account Representative, as applicable, by an agreement binding on all
persons who have an ownership int erest in allowances in the general
account with regard to matters concern ing the general account. I certify
that I have all the necessary author ity to carry out my duties and
responsibilities under the WEB Trading Program on behalf of said
persons and that each such person shall be fully bound by my
representations, actions, inactions, or submissions and by any decision or
order issued to me by the Direct or regarding the general account.”
3. Upon receipt by the Director of the complete Certificate, the Account
Representative represents and, by his or her representations, actions, inactions, or
submissions, legally binds each person who has an ownership interest in
allowances held in the general account w ith regard in all matters concerning the
general account. Such persons shall be b ound by any decision or order issued by

the Director.
4. No WEB Allowance Tracking System general account shall be established until
the Tracking System Administrator has received a complete Certificate. Once the
account is established, the Account Repr esentative shall make all submissions
concerning the account, including the deduction or transfer of allowances.

D. Requirements and Responsibilities.
1. Each submission for the general account shall be signed and certified by the
Account Representative for the general account. Each submission shall include
the following truth and accuracy certification statement by the Account
Representative:
“I am authorized to make this submission on behalf of all personwho have an ownership interest in allowances held in the general
account. I certify under penalty of law that I have personally
examined, and am familiar with, the statements and information

submitted in this document and all its attachments. Based on my
inquiry of those individuals with primary responsibility for
obtaining the information, I certify that the statements and
information are to the best of my knowledge and belief true,
accurate, and complete. I am aware that there are significant
penalties for submitting false statements and information or
omitting required statements and information, including the
possibility of fine or imprisonment.”

E. Changing the Account Representative.
1. The Account Representative or alte rnate Account Representative may be changed
at any time by sending a complete superseding Certificate to the Director and the
Tracking System Administrator under Section 1617(C)(2) of this rule, with the
change taking effect upon receipt of such Certificate by the Director.
Notwithstanding any such change, all representations, actions, inactions, and
submissions by the previous Account Representative or alternate prior to the time

and date when the Director receives the superseding Certificate shall be binding
on the new Account Representative and all person having ownership interest with
respect to allowances held in the general account.

F. Changes to the Account.
1. Any change to the information requi red in the application for an existing account
under Section 1617(A) of this Rule sha ll require a revision of the application.

R18-2-1618. Monitoring, Recordkeeping and Reporting

Note to Reviewer: Theses provisions will be reviewed and compared to the revised provisions
prepared by the Western Regional Air Partnership (WRAP) and EPA on August 13, 2003.
Revisions to this section of the rule may be necessa ry. References within this section are to the

Model Rule versus this Rule. The Model Rule is available on WRAP’s Web page at
www.wrapair.org

.

A. General Requirements.

1. For each SO 2 emitting unit at a WEB source the owner or operator shall comply
with the following, as applicable, to monitor and record SO 2 mass emissions:
a. If a unit is subject to 40 CFR Part 75 under a requirement separate from
the WEB Trading Program, the unit shall meet the requirements containedin Part 75 with respect to monitoring, recording and reporting SO 2 mass emissions. [As necessary, insert state rule language to address changes to
40 CFR Part 75.]
b. If a unit is not subject to 40 CFR Part 75 under a requirement separate
from the WEB Trading Program, a un it shall use one of the following
monitoring methods, as applicable:
i. A continuous emission monitoring system (CEMS) for SO 2 and
flow that complies with all applicable monitoring provisions in
40 CFR Part 75;
ii. If the unit is a gas- or oil-fired combustion device, the excepted
monitoring methodology in Appendix D to 40 CFR Part 75, or, if
applicable, the low mass emissions (LME) provisions (with
respect to SO 2 mass emissions only) of section 75.19 of 40 CFR
Part 75;
iii. One of the optional WEB protocols, if applicable, in Appendix A
to this Rule (attached); or
iv. A petition for site-specific monitoring that the source submits for
approval by the Director, and approval by the U.S. Environmental
Protection Agency in accordance with Section I8(e) of this Rule
(relating to petitions).
c. A permanently retired unit shall not be required to monitor under this
Section if such unit was permanently retired and had no emissions for the
entire period for which the WEB sour ce implements this paragraph (3)
and the Account Representative certifies in accordance with Section L2 of

this Rule that these conditions were met.
2. Notwithstanding paragraph (a) of this Sec tion, the owner or operator of a unit that
meets one of the conditions of paragraph (b)(1) may elect to have the provisions
of this paragraph (b) apply to that unit.
a. Any of the following units may implement this paragraph (b):
i. Any smelting operation where all of the emissions from the
operation are not ducted to a stack; or
ii. Any flare, except to the extent such flares are used as a fuel gas
combustion device at a petroleum refinery.
iii. Any other type of unit without add-on SO 2 control equipment, if
no control level was assumed for the WEB source in establishing
the floor level (and reducible allocation).b. For each unit covered by this para graph (b), the Account Representative
shall submit a notice to request that this paragraph (b) apply to one or

more SO 2 emitting units at a WEB source. The notice shall be submitted

in accordance with the co mpliance dates specified in Section I6(a) of this
Rule, and shall include the following information (in a format specified
by the Director with such additional, related information as may be
requested):
i. A notice of all units at the applicable source, specifying which of
the units are to be covered by this paragraph (b);
ii. Consistent with the emission estimation methodology used to
determine the floor level (and reduc ible allocation) for the source
in accordance with Section C1 of the Implementation Plan, the
portion of the WEB source’s overall allowance allocation that is
attributable to any unit(s) c overed by this paragraph; and
iii. An identification of any such units that are permanently retired.
c. For each new unit at an existing WEB source for which the owner or
operator seeks to comply with this paragraph (b) and for which the
Account Representative applies for an allocation under the new source
set-aside provisions of Section G6 of this Rule, the Account
Representative shall submit a modified notice under paragraph (b)(2) that

includes such new SO 2 emitting unit(s). The modified notice shall be
submitted in accordance with the complian ce dates in Section I6(a) of this
Rule, but no later than the date on which a request is submitted under

Section G6 of this Rule for allocations from the set-aside.
d. The Director shall evaluate the information submitted by the WEB source
in paragraphs (b)(2) and (b)(3), and may issue a notice to the source to
exclude any units that do not qualify unde r this paragraph (b) or to adjust
the portion of allowances attributable to units that do qualify to be
consistent with the emission estimation methodology used to establish the
floor level (and reducible allocation) for the source. Any such notice shall
be provided within 180 days after the date on which the notice from the

WEB source was received.

e. The Director shall hold allowances equal to the adjusted portion of the
WEB source’s allowances under paragra phs (b)(2), (b)(3), and (b)(4) in
an account maintained by the Director, provided that no such hold back of

the WEB source’s allocation will be required for any unit that ispermanently retired.
f. The Account Representative for a WEB source shall submit an annual
emissions statement for each unit under this paragraph (b). The WEB
source shall maintain operating records sufficient to estimate annual

emissions in a manner consistent with the emission estimation
methodology used to establish the floor level (and reducible allocation)

for the source. The Director will retire the allowances held under
paragraph (b)(5) to account for the em issions from such units. In addition,

if the estimated emissions from all such units at the WEB source are
greater than the allowances held under paragraph (b)(5) for the WEB
source, the Account Representative will report the excess amount as part
of the cumulative annual emissions report for the WEB source and be
required to use other allowances in the compliance account for the WEB
source to account for such emissions, in accordance with Section I8 of

this Rule.
g. The remaining provisions of this Section 1618 shall not apply to units
covered by this paragraph except where otherwise noted.
h. A WEB source may opt to modify the monitoring for an SO 2 emitting unit
to use monitoring under Section I1(a) of this Rule, but any such
monitoring change must take effect on January 1 of the next compliance
year. In addition, the Account Re presentative must submit an initial
monitoring plan at least 180 days prior to the date on which the new
monitoring will take effect and a detailed monitoring plan in accordance

with Section I2 of this Rule. Th e Account Representative shall also
submit a revised notice under paragraph (b)(2) at the same time that the
initial monitoring plan is submitted.
3. For any monitoring method that the owner or operator uses under this Section
(including paragraph (b)), the owner or operator (and, as applicable, the Account
Representative) shall implement, certify, and use such method in accordance with
this Section, and record and report the data from such method as required in this
Section. In addition, the owner or operator (and, as applicable, the Account
Representative) may not:
a. Use an alternative monitoring syst em, alternative reference method or
another alternative for the require d monitoring method without having
obtained prior written approval in accordance with Section I8(e) of this
Rule (relating to petitions);b. Operate an SO 2 emitting unit so as to discharge, or allow to be
discharged, SO 2 emissions to the atmosphere without accounting for these
emissions in accordance with the applic able provisions of this Section;
c. Disrupt the approved monitoring method or any portion thereof, and
thereby avoid monitoring and recording SO 2 mass emissions discharged
into the atmosphere, except for periods of recertification or periods when
calibration, quality assurance testing or maintenance is performed in
accordance with the applicable provi sions of this Section; or
d. Retire or permanently discontinue use of an approved monitoring method,
except under one of the following circumstances:
i. During a period when the unit is exempt from the requirements of
this Section, including retirement of a unit as addressed in Section
I1(a)(3);
ii. The owner or operator is monitoring emissions from the unit with
another certified monitoring met hod approved under this Section
for use at the unit that provides da ta for the same parameter as the
retired or discontinued monitoring method; or
iii. The Account Representative submits notification of the date of
certification testing of a replacement monitoring system in
accordance with this Section, and the owner or operator
recertifies thereafter a replacement monitoring system in
accordance with the applicable provisions of this Section.

B. Monitoring Plan.
1. General Provisions. The owner or operator of an SO 2 emitting unit that uses a
monitoring method under Section I1(a)(2) of this Rule shall meet the following
requirements:
a. Prepare and submit to the Director an initial monitoring plan for each
monitoring method that the owner or operator uses to comply with this
Section. In accordance with paragra ph I2(C) of this Rule, the plan shall
contain sufficient information on the units involved, the applicable
method, and the use of data derived from that method to demonstrate that

all unit SO 2 emissions are monitored and reported. The plan shall be
submitted in accordance with the complia nce dates specified in Section I5

of this Rule.
b. Prepare, maintain and submit to the Director a detailed monitoring plan at
least 45 days prior to the first day of certification testing. The plan willcontain the applicable information re quired by paragraph I2(d) of this
Rule. the Director may require that the monitoring plan (or portions
thereof) be submitted electronically. The Director also may require that
the plan be submitted on an ongoing basis in electronic format as part of
the quarterly report submitted under Section I8(a) of this Rule or
resubmitted separately within 30 days after any change is made to the
plan in accordance with the following paragraph (a)(3).
c. Whenever the owner or operator makes a replacement, modification, or
change in one of the systems or methodologies provided for in Section
I1(a)(2), including a change in the automated data acquisition and
handling system or in the flue gas handling system, that affects
information reported in the monitori ng plan (e.g., a change to serial
number for a component of a monitoring system), then the owner or
operator shall update the monitoring plan.
2. The owner or operator of an SO 2 emitting unit that uses a method under Section
I1(a)(1) of this Rule (a unit subject to 40 CFR Part 75 under a program other than
this WEB Trading Program) shall meet the requirements of Section I2(a)-(f) by
preparing, maintaining and submitting a monitoring plan in accordance with the
requirements of 40 CFR Part 75, provided that the owner or operator also shall
submit the entire monitoring plan to the Director upon request.
3. Initial Monitoring Plan. The Account Representative shall submit an initial
monitoring plan for each SO 2 emitting unit (or group of units sharing a common
methodology) that, except as otherwise speci fied in an applicable provision in
Appendix A, contains the following information:

a. For all SO 2 emitting units involved in the monitoring plan:
i. Plant name and location;
ii. Plant and unit identification numbers assigned by the Director;
iii. Type of unit (or units for a group of units using a common
monitoring methodology);

iv. Identification of all stacks or pipes associated with the monitoring
plan;
v. Types of fuel(s) fired (or sulf ur containing process materials used

in the SO 2 emitting unit), and the fuel classification of the unit if
combusting more than one type of fuel and using a 40 CFR Part
75 methodology;
vi. Type(s) of emissions controls for SO 2 installed or to be installed,including specifications of whether such controls are precombustion, post-combustion, or integral to the combustion

process; vii. Maximum hourly heat input capacity, or process throughput
capacity, if applicable;
viii. Identification of all units using a common stack; and
viv. Indicator of whether any stack identified in the plan is a bypass

stack.
b. For each unit and parameter required to be monitored, identification of
monitoring methodology information, consisting of monitoring
methodology, monitor locations, s ubstitute data approach for the
methodology, and general identifica tion of quality assurance procedures.
If the proposed methodology is a site-specific methodology submitted
pursuant to Section I1(a)(2)(D) of th is Rule, the description under this
paragraph shall describe fully all aspects of the monitoring equipment,
installation locations, operating char acteristics, certification testing,
ongoing quality assurance and maintena nce procedures, and substitute
data procedures.
c. If the WEB source intends to petition for a change to any specific
monitoring requirement otherwise re quired under this Section, such
petition may be submitted as part of the initial monitoring plan.
d. The Director may issue a notice of approval or disapproval of the initial
monitoring plan based on the compliance of the proposed methodology
with the requirements for monitoring in this Section. Except for any
petition contained in the initial monitoring plan, if such notice is not
issued within 180 days after the date on which the Director received the
initial monitoring plan, the plan shall be deemed approved.
4. Detailed Monitoring Plan. The Account Representative shall submit a detailed
monitoring plan that, except as otherwise sp ecified in an applicable provision in
Appendix A, shall contain the following information:
a. Identification and description of each monitoring component (including
each monitor and its identifiable components, such as analyzer and/or
probe) in a CEMS (e.g., SO 2 pollutant concentration monitor, flow
monitor, moisture monitor), a 40 CFR Part 75, Appendix D monitoring
system (e.g., fuel flowmeter, data acquisition and handling system), or a
protocol in Appendix A, including:i. Manufacturer, model number and serial number;
ii. Component/system identification code assigned by the facility to
each identifiable monitoring component, such as the analyzer
and/or probe;
iii. Designation of the component type and method of sample
acquisition or operation (e.g., in situ pollutant concentration
monitor or thermal flow monitor);
iv. Designation of the system as a primary or backup system;
v. First and last dates the system reported data;
vi. Status of the monitoring component; and

vii. Parameter monitored.
b. Identification and description of all major hardware and software
components of the automated data acquisition and handling system,
including:
i. Hardware components that perfo rm emission calculations or store
data for quarterly re porting purposes (provide the manufacturer
and model number); and
ii. Software components (provide the identification of the provider
and model/version number).
c. Explicit formulas for each measured emissions parameter, using
component/system identification codes for the monitoring system used to
measure the parameter that links the system observations with the
reported concentrations and mass em issions. The formulas must contain
all constants and factors required to derive mass emissions from
component/system code observations and an indication of whether the
formula is being added, corrected, dele ted, or is unchanged. The owner or
operator of a low mass emissions unit for which the owner or operator is
using the optional low mass emissions excepted methodology in section
75.19(c) of 40 CFR Part 75 is not required to report such formulas.
d. Inside cross-sectional area (ft 2 ) at flow monitoring location (for units with
flow monitors, only).
e. If using CEMS for SO 2 and flow, for each parameter monitored: scale,
maximum potential concentration (a nd method of calculation), maximum
expected concentration (if applicable) (and method of calculation),
maximum potential flow rate (and me thod of calculations), span value,
full-scale range, daily calibration units of measure, span effectivedate/hour, span inactivation date/hour , indication of whether dual spans
are required, default high range value, flow rate span, and flow rate span
value and full scale value (in scfh) for each unit or stack using SO 2 or flow component monitors.
f. If the monitoring system or excep ted methodology provides for use of a
constant, assumed, or default value for a parameter under specific
circumstances, then include the follo wing information for each value of
such parameter:
i. Identification of the parameter;
ii. Default, maximum, minimum, or constant value, and units of
measure for the value;
iii. Purpose of the value;
iv. Indicator of use during controlled/uncontrolled hours;
v. Types of fuel;
vi. Source of the value;
vii. Value effective date and hour;
viii. Date and hour value is no longe r effective (if applicable); and
viv. For units using the excepted methodology under section 75.19 of
40 CFR Part 75, the applicable SO 2 emission factor.
g. Unless otherwise specified in section 6.5.2.1 of Appendix A to 40 CFR
Part 75, for each unit or common stack on which hardware CEMS are

installed:
i. The upper and lower boundaries of the range of operation (as
defined in section 6.5.2.1 of Appendix A to 40 CFR Part 75), or
thousand of lb/hr of steam, or ft/sec (as applicable);
ii. The load or operating level(s) designated as normal in section
6.5.2.1 of Appendix A to 40 CFR Part 75, or thousands of lb/hr of
steam, or ft/sec (as applicable);
iii. The two load or operating levels (i.e., low, mid, or high)
identified in section 6.5.2.1 of Appendix A to 40 CFR Part 75 as
the most frequently used;
iv. The date of the data analysis used to determine the normal load
(or operating) level(s) and the two most frequently-used load (or
operating) levels; and

v. Activation and deactivation dates when the normal load or
operating level(s) change and are updated.h. For each unit that is complying with 40 CFR Part 75 for which the
optional fuel flow-to-load test in section 2.1.7 of appendix D to 40 CFR

Part 75 is used:
i. The upper and lower boundaries of the range of operation (as
defined in section 6.5.2.1 of Appendix A to 40 CFR Part 75),
expressed in thousand of lb/hr of steam;
ii. The load level designated as normal, pursuant to section 6.5.2.1
of Appendix A to 40 CFR Part 75, expressed in thousands of lb/hr
of steam; and
iii. The date of the load analysis used to determine the normal load

level.
i. Information related to quality assurance testing, including (as applicable):
identification of the test strategy; protocol for the relative accuracy test
audit; other relevant test informati on; calibration gas levels (percent of
span) for the calibration error test and linearity check; calculations for
determining maximum potential c oncentration, maximum expected
concentration (if applicable), maxi mum potential flow rate, and span;
j. If applicable, apportionment strate gies under sections 75.10 through 75.18

of 40 CFR Part 75.
k. Description of site locations for each monitoring component in a
monitoring system, including schematic diagrams and engineering
drawings and any other documentati on that demonstrates each monitor
location meets the appropriate siting criteria. For units monitored by a
continuous emission monitoring system, diagrams shall include:
i. A schematic diagram identifying entire gas handling system from
unit to stack for all units, using identification numbers for units,
monitor components, and stacks corresponding to the
identification numbers provided in the initial monitoring plan and
paragraphs (d)(1) and (3). The schematic diagram must depict the
height of any monitor locations. Comprehensive and/or separate
schematic diagrams shall be u sed to describe groups of units
using a common stack.
ii. Stack and duct engineering diag rams showing the dimensions and
locations of fans, turning vanes, air preheaters, monitor
components, probes, reference method sampling ports, and other
equipment that affects the monitoring system location,performance, or quality control checks.
l. A data flow diagram denoting the complete information handling path
from output signals of CEMS components to final reports.
5. In addition to supplying the informati on in paragraphs (c) and (d) above, the
owner or operator of an SO 2 emitting unit using either of the methodologies in
paragraph I.1(a)(2)(B) of this Section sh all include the following information in
its monitoring plan for the sp ecific situations described:
a. For each gas-fired or oil-fired SO 2 emitting unit for which the owner or
operator uses the optional protocol in appendix D to 40 CFR Part 75 for

SO 2 mass emissions, the Account Representative shall include the
following information in the monitoring plan:
i. Parameter monitored;
ii. Type of fuel measured, maximum fuel flow rate, units of
measure, and basis of maximum fu el flow rate (i.e., upper range
value or unit maximum) for each fuel flowmeter;

iii. Test method used to check the accuracy of each fuel flowmeter;
iv. Submission status of the data;
v. Monitoring system identification code;
vi. The method used to demonstrate that the unit qualifies for
monthly GCV sampling or for daily or annual fuel sampling for
sulfur content, as applicable;
vii. A schematic diagram identifying the relationship between the
unit, all fuel supply lines, the fuel flowmeter(s), and the stack(s).
The schematic diagram must depict the installation location of
each fuel flowmeter and the fuel sampling location(s).
Comprehensive and/or separate schematic diagrams shall be used
to describe groups of units using a common pipe;
viii. For units using the optional default SO 2 emission rate for
“pipeline natural gas” or “natural gas” in appendix D to 40 CFR
Part 75, the information on the sulfur content of the gaseous fuel
used to demonstrate compliance with either section 2.3.1.4 or
2.3.2.4 of appendix D to 40 CFR Part 75;
ix. For units using the 720 hour test under section 2.3.6 of appendix
D to 40 CFR Part 75 to determine the required sulfur sampling
requirements, report the procedures and results of the test; and
x. For units using the 720 hour test under section 2.3.5 of appendixD to 40 CFR Part 75 to determine the appropriate fuel GCV
sampling frequency, report the procedures used and the results of

the test.

b. For each SO 2 emitting unit for which the owner or operator uses the low
mass emission excepted methodology of section 75.19 to 40 CFR Part 75,
the designated representative shall in clude the following information in
the monitoring plan that accompanies the initial certification application:
i. The results of the analysis performed to qualify as a low mass
emissions unit under section 75.19(c) to 40 CFR Part 75. This
report will include either the previous three years actual or
projected emissions. The following items should be included:
(1) Current calendar year of application;
(2) Type of qualification;
(3) Years one, two, and three;
(4) Annual measured, estimated or projected SO 2 mass emissions for years one, two, and three; and
(5) Annual operating hours for years one, two, and three.
ii. A schematic diagram identifying the relationship between the
unit, all fuel supply lines and tanks, any fuel flowmeter(s), and
the stack(s). Comprehensive and/or separate schematic diagrams
shall be used to describe groups of units using a common pipe;
iii. For units which use the long term fuel flow methodology under
section 75.19(C)(3) to 40 CFR Part 75, a diagram of the fuel flow
to each unit or group of units and a detailed description of the
procedures used to determine the long term fuel flow for a unit or
group of units for each fuel combusted by the unit or group of
units;

iv. A statement that the unit burns only gaseous fuel(s) and/or fuel

oil and a list of the fuels that are burned or a statement that the
unit is projected to burn only gaseous fuel(s) and/or fuel oil and a
list of the fuels that are projected to be burned;

v. A statement that the unit meets the applicability requirements in
sections 75.19(a) and (b) to 40 CFR Part 75 with respect to SO 2 emissions; and
vi. Any unit historical actual, estimated and projected SO 2 emissions

data and calculated SO 2 emissions data demonstrating that theunit qualifies as a low mass emissions unit under sections
75.19(a) and (b) to 40 CFR Part 75.
c. For each gas-fired unit the Acc ount Representative shall include the
following in the monitoring plan: curre nt calendar year, fuel usage data
as specified in the definition of gas -fired in section 72.2 of 40 CFR Part
72, and an indication of whether the data are actual or projected data.
6. An operating permit for a WEB source i ssued in accordance with Title V of the
Clean Air Act shall require a source to maintain a detailed monitoring
plan in accordance with this Part, but the specific elements of the plan
shall not be part of the permit, and modifications to the elements of the
plan shall not require a permit modification.

C. Certification/Recertification.
1. All monitoring systems are subject to initial certification and recertification
testing as specified in 40 CFR Part 75 or Appendix A to this Rule, as applicable.
Certification or recertification of a monitoring system by the U.S. Environmental
Protection Agency for a WEB source that is subject to 40 CFR Part 75 under a
requirement separate from this Rule sh all constitute certification under the WEB
Trading Program.
2. The owner or operator of an SO 2 emitting unit not otherwise subject to 40 CFR

Part 75 that monitors SO 2 mass emissions in accordance with 40 CFR Part 75 to
satisfy the requirements of this Section sh all perform all of the tests required by
that regulation and shall submit the following:
a. A test notice, not later than 21 days before the certification testing of the
monitoring system, provided that the Director may establish additional
requirements for adjusting test dates after this notice as part of the
approval of the initial monitoring plan under paragraph I2(C) of this Rule;

and
b. An initial certification applicati on within 45 days after testing is
complete. A monitoring system will be considered provisionally certified
while the application is pending, and th e system shall be deemed certified
if the Director does not approve or disapprove the system within six

months after the date on which the application is submitted.

D. Ongoing Quality Assurance and Quality Control.1. The WEB source shall satisfy the app licable quality assuran ce and quality control
requirements of Part 75 or, if the WEB source is subject to a WEB protocol in
Appendix A, the applicable quality assura nce and quality control requirements in
Appendix A on and after the date that certification testing commences.

E. Substitute Data Procedures.
1. For any period after certification testing is complete in which valid data are not
being recorded by a monitoring system sp ecified in this Rule, missing or invalid
data shall be replaced with substitute da ta in accordance with 40 CFR Part 75 or,
if the WEB source is subject to a WEB protocol in Appendix A of this rule, with
substitute data in accordance with Appendix A of this rule.

2. For an SO 2 emitting unit that does not have a certified (or provisionally certified)
monitoring system in place as of the beginning of the first control period for
which the unit is subject to the WEB Trading Program, the owner or operator

shall:
a. If the owner or operator will use a CEMS to comply with this Section,
substitute the maximum potential concentration of SO 2 for the unit and
the maximum potential flow rate, as determined in accordance with 40
CFR Part 75. The procedures for conditional data validation under
section 75.20(b)(3) may be used for any monitoring system under this
Rule that uses these 40 CFR Part 75 procedures, as applicable;
b. If the owner or operator will use the 40 CFR Part 75 Appendix D
methodology, substitute the maximum pot ential sulfur content, density or
gross calorific value for the fuel and the maximum potential fuel flow
rate, in accordance with section 2.4 of Appendix D to 40 CFR Part 75;
c. If the owner or operator will use the 40 CFR Part 75 LME methodology,

substitute the SO 2 emission factor required for the unit as specified in 40
CFR 75.19 and the maximum rated hourly heat input, as defined in 40
CFR 72.2; or
d. If using a protocol in Appendix A to this Rule, follow the procedures in
the applicable protocol.

F. Compliance Dates.
1. The initial monitoring plan sha ll be submitted by the following dates:
a. For each source that is a WEB source on or before the Program Trigger
Date, the monitoring plan shall be submitted 180 days after such Program
Trigger Date.
b. For any existing source that beco mes a WEB source after the ProgramTrigger Date, the monitoring plan sh all be submitted by September 30 of
the year following the inventory year in which the source exceeded the

emissions threshold.
c. For any new WEB source, the monitoring plan shall be included with the
permit application for New Source Review. [State shall modify the
language as necessary to conform with state’s new source review rules.]
2. Emission monitoring systems shall be in stalled, operational and shall have met all
of the certification testing requirements of this Section I (including any referenced
in Appendix A) by the following dates:
a. For each source that is a WEB source on or before the Program Trigger
Date, two years prior to the start of the first control period as described in

Section L of this Rule.
b. For any existing source that beco mes a WEB source after the Program
Trigger Date, one year after the due date for the monitoring plan under
I1(C)(2) of this Rule.
c. For any new WEB source, the earlier of 90 unit operating days or 180
calendar days after the date the new source commences operation.

G. Recordkeeping.
1. Except as provided in Section I7(b), the WEB source shall keep copies of all
reports, registration materials, compliance certifications, sulfur dioxide emissions
data, quality assurance data, and other submis sions under this Rule for a period of
five years. Unless otherwise requested by the WEB source and approved by the
Director, the copies shall be kept on site.
2. The WEB source shall keep all Account Ce rtificates of Representation on site at
the source through the year 2018.
3. The WEB source shall keep records of all operating hours, quality assurance
activities, fuel sampling measurements, hourly averages for SO 2 , stack flow, fuel
flow, or other continuous measurements, as applicable, and any other applicable
data elements specified in this Section or in Appendix A to this Rule. The WEB
source shall maintain the applicable reco rds specified in 40 CFR Part 75 for any

SO 2 emitting unit that uses a Part 75 monitoring method to meet the requirements

of this Section.

H. Reporting.
1. Quarterly Reports. For each SO 2 emitting unit, the Account Representative shall
submit a quarterly report within thirty days after the end of each calendar quarter.
The report shall be in a format specified by the Director and shall be submitted ina manner compatible with the emissions tracking database designed for the WEB
Trading Program. the Director may require the WEB source to submit hourly and
quality assurance activity information comparable to quarterly reports under 40
CFR Part 75. If the owner or operator submits a quarterly report under 40 CFR
Part 75 to the U.S. EPA Administrator, no additional report under this paragraph
(a) shall be required, provided, however, th at the Director may require that a copy
of that report (or a separate statement of quarterly and cumulative annual SO 2 mass emissions) be submitted separately to the Director.
2. Annual Report. Based on the quarterly reports, each WEB source shall submit an

annual statement of total annual SO 2 emissions for all SO 2 emitting units at the
source. The annual report shall contain f our elements: total emissions for all

units monitored in accordance with Section I1(a) of this Rule; total emissions for

all units with emissions estimated in accor dance with Section I1(b) of this Rule;
the number of tons, if any, of SO 2 emissions estimated under Section I1(b) of this
Rule that are subject to deduction of allowances from the source’s compliance
account in accordance with Section I1(b)(6); and the total number of SO 2 tons subject to deduction of allowances from the source’s compliance account in

accordance with Section 1621 of this Rule . The annual report shall be submitted
within 30 days after the end of a control period.
3. The Director may direct that any monitoring plan, report,
certification/recertification, or emissions data required to be submitted under this
Section be submitted to the Tracking System Administrator.
4. The Director may review and reject any report submitted under this Section I7
that contains errors or fails to satisfy the requirements of this Section, and the
Account Representative shall resubmit the report to correct any deficiencies.
5. Petitions. A WEB source may petition for an alternative to any requirement
specified in Section I1(a)(2). The petition shall require approval of the Director

and the U.S. EPA Administrator. An y petition submitted under this paragraph

shall include sufficient information for the evaluation of the petition, including, at
a minimum, the following information:
a. Identification of the WEB source and applicable SO 2 emitting unit(s);
b. A detailed explanation of why the pr oposed alternative is being suggested
in lieu of the requirement;
c. A description and diagram of any e quipment and procedures used in the
proposed alternative, if applicable;
d. A demonstration that the proposed alternative is consistent with thepurposes of the requirement for which the alternative is proposed and is
consistent with the purposes of this Ru le and that any adverse effect of
approving such alternative will be de minimis ; and
e. Any other relevant information that the Director may require.
6. For any monitoring plans, reports, or other information submitted under Section
1618 of this Rule, the Account Representativ e shall ensure that, where applicable,
identifying information is consistent with the identifying information provided in
the most recent certificate of representation for the WEB source submitted under

Section 1614 of this Rule.

R18-2-1619. Allowance Transfers

A. Procedure.
1. To transfer allowances, the Account Representative shall submit the following
information to the Tracking System Administrator:
a. The transfer account number(s) identifying the transferor account;
b. The transfer account number(s) identifying the transferee account;
c. The serial number of each allowance to be transferred; and
d. The transferor’s Account Represen tative’s name and signature and date of

submission.

B. Deadline.
1. The allowance transfer deadline is midnight Pacific Standard Time March 1 of
each year (or if this date is not a business day, midnight of the first business day
thereafter) following the end of the control period. By this time, the transfer of the
allowances into the WEB source’s compliance account must be correctly
submitted to the Tracking System Administrator in order to demonstrate
compliance under Section 1621(A) of this Rule for that control period.

C. Retirement of Allowances.
1. To transfer allowances for the pur pose of retirement, the Account Representative
shall submit the following information to the Tracking System Administrator:
a. The transfer account number(s) identifying the transferor account;
b. The serial number of each allowance to be retired; and
c. The transferor’s Account Represen tative’s name and signature and date of
submission accompanied by a signed statement acknowledging that each
retired allowance as no longer available for future transfers from or to any

account.R.18-2-1620. Use of Allowances from a Previous Year

A. Any allowance that is held in a compliance account or general account will remain in such

an account unless and until the allowance is de ducted in conjunction with the compliance
process, or transferred to another account.

B. In order to demonstrate compliance under Section 1621(A) of this Rule for a control
period, WEB sources shall only use allowances allocated for that current control period or
any previous year.

C. If flow control procedures for the current cont rol period have been triggered, then the use

of allowances that were allocated for a ny previous year will be limited as follows:
1. The number of allowances that are held in each compliance account and general

account as of the allowance transfer dead line for the immediately previous year
and that were allocated for any previous year will be determined.
2. The number determined in (1) will be multiplied by the flow control ratio to

determine the number of allowances that we re allocated for a previous year that
can be used without restriction for the current control period.

3. Allowances that were allocated for a previous year in excess of the number
determined in (2) may also be used for the current control period. If such
allowances are used to make a deduction, two allowances must be deducted for
each deduction of one allowance require d under Section 1621 of this Rule.

D. Special provisions for the year 2018. After compliance with the 2017 allowance limitation

has been determined in accordance with S ection 1621(A) of this Rule, allowances
allocated for any year prior to 2018 shall not be used for determining compliance with the
2018 allowance limitation or any future allowance limitation.

R18-2-1621. Compliance

A. Compliance with Allowance Limitations.
1. The WEB source must hold allowances, in accordance with Section 1620 and
Section 1621(A)(2) of this Rule, as of the allowance transfer deadline in the WEB
source’s compliance account (together with any current control year allowances
held for the WEB source by the Director under Section 1618(A)(2) of this Rule)

in an amount not less than the total SO 2 emissions for the control period from the
WEB source, as determined under the m onitoring and reporting requirements of

Section 1618 of this Rule.
a. For each source that is a WEB source on or before the Program Trigger
Date, the first control period is the calendar year that is six years
following the calendar year for which SO 2 emissions exceeded themilestone.
b. For any existing source that becomes a WEB source after the Program
Trigger Date, the first control period is the calendar year that is four years
following the inventory year in which the source exceeded the SO 2
emissions threshold.
c. For any new WEB source after the Program Trigger Date the first control
period is the first full calendar year that the source is in operation.
d. If the WEB Trading Program is triggered in accordance with the 2013
review, the first control period for each source that is a WEB source on or
before the Program Trigger Date is the year 2018.

2. Allowance transfer deadline. An allowance may only be deducted from the WEB
source’s compliance account if:

a. The allowance was allocated for the current control period or meets the
requirements in Section 1620 of this Rule for use of allowances from a
previous control period, and

b. The allowance was held in th e WEB source’s compliance account as of
the allowance transfer deadline for the current control period, or was
transferred into the compliance account by an allowance transfer correctly
submitted for recording by the allowanc e transfer deadline for the current
control period.
3. Compliance with allowance limitations shall be determined by comparing the
following two numbers:

a. The monitored SO 2 emissions data reported by the source to the Director,

in accordance with Section 1618 of this Rule, and recorded in the
emissions tracking database and

b. The allowance allocations and transfers recorded in the Allowance
Tracking System, adjusted in accordance with Section 1620 of this Rule.

4. To the extent consistent with Sec tion 1620 of this Rule, allowances shall be
deducted for a WEB source for compliance with the allowance limitation as
directed by the WEB source’s Account Representative. Deduction of any other
allowances as necessary for compliance with the allowance limitation shall be on
a first-in, first-out accounting basis in the order of the date and time of their
recording in the WEB source’s compliance account, beginning with the

allowances allocated to the WEB source and continuing with the allowances
transferred to the WEB source’s comp liance account from another compliance
account or general account. The allowances held by the Director for compliance ata WEB source pursuant to Section 1618(A)(2 ) of this Rule shall be deducted as
specified in that Section.

B. Certification of Compliance.
1. For each control period in which a WEB source is subject to the allowance
limitation, the Account Representative of the source shall submit to the Director a
Compliance Certification report for the source.
2. The Compliance Certification repor t shall be submitted no later than the
allowance transfer deadline of each control period, and shall contain the
following:
a. Identification of each WEB source;
b. At the Account Representative’ s option, the serial numbers of the
allowances that are to be deducted from a source’s compliance account
for compliance with the allowance limitation; and
c. The Compliance Certification re port according to subpart 3 of this

section.
3. In the Compliance Certification repor t, the Account Representative shall certify,
based on reasonable inquiry of those pe rsons with primary responsibility for
operating the WEB source in compliance with the WEB Trading Program,
whether the WEB source for which the compliance certification is submitted was
operated during the control period covered by the report in compliance with the
requirements of the WEB Trading Program applicable to the source including:
a. Whether the WEB source operated in compliance with the SO 2 allowance
limitation;

b. Whether SO 2 emissions data has been submitted to [states or tribe] in
accordance with Section 1618(A) of this Rule and other applicable
guidance, for review, revision as necessary, and finalization for
forwarding to the SO 2 Allowance Tracking System for recording;
c. Whether the monitoring plan that governs the WEB source has been
maintained to reflect the actual ope ration and monitoring of the source,
and contains all information necessary to attribute SO 2 emissions to the
source, in accordance with Section 1618(A) of this Rule;

d. Whether all the SO 2 emissions from the WEB source if applicable, were
monitored or accounted for either through the applicable monitoring or
through application of the appropr iate missing data procedures;
e. If applicable, whether any SO 2 emitting unit for which the WEB source is
not required to monitor in accordance with Section 1618(A)(1)(c) of thisrule remained permanently retired and had no emissions for the entire
applicable period; and
f. Whether there were any changes in the method of operating or monitoring
the WEB source that required monitor recertification. If there were any
such changes, the report must specify the nature, reason, and date of the
change, the method to determine comp liance status subsequent to the
change, and specifically, the method to determine SO 2 emissions.
C. Penalties for any WEB source ex ceeding its allowance limitations.
1. Allowance deduction penalties.

a. If emissions from a WEB source exceed the allowance limitation for a
control period, as determined in accord ance with Section 1621(A) of this
Rule, the source’s allowances held in its compliance account will be
reduced by an amount equal to two times the source’s tons of excess

emissions.
b. If the compliance account does not have sufficient allowances allocated
for that control period, the requi red number of allowances will be
deducted from the WEB source’s compliance account regardless of the
control period for which they we re allocated, once allowances are

recorded in the account.
c. Any allowance deduction required under this Section shall not affect the
liability of the owners and operators of the WEB source for any fine,
penalty or assessment or their oblig ation to comply with any other
remedy, for the same violation, as ordered under the Clean Air Act,
implementing regulations or applicable state or tribal law.. 2. A financial penalty of $5,000 per ton of SO 2 emissions in excess of the WEB

source’s allowance limitation shall be levied.
3. WEB Source liability for non-compliance
a. Separate and regardless of any au tomatic penalties assessed for allowance
deduction penalty and fina ncial penalty, a WEB source that violates any
requirement of this Rule, including monitoring record keeping and
reporting requirements, is subject to civil and criminal penalties under the
Director law and the Clean Air Act. Each day of the control period is a
separate violation, and each ton of SO 2 emissions in excess of a source’s
allowance limitation is a separate violation.

R18-2-1622. Special Penalty Provisions for the 2018 MilestoneA. If the WEB Trading Program is triggered and the first control period will not occur until
after the year 2018, the following provisions shall apply for the 2018 emissions year.
1. All WEB sources shall register, a nd open a compliance account within 180 days
after the Program Trigger Date, in accordance with Sections 1615(A)and 1617 of

this Rule.
2. The Tracking System Administra tor will record the allowances for the 2018
control period for each WEB source in the source’s compliance account once the

Director allocates the 2018 allowances.
3. The allowance transfer deadline is midnight Pacific Standard Time on May 30,
2021. WEB sources may transfer allowa nces as provided in Section 1619(A) of

this Rule until the a llowance transfer deadline.

4. A WEB source must hold allowa nces allocated for 20 18 including those
transferred into the compliance account by an allowance transfer correctly
submitted by the allowance transfer dead line, in an amount not less than the WEB

source’s total SO 2 emissions for 2018. Emissions are determined using the pre
trigger monitoring provisions in Section 1611 of this rule.
5. An allowance deduction penalty and fi nancial penalty shall be assessed and levied
in accordance with Sections 1620(D) , 1621(A)(4) and 1621(C) of this Rule,
except that SO 2 emissions shall be determined under Section 1622(A)(4) of this

Rule.

B. If the program has been triggered and provision 1622(A) is implemented, the provisions of
1622(C) of this Rule shall apply for each year after the 2018 emission year until:
1. The first control period under the WEB trading program; or

2. The Director determined that the 2018 SO2 milestone has been met.

C. If provision in Section 1622(A) has been im plemented, the following shall apply to each
emissions year after the 2018 emissions year:
1. The Tracking System Administrator will record the allowances for the control
period for the specific year for each WEB source in the source’s compliance

account once the Director allocates the allowances.

2. The allowance transfer deadline is midnight Pacific Standard Time on March 1 of
each year (or if this date is not a business day, midnight of the first business day
thereafter) following the end of the specific emissions year. WEB sources may
transfer allowances as provided in Section 1619(A) of this Rule until the

allowance transfer deadline.
3. A WEB source must hold allowances allocated for that specific emissions year, or
any year after 2018, including those transferred into the compliance account by anallowance transfer correctly submitted by th e allowance transfer deadline, in an

amount not less than the WEB source’s total SO 2 emissions for the specific
emissions year. Emissions are determin ed using the pre-trigger monitoring
provisions in Section 1611 of this rule.
4. An allowance deduction pe nalty and financial penalty shall be assessed and levied
in accordance with Sections 1620(D), 1621(A)(4) and 1621(C) of this Rule,
except that SO 2 emissions shall be determined under Section 1622(C)(3) of this

Rule.

NOTE: Appendix A follows.**APPENDIX A: WEB MODEL RULE MONITORING PROTOCOLS**

**Protocol WEB-1: SO 2**  **Monitoring of Fuel Gas Combustion Devices**

1. Applicability

(a) The provisions of this protocol are applicable to fuel gas combustion devices at petroleum refineries.

(b) Fuel gas combustion devices include boilers, process heaters, and flares used to burn fuel gas generated at a petroleum refinery.

(c) Fuel gas means any gas which is generated and combusted at a petroleum refinery. Fuel gas does not include (1) natural gas, unless combined with other gases generated at a petroleum refinery, (2) gases generated by a catalytic cracking unit catalyst regenerator, (3) gases generated by fluid coking burners, (4) gases combusted to produce sulfur or sulfuric acid, or (5) process upset gases generated due to startup, shutdown, or malfunctions.

2. Monitoring Requirements

(a) Except as provided in paragraphs (b) and (c) of this Section 2, fuel gas combustion devices shall use a continuous fuel gas monitoring system (CFGMS) to determine the total sulfur content (reported as H 2 S) of the fuel gas mixture prior to combustion, and continuous fuel flow meters to determine the amount of fuel gas burned.

(1) Fuel gas combustion devices having a common source of fuel gas may be monitored for sulfur content at one location, if monitoring at that location is representative of the sulfur content of the fuel gas being burned in any fuel gas combustion device.

(2) The CFGMS shall meet the performance requirements in Performance Specification 2 in Appendix B to 40 CFR Part 60, and the following:

(i) Continuously monitor and record the concentration by volume of total sulfur compounds in the gaseous fuel reported as ppmv

H 2 S.

(ii) Have the span value set so that the majority of readings fall between 10 and 95% of the range.

(iii) Record negative values of zero drift. (iv) Calibration drift shall be # 5.0% of the span, for initial certification and daily calibration error tests.

(v) Methods 15A, 16, or approved alternatives for total sulfur, are the reference methods for therelative accuracy test. The relative accuracy test shall include a bias test in accordance with paragraph 4.(c) of this section.

(3) All continuous fuel flow meters shall comply with the provisions of section 2.1.5 of Appendix D to 40 CFR
Part 75.

(4) The hourly mass SO 2 emissions rate for all the fuel gas combustion devices monitored by this approach shall be calculated using the following equation:

E t = ( C S )( Q t )( K )

where: E t = Total SO 2 emissions in lb/hr from applicable fuel gas combustion devices
C S = Sulfur content of the fuel gas as H 2 S(ppmv) Q t = Fuel gas flow rate to the applicable fuel gas combustion devices (scf/hr)

K

= 1.660 x 10 -7 (lb/scf)/ppmv

(b) In place of a CFGMS in paragraph (a) of this Section 2, fuel gas combustion devices having a common source of fuel gas may be monitored with an SO 2 CEMS, a flow CEMS, and (if necessary) a moisture monitoring system at only one location, if the CEMS monitoring at that location is representative of the SO 2 emission rate (lb SO 2 /scf fuel gas burned) of all applicable fuel gas combustion devices. Continuous fuel flow meters shall be used in accordance with paragraph (a), and the fuel gas combustion device monitored by a CEMS shall have separate fuel metering.

(1) Each CEMS for SO 2 , flow, and (if applicable) moisture, shall comply with the operating requirements, performance specifications, and quality assurance requirements of 40 CFR Part 75.

(2) All continuous fuel flow meters shall comply with the provisions of section 2.1.5 of Appendix D to 40 CFR
Part 75.

(3) The SO 2 hourly mass emissions rate for all the fuel gas combustion devices monitored by this approach shall be determined by the ratio of the amount of fuel gas burned by the CEMS-monitored fuel gas combustion device to the total fuel gas burned by all applicable fuel gas combustion devices using the following equation:
E t = (E m ) ( Q t )/( Q m )

where: E t = Total SO 2 emissions in lb/hr from applicable fuel gas combustion devices

E

m = SO 2 emissions in lb/hr from the CEMSmonitored fuel gas combustion device, calculated using Equation F-1 or (if applicable) F-2 in Appendix F to 40 CFR Part 75 Q t = Fuel gas flow rate (scf/hr) to the applicable fuel gas combustion devices Q m = Fuel gas flow rate (scf/hr) to the CEMSmonitored fuel gas combustion device(c) In place of a CFGMS in paragraph (a) of this section, fuel gas combustion devices having a common source of fuel gas may be monitored with an SO 2 - diluent CEMS at only one location, if the CEMS monitoring at that location is representative of the SO 2 emission rate (lb SO 2 /mmBtu) of all applicable fuel gas combustion devices. If this option is selected, the owner or operator shall conduct fuel gas sampling and analysis for gross calorific value (GCV), and shall use continuous fuel flow metering in accordance with paragraph (a) of this Section 2, with separate fuel metering for the CEMS-monitored fuel gas combustion device.

(1) Each SO 2 -diluent CEMS shall comply with the applicable provisions for SO 2 monitors and diluent monitors in 40 CFR Part 75, and shall use the procedures in section 3 of Appendix F to Part 75 for determining SO 2 emission rate (lb/mmBtu) by substituting the term SO 2 for NO x in that section, and using a K factor of 1.660 x 10 -7 (lb/scf)/ppmv instead of the NO
x K factor.

(2) All continuous fuel flow meters and fuel gas sampling and analysis for GCV to determine the heat input rate from the fuel gas shall comply with the applicable provisions in sections 2.1.5 and 2.3.4 of Appendix D to 40 CFR Part 75.

(3) The SO 2 hourly mass emissions rate for all the fuel gas combustion devices monitored by this approach shall be calculated by using the following equation:

E t = (E m ) ( Q t ) (GCV) /10 6

where:

E t = Total hourly SO 2 mass emissions in lb/hr from the applicable fuel gas combustion devices

E

m = SO 2 emission rate in lb/mmBtu from the CEMS - monitored fuel gas combustion device Q t = Fuel gas flow rate (scf/hr) to the applicable fuel gas combustion devices
GCV = Fuel Gross Calorific Value (Btu/scf)
10 6 = Conversion from Btu to million Btu

(d) Calculate total SO 2 mass emissions for each calendar quarter and each calendar year based on the emissions in lb/hr and Equations F-3 and F-4 in Appendix F to 40 CFR Part 75, Appendix F.

3. Certification/Recertification Requirements

All monitoring systems are subject to initial certification and recertification testing as follows:

(a) The owner or operator shall comply with the initial testing and calibration requirements in Performance Specification 2 in Appendix B to 40 CFR Part 60 and paragraph 2 (a)(2) of this section for each CFGMS.

(b) Each CEMS for SO 2 and flow or each SO 2 -diluent CEMS shall comply with the testing and calibration requirements specified in 40 CFR Part 75, section 75.20 and Appendices Aand B, except that each SO 2 -diluent CEMS shall meet the relative accuracy requirements for a NO
x -diluent CEMS (lb/mmBtu).

(c) A continuous fuel flow meter shall comply with the certification and quality-assurance requirements in sections 2.1.5 and 2.1.6 to Appendix D to 40 CFR Part 75.

4. Quality Assurance/Quality Control Requirements

(a) A quality assurance/quality control (QA/QC) plan shall be developed and implemented for each CEMS for SO 2 and flow or the SO 2 - diluent CEMS in compliance with sections 1, 1.1, and 1.2 of Appendix B to Part 75.

(b) A QA/QC plan shall be developed and implemented for each continuous fuel flow meter and fuel sampling and analysis in compliance with sections 1, 1.1, and 1.3 of Appendix B to 40
CFR Part 75.

(c) A QA/QC plan shall be developed and implemented for each CFGMS in compliance with sections 1 and 1.1 of Appendix B to 40 CFR Part 75, and the following:

(i) Perform a daily calibration error test of each CFGMS at two gas concentrations, one low level and one high level. Calculate the calibration error as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the error is greater than 5.0% of the span value.

(ii) In addition to the daily calibration error test, an additional calibration error test shall be performed whenever a daily calibration error test is failed, whenever a monitoring system is returned to service following repairs or corrective actions that may affect the monitor measurements, or after making manual calibration adjustments.

(iii) Perform a linearity test once every operating quarter. Calculate the linearity as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the linearity error is greater than 5.0 percent of a reference value, and the absolute value of the difference between average monitor response values and a reference value is greater than 5.0 ppm.

(iv) Perform a relative accuracy test audit once every four operating quarters. Calculate the relative accuracy as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the relative accuracy is greater than 20.0% of the mean value of the reference method measurements.

(v) Using the results of the relative accuracy test audit, conduct a bias test in accordance with Appendix A to 40 CFR Part 75, and calculate and apply a bias adjustment factor if required.5. Missing Data Procedures

(a) For any period in which valid data are not being recorded by
an SO 2 CEMS or flow CEMS specified in this section, missing or invalid data shall be replaced with substitute data in accordance with the requirements in Subpart D of 40 CFR Part
75.

(b) For any period in which valid data are not being recorded by
an SO 2 -diluent CEMS specified in this section, missing or invalid data shall be replaced with substitute data on a rate basis (lb/mmBtu) in accordance with the requirements for SO 2 monitors in Subpart D of 40 CFR Part 75.

(c) For any period in which valid data are not being recorded by a continuous fuel flow meter or for fuel gas GCV sampling and analysis specified in this section, missing or invalid data shall be replaced with substitute data in accordance with missing data requirements in Appendix D to 40 CFR Part
75.

(d) For any period in which valid data are not being recorded by the CFGMS specified in this section, hourly missing or invalid data shall be replaced with substitute data in accordance with the missing data requirements for units performing hourly gaseous fuel sulfur sampling in section 2.4 of Appendix D to 40 CFR Part 75. 6. Monitoring Plan and Reporting Requirements

In addition to the general monitoring plan and reporting requirements of Section I of this Rule, the owner or operator shall meet the following additional requirements:

(a) The monitoring plan shall identify each group of units that are monitored by a single monitoring system under this Protocol WEB-1, and the plan shall designate an identifier for the group of units for emissions reporting purposes. For purpose of submitting emissions reports, no apportionment of emissions to the individual units within the group is required.

(b) If the provisions of paragraphs 2.(b) or (c) are used, provide documentation and an explanation to demonstrate that the SO 2 emission rate from the monitored unit is representative of the rate from non-monitored units.**Protocol WEB-2: Predictive Flow Monitoring Systems for Kilns with Positive Pressure Fabric Filter** 

1. Applicability

The provisions of this protocol are applicable to cement kilns or lime kilns that (1) are controlled by a positive pressure fabric filter, (2) combust only a single fuel, no fuel blends, and (3) have operating conditions upstream of the fabric filter that the WEB source documents would reasonably prevent reliable flow monitor measurements. This protocol does not modify the SO 2 monitoring requirements in section I of this Rule.

2. Monitoring Requirements

(a) A cement or lime kiln with a positive pressure fabric filter shall use a predictive flow monitoring system (PFMS) to determine the hourly kiln exhaust gas flow.

(b) A PFMS is the total equipment necessary for the determination of exhaust gas flow using process or control device operating parameter measurements and a conversion equation, a graph, or computer program to produce results in cubic feet per hour.

(c) The PFMS shall meet the following performance specifications:

(1) Sensors readings and conversion of sensor data to flow in cubic feet per hour must be automated.

(2) The PFMS must allow for the automatic or manual determination of failed monitors. At a minimum a daily determination must be performed.

(3) The PFMS shall have provisions to check the calibration error of each parameter that is individually measured. The owner or operator shall propose appropriate performance specifications in the initial monitoring plan for all parameters used in the PFMS comparable to the degree of accuracy required for other monitoring systems used to comply with this Rule. The parameters shall be tested at two levels, low: 0 to 20% of full scale, and high: 50 to 100% of full scale. The reference value need not be certified.

(4) The relative accuracy of the PFMS must be < 10.0% of the reference method average value, and include a bias test in accordance with paragraph 4(c) of this section.

3. Certification Requirements

The PFMS is subject to initial certification testing as follows: (a) Demonstrate the ability of the PFMS to identify automatically or manually a failed monitor.

(b) Provide evidence of calibration testing of all monitoring equipment. Any tests conducted within the previous 12 months of operation that are consistent with the QA/QC plan for the PFMS are acceptable for initial certification purposes.

(c) Perform an initial relative accuracy test over the normal range of operating conditions of the kiln. Using the results ofthe relative accuracy test audit, conduct a bias test in accordance with Appendix A to 40 CFR Part 75, and calculate and apply a bias adjustment factor if required.

4. Quality Assurance/Quality Control Requirements

A QA/QC plan shall be developed and implemented for each PFMS in compliance with sections 1 and 1.1 of Appendix B of 40 CFR Part 75, and the following:

(a) Perform a daily monitor failure check.

(b) Perform calibration tests of all monitors for each parameter included in the PFMS. At a minimum, calibrations shall be conducted prior to each relative accuracy test audit.

(c) Perform a relative accuracy test audit and accompanying bias test once every four operating quarters. Calculate the relative accuracy (and bias adjustment factor) as described in Appendix A to 40 CFR Part 75. An out of control period occurs whenever the flow relative accuracy is greater than 10.0% of the mean value of the reference method.

5. Missing Data

For any period in which valid data are not being recorded by the PFMS specified in this section, hourly missing or invalid data shall be replaced with substitute data in accordance with the flow monitor missing data requirements for non-load based units in Subpart D of 40 CFR Part 75.

6. Monitoring Plan Requirements

In addition to the general monitoring plan requirements of Section I of this Rule, the owner or operator shall meet the following additional requirements:

(a) The monitoring plan shall document the reasons why stack flow measurements upstream of the fabric filter are unlikely to provide reliable flow measurements over time.

(b) The initial monitoring plan shall explain the relationship of the proposed parameters and stack flow, and discuss other parameters considered and the reasons for not using those parameters in the PFMS. The [state or tribe] may require that the subsequent monitoring plan include additional explanation and documentation for the reasonableness of the proposed PFMS.NPRM WEB Trading Program, 11/10/03 47Appendix A-7 – Stationary Sources Arizona Regional Haze SIP 

## Appendix A-7b. Proposed WRAP 309 Coordinating Committee Charter

### WRAP Board of Directors

Proposal to form a standing 309 Coordinating Committee October 15, 2003

Background:

Section 309 of the Regional Haze Rule provides that the 9 western “transport region” states and Indian tribes within thos e states may opt to develop regional haze SIPs following the recommendati ons of the Grand Canyon Visibility Transport Commission (GCVTC). If impl emented, the GCTVC recommendations satisfy the requisite showing of “Reas onable Progress” toward meeting the national visibility goal. Tr ansport states electing to submit 309 SIPs must incorporate the GCVTC recommendations, and submit their initial SIPs by December 31, 2003. Eligible tribes are not subject to this deadline and may submit 309 TIPs at later dates. Over the last several years the WRAP has performed most of the technical analyse s and policy recommendations to support the states on a regional scale.

Five transport region states have declared their intent to submit 309 SIPs. These states are AZ, NM, OR, UT, and WY. To date, no tribe has announced its intention to submit a 309 TIP.

As these 309 states have moved through their individual planning processes following the work of the WRAP, it is clear they would benefit greatly through continuing the cooperative relationship s already established under the WRAP. Likewise, tribes that choose 309 would also benefit greatly from this ongoing collaboration. This would better enable eac h participant to take advantage of the work done by the other participants on t heir initial submittals, with higher assurance that the SIPs and TIPs would meet all requirement s of the Regional Haze Rule and the Annex. Over the longer term, a coordinated approach provides a forum to facilitate ongoi ng communications among the participants, and a mechanism to meet particular im plementation requirements, such as milestone tracking, monitoring information and data exchange.

Proposal:

The 309 states propose that the WR AP board create a standing committee, called the “309 Coordinating Committ ee.” This committee would be formed according to the WRAP Bylaws, II. E., wh ich allows the formation of additional standing committees (see attachment). The committee would be organized as follows:

### Membership –

One designated representativ e from each state and trib e that submits a plan under §309 (in the case of tribes, a dec laration of intent to move ahead with submission of a plan would warrant member ship). Additional state and tribal staff may participate in meetings of the co mmittee, as appropriate. The WRAP will appoint Co-Chairs from the membership.

Additional members –

If issues arise which require participation of federal agencies or stakeholders, the committee at its discretion will ext end membership to such federal representatives and stakeholders as appr opriate. The WRAP will make these appointments for limited durat ion as long as the issue requiring federal or stakeholder membership is active.

Charge of the Committee –

To provide an ongoing forum for 309 st ates and tribes to facilitate communications and information exchange.

To provide a mechanism to achieve cons istency in implementing requirements of §309 of the regional haze rule, including but not limited to implementation of: the emissions tracking system to evaluate st ationary source compliance with the SO 2 

### milestones; the backstop market-trading pr ogram for stationary sources, if required; and emission tracking in cl ean air corridors, for fire and enhanced smoke management programs, and for mobile and area sources.

The committee will also make recommendat ions to the WRAP Board, as needed, toward improving implementation of programs contained in SIPs and TIPs adopted under §309, and evaluate the va lue and appropriateness of WRAP involvement in resolving disagreements between states or bet ween states and tribes on 309 matters.ATTACHMENT

(From WRAP bylaws, revised 7/23/02)

...

I. GENERAL GUIDELINES FOR STANDING COMMITTEES REPORTING DIRECTLY TO THE WRAP.

A. All meetings shall be open to the public, and should include an opportunity for those members of the public who are observing the meeting to comment on or provide suggestions relevant to the committee's work.

B. Whenever processes are directed to be stakeholder based, membership should represent a wide range of social, cultural, economic, geographic, relative population and technical viewpoints. To meet this goal, the following categories of representatives should be considered.

* Industry (focused on production sector but excluding the mobile source sector)

* Small business (focused on the service sector, including "green industry")

* Mobile sources (including vehi cle manufacturers and transportation planners)

* Federal government

* Tribal government

* State government

* Local government

* Academia

* Environmental groups

* General public

In all cases it may not be possible or appropriate to include each of the categories in stakeholder processes. However, whenever a category is not included, an explanation for the exclusion should be recorded.

In selecting members for committees, both technical expertise and diversity of viewpoints must be considered in balancing committee membership to provide equity. Itis not expected that each member of a committee be a technical expert in all aspects of the committee's work but rather, that all can contribute to the committee's overall goals.

II. TECHNICAL OVERSIGHT COMMITTEE (TOC), INITIATIVES OVERSIGHT COMMITTEE (IOC), AND OTHER COMMITTEES

...

E. Other Committees

1. The WRAP may establish other standing committees, forums or work groups. Membership on such standing committees, forums, or work groups shall consist of state and tribal representatives from the applicable region.

2. The committee shall extend membership to other regional stakeholders as appropriate. Members will be selected by the WRAP from letters of interest. Duration of the appointment shall coincide with the duration of the air quality issue.

3. The WRAP will appoint co-chairs of any standing committees. The cochairs of any standing committees established will be members of the Coordinating Group.Appendix A-7 – Stationary Sources Arizona Regional Haze SIP 

## Appendix A-7c. WRAP Report on Assessment of NOx/PM Strategies

# Stationary Source NOx and PM Emissions in the WRAP Region:

An Initial Assessment of Emissions, Controls, and Air Quality Impacts

Final Report of the WRAP Market Trading Forum

October 1, 2003

Western Governors’ Association 1515 Cleveland Place, Suite 200 Denver, CO 80202

NOTE: Section VI of this report is bound separately and available on the WRAP Web site at http://www.wrapair.org/forums/mtf/nox-pm.html

### PREFACE

Regulatory Framework for Tribal Visibility Implementation Plans

The regional haze rule explicitly recognizes the authority of tribes to implement the provisions of the rule, in accordance with principles of federal Indian law, and as provided by the Clean Air Act §301(d) and the tribal authority rule (TAR) (40 CFR §§49.1– .11). Those provisions create the following framework:

1. Absent special circumstances, reservation lands are not subject to state jurisdiction. 2. Federally recognized tribes may apply for and receive delegation 1 

### of federal authority to implement CAA programs, including visibility regulation, or "reasonably severable" elements of such programs (40 CFR §§49.3, 49.7). The mechanism for this delegation is a tribal implementation plan (TIP). A reasonably severable element is one that is not integrally related to program elements that are not included in the plan submittal, and is consistent with applicable statutory and regulatory requirements. 3. The regional haze rule expressly provides that tribal visibility programs are “not dependent on the strategies selected by the state or states in which the tribe is located” (64. Fed. Reg. 35756), and that the authority to implement §309 TIPs extends to all tribes within the GCVTC region (40 CFR §51.309(d)(12)). 4. The EPA has indicated that under the TAR tribes are not required to submit §309 TIPs by the end of 2003. Rather, they may choose to opt-in to §309 programs at a later date (67 Fed. Reg. 30439). 5. Where a tribe does not seek delegation through a TIP, EPA, as necessary and appropriate, will promulgate a federal implementation plan (FIP) within reasonable timeframes to protect air quality in Indian country (40 CFR §49.11). EPA is committed to consulting with tribes on a government-to-government basis in developing tribe-specific or generally applicable TIPs where necessary (See, e.g., 63 Fed. Reg. 7263-64).

The amount of modification, if any, needed for this report to fulfill tribal needs may vary considerably from tribe to tribe. The authors have striven to ensure that all references to tribes in the document are consistent with principles of tribal sovereignty and autonomy as reflected in the above framework. Any inconsistency with this framework is strictly inadvertent and not an attempt to impose requirements on tribes which are not present under existing law.

Tribal Participation in the WRAP

Tribes, along with states and federal agencies, are full partners in the WRAP, having equal representation on the WRAP Board as states. Whether Board members or not, it must be remembered that all tribes are governments, as distinguished from the “stakeholders” (private interest) which participate on Forums and Committees but are not eligible for the Board.

1 Tribes also possess a more fundamental source of authority to regulate their environments, based on their inherent authority as sovereign nations, which predates the formation of the United States. However, in the context of air pollution regulation and visibility planning in particular, tribal authority will more likely be based on delegation of federal authority.

### Despite this equality of representation on the Board, tribes are very differently situated than states. There are over four hundred federally-recognized tribes in the WRAP region, including Alaska. The sheer number of tribes makes full participation impossible. Moreover, many tribes are faced with pressing environmental, economic, and social issues, and do not have the resources to participate in an effort such as the WRAP, however important its goals may be. These factors necessarily limit the level of tribal input into and endorsement of WRAP products.

The tribal participants in the WRAP, including Board members Forum and Committee members and co-chairs, make their best effort to ensure that WRAP products are in the best interest of the tribes, the environment, and the public. One interest is to ensure that WRAP policies, as implemented by states and tribes, will not constrain the future options of tribes who are not involved in the WRAP. With these considerations and limitations in mind, the tribal participants have joined the state, federal, and private stakeholder interests in approving this report as a consensus document.

## TABLE OF CONTENTS

Section I: Executive Summary

Prepared by WRAP Staff

Section II: NOx and PM Emissions from Stationary Sources

Prepared by WRAP Staff

Section III: Nitrate and PM Ambient Concentrations

Prepared by WRAP Staff

Section IV: A Conceptual Model of Regional Haze in the West and the Role of Stationary Source NOx and PM Emissions

Prepared by Armistead Russell, Georgia Institute of Technology

Section V: Summary of Air Quality Modeling Results

Prepared by WRAP Staff, the University of California at Riverside, and ENVIRON Corporation

Section VI: Summary of Emission Controls Available for Large Stationary Sources of NOx and PM

Prepared by Reaction Engineering Incorporated and Energy & Environmental Strategies

Section VI Bound separately and available at http://www.wrapair.org/forums/mtf/nox-pm.html

### I-1 

## SECTION I: EXECUTIVE SUMMARY

Background and Purpose

The primary purpose of this report is to provide the information necessary for western states and tribes to fulfill the requirements of Section 309(d)(4)(v) of the U.S. Environmental Protection Agency’s (EPA) regional haze rule (40 CFR 51.309). Specifically, the rule states:

Provisions for stationary source NOx and PM. The plan submission must include a report which assesses emissions control strategies for stationary source NOx and PM, and the degree of visibility improvement that would result from such strategies. In the report, the State must evaluate and discuss the need to establish emission milestones for NOx and PM to avoid any net increase in these pollutants from stationary sources within the transport region, and to support potential future development and implementation of a multipollutant and possibly multisource market-based program. The plan submission must provide for an implementation plan revision, containing any necessary long-term strategies and BART requirements for stationary source PM and NOx (including enforceable limitations, compliance schedules, and other measures) by no later than December 31, 2008.

The regional haze rule provides the nine western states within the Grand Canyon Visibility Transport Region (GCVTR) an opportunity to submit state implementation plans (SIPs) containing policies and programs recommended in the final report of the Grand Canyon Visibility Transport Commission (June 1996). Such plans must be submitted by December 31, 2003. GCVTR states electing not to submit SIPs under Section 309 must submit SIPs under Section 308 of the regional haze rule in the 2005-07 time frame. Indian tribes have the option to submit tribal implementation plans (TIPs) under either section at any time. Moreover, the TIPs may include reasonably severable elements of the rule. A map of the WRAP region, mandatory federal Class I areas addressed by the regional haze rule, and WRAP state and tribal members is provided in Figure I-1

. A major provision of Section 309 is the control of stationary source sulfur dioxide (SO 2 

### ) emissions. The provision quoted above – for a report on stationary sources of NOx and PM – is to ensure that states begin the process of evaluating other pollutants from stationary sources. Hence, this report is meant as a starting point for a potentially multi-year process of evaluating stationary sources and designing further control strategies where appropriate. At a minimum, this process must include the determination of best available retrofit technology (BART) for certain sources 1 

### and the resulting visibility improvements and may include an alternative (e.g., emissions trading) program achieving greater reasonable progress towards the national visibility goal of no man-made impairment.

1 BART-eligible sources are those which belong to one of 26 industrial categories, have the potential to emit at least 250 tons per year of a visibility-impairing pollutant, and were put into place between 1962 and 1977.

### I-2 Organization of Report

This report is required for the GCVTR states choosing to submit SIPs under Section 309 of the region haze rule, but since all states must ultimately address stationary source NOx and PM emissions from BART-eligible and potentially other stationary sources, the scope of this report goes somewhat beyond the nine states in the GCVTR and the limited number of BART-eligible sources in the WRAP region. For example, the air quality modeling evaluates the impact of emission changes within the GCVTR, but at all Class I areas within the contiguous WRAP region. Also, emission control technologies evaluated in Section VI were chosen on the basis of source types throughout the WRAP region, which do not differ substantially from those types within the GCVTR. They were also chosen on the basis of all existing source types, not just BART-eligible source types, partly because sources eligible for BART as a result of pollutants other than SO 2 

### have not yet been identified 2 

### and partly because an alternative program to BART could apply to a much broader universe of sources. By extending the scope of this report beyond the nine GCVTR states and beyond the BART-eligible stationary sources, it not only becomes applicable to a wider range of WRAP members and potential control strategies but serves to coordinate regional development of such strategies. It is also a more cost-effective approach than dealing with the nine GCVTR states separately.

As noted above, this report contains analyses and information to initiate a process for evaluating stationary sources of NOx and PM – a process required of all states and open to Indian tribes as well. The Executive Summary contains highlights of the report, but it is also where specific issues raised in Section 309(d)(4)(v), such as interpollutant trading, are directly and succinctly discussed. This is intended to help Section 309 states and tribes address the literal requirements of the rule.

Table I-1 shows how analyses within this report were designed to address the specific requirements of the rule. Emissions data can be used to assess emission control strategies and to evaluate the need for milestones by illustrating the relative significance of different source categories to total NOx and PM emissions, both now and in the future. Ambient monitoring data can be used to assess emission control strategies by illustrating where and how much nitrate and primary PM may contribute to actual visibility impairment. The conceptual model is intended to support this entire assessment and to provide a common, scientifically-founded understanding of western haze and the role of stationary sources in anticipation of a multi-year assessment of their importance and control options. The conceptual model is intended to provide a more complete framework than what can be provided alone by the air quality modeling and other assessments. Air quality modeling is used in a “sensitivity capacity” to assess emission control strategies, their degree of visibility improvement, and the need for milestones to prevent any future increase in emissions. A summary of current NOx and PM control technologies and their costs, trends, and secondary and multi-pollutant impacts can be used to assess emission control technologies and the need for milestones to support multisource and multipollutant programs. This summary is also a useful starting point for addressing the BART requirements in Section 308 SIPs and Section 309 SIP revisions. All these analyses are expected to be updated and improved by the WRAP before such SIPs are adopted.

2 The full universe of BART-eligible sources does not need to be identified until SIPs and SIP revisions are due in 2005-08, although this identification process is expected to begin in 2003.

### I-3 Table I-1. Analyses Contained in this Report and Their Relation to the Requirements in Section 309(d)(4)(v) of the Regional Haze Rule.

Requirements of 309(d)(4)(v)EmissionsDataAmbientDataConceptualModelAir QualityModelControlTechnologies



### Assess emission control strategies X X X X X
Assess degree of visibility improvement that would result from such strategies XXX

Evaluate and discuss the need to establish milestones to avoid any net increase X XX

Evaluate and discuss the need for milestones to support potential future development of multipollutant and multisource market-based programs X X

Implementation plan revision by December 31, 2008

Finally, emissions in Alaska are not presented because resources did not permit examination of a second emissions inventory database, nor are air quality modeling results presented for Alaska because the visibility modeling system for Alaska is currently under development. However, ambient monitoring data for Alaska are presented, and the conceptual model and control technology information are applicable as well.

Summary of Findings

Analysis of current and future emissions, ambient monitoring data, and very limited modeling results indicates that stationary source emissions of PM probably cause less than 2 percent of the region’s visibility impairment, whereas stationary source NOx emissions result in nitrates 3 

### that probably cause about 2 to 5 percent of the impairment on the Colorado Plateau 4 

### and about 10 percent of the impairment in some areas of the Northern Plains, Pacific Northwest, and southern California. These findings may change as emission projections are updated and as ambient monitoring data from new sites is collected and analyzed, and especially as modeling capabilities are improved and as more data become available for the best and worst visibility days.

3 NOx emissions may also increase other PM species.

4 Some of the 20 percent haziest days, however, are dominated by nitrate.

### I-4 Regardless of this or future regional technical analyses, the remedy embodied in reasonably attributable visibility impairment requirements under the regional haze rule is still available where BART-eligible sources of NOx and PM are found to have direct impact on specific mandatory federal Class I areas. Furthermore, when considering NOx and PM milestones, attention should be given to the reasonable progress goals in the regional haze rule, which generally entail steady and continuing emission reductions and no degradation on the best visibility days. Where stationary source NOx emission reductions are appropriate, substantial reduction may be feasible with commercially-available technologies for about $300 to $1,200 per ton.

Assessment of Emission Control Strategies for Stationary Sources of NOx and PM

Since this report is primarily a starting point for addressing stationary source NOx and PM emissions, the control of which would not be determined until the 2005-08 timeframe, specific emission control strategies including such elements as level of control, applicability, and emissions trading are not addressed. Rather, this report identifies significant issues in assessing and designing such control strategies and provides some preliminary emissions, monitoring, and modeling results.

Stationary source NOx emissions comprise about 25 percent of the WRAP NOx emission inventory. One byproduct of NOx emissions is nitrate aerosols. As described in Section III, during the 20 percent worst days on the Colorado Plateau, nitrate aerosols are responsible for about 6 to 18 percent of the man-made visibility impairment, although on some of these days they are responsible for as much as 40 to 60 percent. At some sites in the Northern Plains, Pacific Northwest, and southern California, nitrate aerosols are responsible for about 40 percent of the man-made visibility impairment during the 20 percent worst days. Assuming the contribution of stationary sources to nitrate is roughly equal to their proportion of the NOx emission inventory, then stationary source NOx emissions might be expected to contribute to about 2-5 percent of the Plateau’s light extinction and to about 10 percent of the extinction in the Northern Plains, Pacific Northwest, and southern California.

Potentially increasing these contributions is the fact that stationary sources have unique emission characteristics which may disproportionately impact visibility (e.g., stack heights, transport distances, and proximity to Class I areas). Also, NOx is known to influence the formation of non-nitrate secondary fine particles, to alter the characteristics of primary coarse particles, and its future significance may depend on future changes in sulfur and ammonia emissions. On the other hand, total NOx emission in the WRAP region are expected to decrease by over 25 percent, 5 

### primarily as a result of federal controls on mobile sources, and NOx reductions may, in isolated instances, lead to local increases in nitrate concentrations.

To determine the effectiveness of stationary source NOx controls, it is therefore important to have an air quality model that can account for the processes above. The WRAP’s current modeling system, while sufficient for analyzing the regional impact of some emission changes, is not predicting nitrate concentrations well enough to support a decision on whether or not

5 Future NOx emissions will, of course, depend on uncertain activity levels (e.g., oil and gas development) and regulatory developments (e.g., new source review reforms).

### I-5 stationary source NOx controls are an effective way at achieving reasonable progress – the results are simply too uncertain. Several improvements to the modeling system are underway, but until the model produces better nitrate results, other means of assessment will be necessary to determine the appropriate level of NOx control in future SIPs.

Given the model’s current performance, its use in this report is limited to the summer months (July through September), when it is performing best for nitrate, but also when nitrate concentrations are lowest. Furthermore, its use is limited to two “sensitivity analyses” – a 50 percent stationary source NOx reduction and a 50 percent stationary source PM 10 

### reduction. The purpose of the sensitivity analyses is to gauge how nitrate and other atmospheric constituents might respond to significant changes in emissions, albeit such responses may be conservative given the model’s limited application to the July – September time period. Results are summarized in the next part of this Executive Summary and discussed in more detail in Section V of the report.

As advancements are made towards understanding the air quality impacts of stationary source NOx emissions, it is appropriate to investigate the potential level of control that can be achieved, and at what cost. Section VI of this report identifies 34 NOx control technologies. Most of these are commercially available, while others are near-available. Those for coal-fired boilers (by far the largest category of stationary source NOx emissions) typically achieve 30 to 50 percent NOx control at a cost of about $300 to $1,200 per ton. 6 

### Actual costs and emission reductions are highly dependent on boiler type, vintage, and configuration, fuel burned, and existing controls. For these reasons, it is important to have recent, extensive, and reliable data on the emission source population, some of which are lacking in the WRAP inventory, such as current control information, utility boiler heat rates, information on the process producing the emissions (e.g., from natural gas compressor stations), and utilization rates (e.g., from industrial internal combustion engines). Future WRAP emission inventories should include such information.

Visibility impairment may occur when a high portion of the NOx emissions are in the form of (or converted to) nitrogen dioxide gas (NO 2 

### ). This may be important in urban hazes and in some coherent plumes, but is typically negligible for regional haze. 7 

### For this reason, NO 2 

### is not included in the light extinction budget in the EPA’s guidance for tracking reasonable progress.

Stationary source PM 10 

### emissions 8 

### are currently 6 percent of the WRAP PM 10 

### inventory and maygrow slightly to 7 percent by 2018. However, the WRAP inventory does not yet include windblown fugitive dust emissions (currently under development), which will tend to decrease the apparent contribution of stationary source PM 10 

### emissions. PM 10 

### accounts for nearly all the man-made light extinction, but the amount attributable to primary stationary source emissions is difficult to determine. Since most of the coarse fraction (between 2.5 and 10 microns) is believed to be primary and only some of the fine fraction is believed to be primary, the percent of visibility impairment attributable to coarse particles should approximate the contribution of

6 One exception is selective catalytic reduction (SCR), which is capable of achieving 70 to 90+ percent control at costs of approximately $1,200 to $2,000 per ton.

7 See, for example, Watson J., Visibility: Science and Regulation, J. of Air and Waste Manage. Assoc. 52:628.
8 As explained in Section II of this report, the term “PM” used in Section 309(d)(4)(v) of the regional haze rule is construed as primary PM 10 emissions.

### I-6 primary PM 10 

### emissions from all sources. As shown in Section III, this is approximately 10 to 20 percent (on average) across most of the WRAP region, with generally lower percentages in the Pacific Northwest and higher percentages in the southeast part of the region. Assuming the contribution of stationary sources to ambient primary PM 10 

### is roughly equal to their proportion of the PM 10 

### emission inventory, then stationary source PM 10 

### emissions might be expected to contribute to less than 2 percent of the region’s light extinction. Coupled with the fact that stationary source PM 10 

### emissions are relatively well controlled in the West, there does not appear to be much potential in a stationary source PM control strategy for purposes of regional haze. PM 10 

### emissions, however, appear to have a greater visibility impact per ton than NOx emissions, as shown in Section V. Also, some PM 10 

### emission co-benefits may result from multi-pollutant technologies described in Section VI, so reductions in stationary source PM 10 

### emissions could conceivably be part of a broader air quality management strategy and/or part of a broader strategy to achieve reasonable progress under the visibility regulations – e.g., to prevent degradation on the cleanest days.

Finally, the appropriate level of stationary source NOx and PM control, if any, should be informed by a comprehensive assessment, which may include some non-visibility impacts (to the extent they can be estimated within WRAP resources and with the WRAP’s visibility-based tools) and the full costs and benefits of controls, not just those associated with facility compliance and visibility improvements. To this end, the WRAP is completing work on an economic analysis framework to conduct such analyses in a consistent and technically sound

manner.

Degree of Visibility Improvement Resulting from Emission Control Strategies for Stationary Sources of NOx and PM

Due to the complex role of NOx emissions in the atmosphere, a regional-scale modeling effort is underway to more carefully assess the visibility improvement from potential control strategies.Given the model’s current performance, its application in this report is limited to the JuneSeptember timeframe – when nitrate performance is best, but also when nitrate concentrations are lowest – and it is only used in a “sensitivity analysis mode”, meaning two scenarios were modeled to gauge how nitrate and other atmospheric constituents might respond to significant changes in emissions: one in which emissions of NOx are reduced by 50 percent (412,000 tpy) from stationary sources in the GCVTR with emissions of NOx greater than 100 tpy, and an identical scenario for PM 10 

### (98,000 tpy).

Current modeling results indicate that the stationary source NOx and PM 10 

### emission reductions described above would reduce regional haze (in Mm -1 

### ) by 0.5 percent and 0.4 percent, respectively, when averaged across all sites in the GCVTR over the June-September time period, although some areas would see an improvement of 2 to 5 percent on some days. 9 

### On a purely ton-per-ton basis, reductions in stationary source PM 10 

### emissions appear to yield greater regional haze benefits than reductions in NOx emissions, since they produced almost the same visibility benefit at one-fourth the emission change.

9 These results are similar to the more general assessment made in Section IV (see page IV-21).

### I-7 The NOx emission reductions had the greatest impact in southern CA, where ammonium nitrate concentrations in Class I areas are predicted to decrease by 0.15 to 0.25 ug/m 3 

### . A second area of reductions is predicted in the central-east Rocky Mountains, especially in north-central CO. Although the reductions are not as large as in southern CA (0.04 to 0.11 ug/m 3 

### ), they are larger than average across the domain and exhibit the largest percentage reduction (10 to 20 percent).

It is interesting to compare these results with those simulating the effects of the SO 2 

### backstop emissions trading program, or Annex. In the case of the Annex, an SO 2 

### emission reduction of 15 percent (132,000 tons) in the GCVTR produced a sulfate reduction of 4 percent averaged across all Class I areas in the GCVTR on the 20% worst modeled days. In the case of the NOx sensitivity run, a NOx emission reduction of 15 percent (412,000 tons) in the GCVTR produceda nitrate reduction of 5 percent averaged across all Class I areas in the GCVTR on the JulySeptember modeled days. The nitrate reduction does not produce as much visibility benefit at most Class I areas because its concentrations are much smaller than the sulfate concentrations, but the response of nitrate to NOx reductions is similar in proportion to the response of sulfate to SO 2 

### reductions.

NOx changes appear to have very little effect on aerosol concentrations beyond changes in nitrate. Other species that could be indirectly affected – e.g., ozone concentrations and subsequent oxidation of SO 2 

### and organic gases into the particulate phase – do not appear influenced by the levels of NOx reductions (16 percent of the total inventory) assumed in this analysis.

The PM 10 

### emission reductions had a maximum impact of about 0.1 to 0.5 ug/m 3 

### , or about 4 to 8 percent. Compared to the NOx reduction scenario, reductions in ambient PM 10 

### are more dispersed, with a greater number of local maximums. This may reflect the fact that there are a fewer number of large PM 10 

### sources than large NOx sources and that much of the PM 10 

### emissions are coarse particles, with shorter transport distances.

All modeling results in this report are subject to change after the modeling improvements described in Section V are implemented. Results may also change when compiled for the best and worst visibility and nitrate days throughout the year, as opposed to a three-month summer average. For reasons described in Section V, the three-month summer average probably tends to reduce the apparent impact of emission changes.

The Need to Establish Milestones to Avoid Any Net Increase in NOx and PM Emissions from Stationary Sources

Sensitivity modeling was also done to evaluate the impacts of a 25 percent simultaneous increase in stationary source NOx and PM 10 

### emissions. The increase in nitrate formation was approximately half the magnitude of the decrease resulting from the NOx reduction scenario. However, the increase in PM 10 

### (nitrates and primary particulates) and visibility impairment were about the same in the 25 percent increase scenario as in the two 50 percent decrease scenarios because both pollutants were increased simultaneously.

### I-8 The need to establish milestones to avoid any net increase in NOx and PM emissions from stationary sources should be determined when more complete and accurate modeling results (and ambient data analyses) are available, prior to submittal of the Section 309 SIP revisions in 2007-08. In addition to the modeling results per se, consideration should be given to meeting the reasonable progress goals of the regional haze rule, which generally imply a steady and continuous reduction in emissions and a prevention of degradation on the best visibility days.

The Need for Milestones to Support Potential Future Development of Multipollutant and Multisource Market-Based Program

Milestones are not absolutely necessary to support potential multipollutant and multisource market-based programs. For example, a group of sources could theoretically comply with an SO 2 

### milestone by reducing emissions of other pollutants, and/or in other sectors, for which no milestones exist. Regardless, the key issues raised by such programs do not involve the milestones as much as the uncertainties associated with such emissions trading.

As discussed in Section IV, there are a number issues that must be addressed. Most of these relate to the visibility-improvement value of eliminating a ton of emissions. Different pollutants have different impacts on visibility on a per ton basis. Establishing an “equivalency ratio” to allow X tons of one pollutant to be reduced in lieu of Y tons of another would require significant analysis, and the certainty of such values may be suspect (especially for NOx) or insufficient to ensure a specific level of visibility improvement. Moreover, the equivalency ratio between two pollutants may vary across the region, between seasons, and possibly over time as the composition of the atmosphere changes. These same uncertainties (involving trades among pollutants) also pertain to trades among a single pollutant, most notably NOx, as nitrate concentrations are highly variable by season and location.

Trading across emission source categories poses a couple of additional issues. First, all categories would have to have sufficient emissions monitoring to validate emission credits, and monitoring of non-stationary sources is generally less accurate and verifiable than monitoring of stationary sources. Second, concentrated emissions from stacks may have different impacts than diffuse emissions at ground-level.

The uncertainties identified above could be reduced through further research, and the remaining uncertainties could be further addressed by limiting the emission trading markets to certain subregions, pollutants, or seasons where the equivalency ratios are fairly certain and stable. However, such market restrictions could limit the economic benefits the market is intended to provide. In short, some level of multipollutant and/or multisource market based program could be a feasible way of meeting the long-term national visibility goal, and several of the technologies described in Section VI of this report are capable of multipollutant reductions, but substantially more research should be performed before committing to such programs, especially in the 2007-08 timeframe.

### I-9 Figure I-1. Map of the WRAP Region, Members, and Mandatory Federal Class I Areas.

### II-1 

## SECTION II: NOx AND PM EMISSIONS FROM STATIONARY SOURCES

Data Sources

The data presented in this section are based on “Version 1” of the WRAP stationary source emission inventory, downloaded from the WRAP website in June 2002 (filename wga_pt96.dbf). A second version of the inventory was released in October 2002, which contained a couple dozen corrections to point source coordinates, stack parameters, and source classification codes among the 214,000 records in the database. There were also some corrections to the NOx and PM emissions, which reduced the regional point source totals by two percent and six percent, respectively. A third version of the inventory was released in March 2003. This version contained minor NOx and PM emission changes in Pima and Navajo Counties (less than one percent of state-wide point sources) and NOx emission reductions in Nevada amounting to a 4,400 ton (or nine percent) decrease in the state-wide point source inventory. Discrepancies noted in Maricopa, Pima, and Pinal Counties by stakeholders in Arizona have not yet been incorporated into the WRAP database.

For the purposes of this regional-scale characterization of NOx and PM sources, the changes made to Version 1 of the stationary source inventory are essentially insignificant. The analysis, therefore, was not repeated. However, the analysis presented in Section VI is based on the most recent inventory since the analysis was begun after the Version 3 was available. This may cause slight discrepancies between the data presented here and in Section VI, but the conclusions are unaffected.

The term “PM” used in Section 309(d)(4)(v) of the regional haze rule has been construed in this report as primary PM 10 

### emissions. Precursor emissions are not considered “PM” because they are explicitly referenced where appropriate throughout the rule, as is done with NOx in 309(d)(4)(v). PM 10 

### was chosen over PM 2.5 

### because PM 10 

### includes PM 2.5 

### and because all particles less than 10 microns have visibility impairing attributes. Moreover, many of the PM 2.5 

### emission estimates are derived from PM 10 

### emission factors as opposed to direct PM 2.5 

### measurements – i.e., a certain fraction of the PM 10 

### is assumed to be PM 2.5


### .
Emissions Summary

Table II-1 provides a summary of air pollutant emissions in the 13-state contiguous WRAP region (including Nevada but not Alaska). NOx emissions from stationary sources are expected to increase slightly, but due to decreases from other sources, their percentage of the total inventory is expected to grow from 22 percent to 33 percent to become the single largest source category. Stationary source PM 10 

### emissions appear less important than NOx emissions, but they may contribute more to haze on a per ton basis, partly because not all NOx emissions are converted to particles and partly because stationary source PM emissions contain some elemental carbon, which is a highly-efficient light absorber. Compared to other source categories, stationary sources do not emit a large amount of PM 10 

### , but their emissions may contribute more to haze on a per ton basis than other source categories because they emit particles primarily in

### II-2 the fine mode (less than 2.5 microns) and often through stacks, making them more likely to be transported to Class I areas. Future work should examine available information on the dispersion characteristics, size distribution, and chemical and optical properties of primary PM emissions from stationary sources relative to other types of sources.

Table II-1. Air Pollutant Emissions in the 13-State WRAP Region.

Figure II-1 shows the location and relative magnitude of stationary source NOx emissions in the WRAP region with emissions of NOx greater than 100 tons per year (tpy) on a plant-wide basis. The WRAP 1996 inventory contains over 6,700 point sources of NOx. Approximately 11 percent of these plants (763) emitted 100 tpy or more of NOx and were responsible for 94 percent of total stationary source NOx emissions. Approximately 150 of the plants are electric power plants.

Figure II-2 shows the location and relative magnitude of stationary source PM 10 

### emissions in the WRAP region with emissions of PM 10 

### greater than 100 tpy on a plant-wide basis. The WRAP 1996 inventory contains over 6,500 point sources of PM 10 

### . Approximately 5 percent of these (338 plants) emitted 100 tpy or more of PM 10 

### and were responsible for 82 percent of total stationary source PM 10 

### emissions.

Figures II-3 and II-4 identify and compare emissions from the major stationary source categories of NOx and PM 10 

### , respectively. External combustion boilers (utility and industrial) are the largest source categories for both NOx and PM 10 

### . Industrial internal combustion engines (mostly natural gas fired) is another substantial source of NOx emissions. This category may warrant more attention since it is not inventoried with the same rigor as electric utility sources. The major source categories of PM 10 

### are more diverse in character than those for NOx, including such broad categories as mineral products, chemical manufacturing, and primary metal production. This part of the inventory may also warrant further investigation since many of the emissions might be fugitive. Categorization of fugitive emission, in addition to source classifications, may vary across states. Further information on stationary source emissions, especially on the largest sources (boilers and internal combustion engines), is provided in Section VI. Emissions Category tons % tons % tons % tons %
Point 1,059,985 22% 196,005 6% 1,118,460 33% 247,071 7% Area 352,623 7% 1,921,389 54% 449,559 13% 1,981,060 54% On-Road Mobile 1,755,573 37% 59,098 2% 485,270 14% 46,139 1% Off-Road Mobile 1,368,663 29% 103,069 3% 950,414 28% 91,412 2% Wildfire 166,703 4% 755,537 21% 59,641 2% 270,307 7% Prescribed Fire 16,688 0% 50,057 1% 338,627 10% 525,393 14% Agricultural Fire * * * * 3,504 0% 8,894 0% Paved Road Dust 0 0% 91,322 3% 0 0% 165,106 5% Unpaved Road Dust 0 0% 370,762 10% 0 0% 326,042 9% Total 4,720,236 100% 3,547,239 100% 3,405,475 100% 3,661,423 100% * Not available 1996 2018 NOx PM10 NOx PM10

### II-3 Figure II-1. Stationary Source NOx Emissions > 100 tpy in the WRAP Region (1996).

### II-4 Figure II-2. Stationary PM 10 

### Emissions > 100 tpy in the WRAP Region (1996).

### II-5 Figure II-3. Categorization of Stationary Source NOx Emissions > 100 tpy in the WRAP Region (1996).

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000

Emissions (tpy) Process Heaters (petro) Natural Gas Production Cement Manufacturing Natural Gas Wood/Bark Waste Distillate Oil Sub/Bituminous Coal Natural Gas Natural Gas Distillate Oil (diesel) Natural Gas Lignite Sub/Bituminous Coal

Utilit y Boilers

Utility ICEs

Industrial ICEs

Industrial Processes Industrial Boilers These sources comprise 91% of the emissions > 100 t py

### II-6 Figure II-4. Categorization of Stationary Source PM 10 

### Emissions > 100 tpy in the WRAP Region (1996).

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

Emissions (tpy) Misc. Manufacturing Sulfate (Kraft) Pulping Not Classified Copper Smelting Gold Iron Production Metal Mining (General) Not Classified Magnesium Carbonate Nonmetallic Minerals Mining

Coal Mining and Handling Sub/Bituminous Coal

Wood/Bark Waste Lignite Sub/Bituminous Coal Utilit y Boilers

Industrial Boilers

Mineral Products

Chemical Manufacturing

Primary Metal Production

Industrial Processes These sources comprise 78% of the emissions > 100 tpy

### III-1 

## SECTION III: NITRATE AND PM AMBIENT CONCENTRATIONS

Figures III-1 through III-11 show spatial patterns of ammonium nitrate (NH4NO3) and PM and historical trends in PM at IMPROVE monitoring sites in 1996 and 2001. The maps and data were downloaded from the VIEWS website ( http://vista.cira.colostate.edu/views ) on May 20, 2003. At that time, maps were only available for annual and seasonal averages, but some are now available for the best and worst visibility days. Hence, all the maps in this section except one indicate annual averages. Also, because the legends are auto-scaled, they are not the same in each map. For example, the value indicated by a yellow contour in Figure III-1 (1996) is not the same as the value indicated by a yellow contour in Figure III-2 (2201).

IMPROVE sites are located in rural settings, typically within Class I areas. They are not representative of more heavily polluted urban areas and tend to represent air quality at regional scales. Due to the size of the IMPROVE monitoring network, the maps for 1996 include data from less than a third of the western Class I areas. The maps for 2001 include data from about two-thirds of the western Class I areas, and additional monitors have been established since then.

Figures III-1 and III-2 show the annual average NH4NO3 concentrations in 1996 and 2001, respectively. Concentrations are typically less than 0.6 ug/m 3 

### , with some areas in southern CA and the Columbia River Gorge exceeding 1.5 ug/m 3



### .
Figures III-3 and III-4 show the percent of aerosol-caused 10 

### annual average light extinction due to NH4NO3 in 1996 and 2001, respectively. This percent is typically less than 14, with some higher areas in the Pacific Northwest and Northern Plains, and especially in southern CA (exceeding 20 percent). Since some aerosols – principally organic carbon and “soil” and “coarse” aerosols – have substantially strong natural sources, the percent contribution of NH4NO3 to man-made haze is somewhat greater than indicated in Figures III-3 and III-4. A rough estimate of the contribution to man-made impairment can be obtained by assuming half the organic carbon, soil, and coarse aerosols are naturally caused. Removing these natural contributions from the light extinction budgets would raise the percent contribution of NH4NO3 by approximately 20 percent in each of the regions noted above (Colorado Plateau, Pacific Northwest, Northern Plains, and southern California). 11 

### For example, where NH4NO3 may contribute to 15 percent of the aerosol-caused light extinction in these areas, it would contribute to about 18 percent of the man-made light extinction.

Data recently provided on the VIEWS website indicates that the percent contribution of NH4NO3 to light extinction on the 20 percent worst days, as shown in Figure III-5 , is slightly greater than the percent contribution on average, as shown in Figure III-4. Moreover, a cursory examination of daily data collected on the Colorado Plateau in 2001 indicates that some of the 20 percent worst days are dominated by NH4NO3. Some examples are provided in Table III-1

. Such episodes should be quantified and studied more thoroughly in future WRAP work.

10 Aerosol-caused light extinction excludes natural (Rayleigh) scattering by air molecules.

11 See Table 3.3 in Malm, William C. et al., Spatial and Seasonal Patterns and Temporal Variability of Haze and Its Constituents in the United States, Colorado State University, May 2000.

### III-2 Table III-1. A Sample of Hazy Days in 2001 Dominated by NH4NO3 on the Colorado Plateau.

Class I Area Date Light Extinction a 

### (Mm -1 

### ) NH4NO3 Contribution 2001 Average Light Extinction a 

### (Mm -1 

### ) 2001 Average NH4NO3 Contribution Bryce Canyon 01/16/01 35 55 % 16 11 % 01/28/01 28 49 %

Canyonlands 01/04/01 23 55 % 14 15 % 01/19/01 31 48 % 01/22/01 33 55 %

San Pedro 01/07/01 16 50 % 11.5 10 % 02/09/01 14 31 % 12/21/01 13 36 %

a 

### Over and above natural (Rayleigh) scattering by air molecules (10 Mm -1 

### ).

Finally, NH4NO3 exhibits a strong seasonal pattern. When averaged across the 32 IMPROVE sites operating in 1996-1999, the light extinction due to NH4NO3 is about 10 percent on an annual basis and about 17 percent in the winter.

Figures III-6 and III-7 show the annual average PM 10 

### concentrations in 1996 and 2001, respectively. Specifically, the values are reconstructed total mass – that is, speciated fine mass plus gravimetrically-determined coarse mass (PM 10 

### - PM 2.5 

### ). (Gravimetric PM 10 

### was not available from the VIEWS website.) PM 10 

### concentrations are typically below 8 ug/m 3 

### , with some areas in the Columbia River Gorge, Northern Plains, and southern CA exceeding 10 ug/m 3



### .
Figures III-8 and III-9 show the percent of aerosol-caused annual average light extinction due to coarse particulate matter (between 2.5 and 10 microns) in 1996 and 2001, respectively. Since most of the coarse fraction is believed to be primary and only some of the fine fraction is believed to be primary, the percent of visibility impairment attributable to coarse particles should approximate the contribution of primary PM 10 

### emissions from all sources to visibility impairment. As shown in the figures, this is approximately 10 to 20 percent across most of the WRAP region, with generally lower percentages in the Pacific Northwest and higher percentages in the southeast part of the region.

Figure III-10 shows trends in (gravimetric) PM 10 

### concentrations during average visibility days at 27 western IMPROVE sites. Data for the best and worst visibility days are available, but only data for average visibility days are shown for comparability with the maps in Figures III-1 through III-7. The values shown are 5-year rolling averages, meaning that the value shown for1993 represents data collected from 1989-1993. The full names of the sites shown in Figure III10 are provided in Table III-2

.

### III-3 At most sites, there appears to be a gradual decline in PM 10 

### concentrations on days with average visibility, with exceptions at Chiricahua, Grand Canyon, and Guadalupe Mountain. On the worst visibility days, however, there is less of a decline, if any, at most sites. Compare, for example, the trend at the sites shown in Figure III-11 with the first trend chart shown in Figure III-10.

Note that the trends, even when averaged over 5-year periods, can sometimes be affected by one or two extremely high events, typically associated with wildfires or dust storms. Trends in NH4NO3 concentrations and the percent of light extinction due to NH4NO3 are not available because of a measurement bias in data collected prior to June 1996. These data, however, are sufficient for showing the spatial patterns in Figures III-1 through III-7.

### III-4 Figure III-1. A nnual Average NH4NO3 Concentrations at IMPROVE Sites (1996).

Figure III-2. A nnual Average NH4NO3 Concentrations at IMPROVE Sites (2001).

### III-5 Figure III-3. Percent of A nnual Average Aerosol Light Extinction Due to NH4NO3 at IMPROVE Sites (1996).

Figure III-4. Percent of A nnual Average Aerosol Light Extinction Due to NH4NO3 at IMPROVE Sites (2001).

### III-6 Figure III-5. Percent of Aerosol Light Extinction Due to NH4NO3 at IMPROVE Sites on the 20 Percent Worst Days (2001).

### III-7 Figure III-6. A nnual Average PM 10 

### Concentrations at IMPROVE Sites (1996).

Figure III-7. A nnual Average PM 10 

### Concentrations at IMPROVE Sites (2001).

### III-8 Figure III-8. Percent of A nnual Average Light Extinction Due to Coarse Particulate Matter at IMPROVE Sites (1996).

Figure III-9. Percent of A nnual Average Light Extinction Due to Coarse Particulate Matter at IMPROVE Sites (2001).

### III-9 Table III-2. Name of IMPROVE Sites Shown in Figure III-9.

Code Site Name Code Site Name BADL Badlands LAVO Lassen Volcanic BAND Bandalier MEVE Mesa Verde BRCA Bryce Canyon MORA Mount Ranier BRID Bridger PEFO Petrified Forest CANY Canyon Lands PINN Pinnacles CHIR Chiricahua PORE Point Reyes CRLA Crater Lake REDW Redwood DENA Denali ROMO Rocky Mountain GLAC Glacier SAGO San Gorgonio GRBA Great Basin TONT Tonto GRCA Grand Canyon WEMI Weminuche GRSA Great Sand Dunes YELL Yellowstone GUMO Guadalupe Mountain YOSE Yosemite JARB Jarbidge

Figure III-10. Trends in PM 10 

### Concentrations at Western IMPROVE Sites on Days with Average Visibility.

0 2 4 6 8 10 12 14

1993 1994 1995 1996 1997 1998 1999PM10on Days with Average Visibility (ug/m3)

BADL
BAND
BRCA
BRID
CANY

### III-10 0 2 4 6 8 10 12 14

1993 1994 1995 1996 1997 1998 1999PM10on Days with Average Visibility (ug/m3)

GRCA
GRSA
GUMO
JARB
LAVO 0 2 4 6 8 10 12 14

1993 1994 1995 1996 1997 1998 1999PM10on Days with Average Visibility (ug/m3)

CHIR
CRLA
DENA
GLAC
GRBA

### III-11 0 5 10 15 20 25 30

1993 1994 1995 1996 1997 1998 1999PM10on Days with Poor Visibility (ug/m3)

BADL
BAND
BRCA
BRID
CANY 0 5 10 15 20 25

1993 1994 1995 1996 1997 1998 1999PM10on Days with Average Visibility (ug/m3)

MEVE
MORA
PEFO
PINN
PORE

### III-12 Figure III-11. Trends in PM 10 

### Concentrations at Western IMPROVE Sites on Days with Poor Visibility (Worst 20 Percent).

0 5 10 15 20 25

1993 1994 1995 1996 1997 1998 1999PM10on Days with Average Visibility (ug/m3)

REDW
ROMO
SAGO
TONT
WEMI
YELL
YOSE

### IV-1 

## SECTION IV: A CONCEPTUAL MODEL OF REGIONAL HAZE IN THE WEST AND THE ROLE OF STAITIONARY SOURCE NOx AND PM EMISSIONS

Introduction

The objective of this report is to provide a foundation for better understanding the dynamics of PM in the West, with particular attention to the nitrate and primary component that may be due to point source emissions. Further, the report explores how stationary source NOx and primary PM controls might impact FPM levels. As part of that, the utilization of a trading system is discussed. The report sets up a detailed framework to understand the issues by developing a conceptual model of PM formation, atmospheric dynamics, and impacts in the West. Next, the report discusses the likely effectiveness of PM and NOx controls on PM levels in the West and the relationship with visibility. This section also deals with issues involving emission trading. The final two sections discuss potentially useful computer simulations and a summary.

Overview of PM in the West

The area covered by the Western Regional Air Partnership (WRAP) includes a large fraction of the continental United States. In an air quality management context, this area has very different air quality characteristics. In part, this is due to the diversity in the source characteristics of the region, ranging from large coastal California cities to very sparsely populated and isolated regions. In the former, the emissions are dominated by mobile sources, disperse human activities, and a variety of industries. In the latter, natural sources (e.g., fire, dust, and biogenic emissions) and large point sources (e.g., electricity generating units) can dominate. Similarly important are the meteorological and topographical differences: e.g., rainy and cool coastal areas in the Northwest, dry mountainous regions further inland, and deserts in the Southwest. Pollutant levels and characteristics vary accordingly. Not only do the relative levels of pollutants vary, but the composition and source contributions change as well. This is especially seen in the particulate matter composition. In Los Angeles, nitrate (and the associated ammonia) is a major contributor. Outside of California, nitrate is usually a relatively minor contributor, though the Columbia Gorge and Seattle areas find somewhat elevated levels (Malm et al., 2003).

Unlike gases, particulate matter is characterized not only by its composition, but by the particle size as well. From a regulatory standpoint, particulate matter is divided in to three fractions: fine, coarse and very coarse. To a degree, these capture how the particulate mater size distribution is considered from a scientific perspective, which is broken in to four modes of ascending size: nucleation, Aitken, accumulation and coarse modes. The nucleation mode is the very fine fraction where new particles are formed from nucleation of vapors. Recently, as part of the Supersite experiments, regional nucleation events have been seen. These particles then grow into the Aitken mode, which also contains primary emissions from combustion sources, and finally the accumulation mode. The accumulation mode is aptly named as the smaller particles grow in to this mode, but the growth out of accumulation mode particles into the coarse mode is very slow. Recent interest has grown over another possible division of PM: ultrafines (having

### IV-2 particle diameters less than about 0.1 um). There is relatively less information about ultrafine PM.

Fine particulate matter (FPM) is often measured as PM2.5, or particulate matter with an aerodynamic diameter less than 2.5 micrometers (um). Some measurements of FPM have used other cut points, but there is a natural cut point at 2.5 um between the accumulation and coarse modes. On a mass basis, FPM is dominated by PM in the accumulation mode. Thus, coarse particulate matter is the fraction with particle diameters greater than 2.5 um. Given the historical measurements of PM10, coarse PM is often taken as the fraction between 2.5 and 10 um. The fraction above 10 um can be considered as very coarse, and is included (along with the other fractions) in total suspended particulate matter (TSP) measurements. The reasons for using these ranges have to do with the somewhat distinct dependence of the various size fractions on source, their atmospheric dynamics and impacts. Also, if one looks at a size distribution of PM, these modes become apparent. Characteristics of the coarse fraction are that the particles are mechanically generated (e.g. from road dust, construction, mining, etc.) and have relatively shorter atmospheric lifetimes due to settling and deposition, particularly for the very coarse particles. FPM can be mechanically generated (FPM can be present as the tail end portion of emissions that are mostly coarse) or from chemical conversion (SO2 oxidation to sulfate, combustion generation of soot, etc.), the latter often dominating. FPM also has a longer lifetime in the atmosphere as it deposits relatively slowly, though rain can rapidly remove much of the FPM. Ultrafines are due to emissions from combustion sources and chemical reactions in the atmosphere. Like FPM, ultrafines deposit slowly, but have a limited atmospheric lifetime as ultrafines because they grow due to condensation and coagulation.

While size differences are important, so are species differences. Sulfate is almost solely a secondary species, formed from the oxidation of SO2 (e.g., from coal-fired EGUs and other combustion processes). This may take place in the gas phase or from heterogeneous reactions. Sulfate is found in the fine fraction. Sulfate tends to be one of the largest components of FPM in the rural West, and still a major fraction in urban areas. Average levels are about 1 ug/m 3 

### in rural western areas. Nitrate is also a secondary component, resulting from the oxidation of NOx to form nitric acid gas, which then undergoes gas-to-particle conversion. NOx emissions are dominated by combustion sources, though there is a small fraction from biogenic emissions. Nitrate is also primarily in the FPM range, though tends to have a somewhat larger average particle diameter than the sulfate. A fraction of the nitrate is found in the coarse mode, indicative of gaseous nitric acid reacting with preexisting CPM (Malm et al., 2003). In the West, typical levels of measured nitrate outside of and not downwind of urban areas and central California tend to be low, averaging well less than 1 ug/m 3 

### . In the Los Angeles basin, nitrate levels can exceed 25 ug/m 3 

### , and significantly impact areas downwind. Care should be taken in interpreting measured nitrate levels as the techniques used are subject to artifacts (both positive and negative).

Organic carbon (OC) is the most complex part of the PM in many ways. First, it is comprised of many different species. Further, it can be primary or secondary, and biogenic and anthropogenic in origin. Again, OC is primarily FPM. Levels are highest in the cities or in areas with biomass burning (e.g., due to wild or planned fires), and there is growing evidence of the importance of secondary OC (Brown et al., 2000).

### IV-3 Elemental carbon (EC), or black carbon, is due to incomplete combustion, and appears to be primarily from wood burning and diesel vehicle emissions, though other sources contribute, and the actual fraction due to diesel vehicles is under study. Given the sources, EC is highest in urban areas, and a relatively small component of FPM in rural locations. While small on a mass basis, EC does absorb light, so can contribute more significantly to visibility degradation.

Metals, metal oxides and other crustal materials are due to a wide variety of sources, largely wind blown dust, as well as combustion, cement manufacture, etc. These are largely in the coarse mode, though a fraction is found as FPM, generally as the tail end of the size distribution of the coarse PM, or from combustion sources. In the non-coastal states of the West, the soil fraction is between about 20-30% of the FPM (Malm et al., 2003).

FPM has come to attention as an important fraction of the total particulate matter because of its potential impacts. FPM has been suspect of impacting human health, and recent and continuing studies tend to provide further support. (Less information is available for ultrafines). FPM also exists in a size range (e.g., similar to the wavelength of visible light) that effectively scatters and absorbs light, decreasing visibility, which is of particular concern in the West with its many national parks, forests and wilderness areas. Coarse particulate matter is of less concern (though still some) due to its shorter lifetimes, apparently reduced health effects and it is less effective, on a mass basis, of scattering light.

FPM levels in the West go from very low, with some of the lowest annual averages found in the US, to very high, with the Los Angeles area experiencing some of the highest. Other areas in the West experience isolated events of high PM (e.g., due to dust storms and fires) but annual average levels tend to be low. In much of the West and other parts of the country, the FPM is dominated by organic carbon and sulfate, while nitrate is typically a more minor constituent. While levels of these components, as well as FPM in general, are usually lower than in the east, the sources appear to be similar: sulfate comes from fuel combustion, particularly coal fired power plants and organic carbon comes from biomass burning and secondary formation. Of interest, recent results from the BRAVO study using molecular markers (Brown et al, 2002) suggest that a significant fraction of the organic FPM is secondary, as do similar studies in the Southeast. Carbon 14 dating of the organic matter in the Southeast (Edgerton, 2002) further suggest that the secondary organic is biogenic, which, given the emissions in the Big Bend area, would likely be the case there. Unlike most other areas, in Los Angeles and the Central Valley of California nitrate is a significant contributor, along with organic carbon and some sulfate.

Literature Review

Particulate matter dynamics has been an on-going research topic for decades. In-depth treatments of atmospheric particulate matter are contained in Seinfeld and Pandis (1998) and Friedlander (1977). The impact of PM on visibility has likewise been studied for years, with early work by van de Hulst (1957), and on-going study from the IMPROVE (Interagency Monitoring of Protected Visual Environments ) program begun in 1985 (e.g., http://vista.cira.colostate.edu/improve/ , and Malm, 2000, and references there in). Early studies

### IV-4 of nitrate dynamics and response to emissions controls include Stelson and Seinfeld (1982) and Russell and Cass (1984).

In the WRAP area, particulate matter studies have been conducted for years. One could group them in to urban vs. pristine area studies, or a second split could be California studies and the rest of the west. The urban vs. pristine area consideration is typified by studies with different considerations, e.g., in urban areas health and attaining the National Ambient Air Quality Standards are often the drivers, while in pristine areas, visibility is of primary importance. The latter distinction, between California and other areas in the west, is made on a couple of bases. First, California has been very active in conducting air quality studies, in part because of the severe air quality problems in that state. Second, as presented in the regional conceptual model discussion below, particulate matter in regions in California is compositionally distinct from what is found over much of the West.

Outside of California, the primary information that is available concerning PM in the West is derived from the IMPROVE program (e.g., Malm, 2000), and a number of studies focusing on specific areas. IMPROVE is an ongoing study of visibility in Class I areas in the U.S. most notably national parks. Amongst its objectives are to monitor the composition of particulate matter in protected environments and identify sources. Other, more regionally focused studies include the Big Bend Regional Aerosol and Visibility Observational (BRAVO) study (see Green et al., 2000, Brown et al., 2002) those associated with the Grand Canyon and Colorado Plateau (e.g., Grand Canyon Visibility Transport Commission, 1996 and project MOHAVE: Lowenthal et al., 2000), Mt. Zirkel (e.g., Watson et al., 2001), the Denver Brown Cloud, which included the Northern Front Range Air Quality Study (NFRAQS) (e.g., Watson et al., 1998). The Grand Canyon studies were directed primarily at assessing how nearby power plants (in particular, the Navajo Generating station) impact visibility in areas on the Colorado Plateau, which includes a number of Class I areas, including the Grand Canyon, which had experienced days with decreased visibility. BRAVO is assessing the sources of particulate matter and visibility degradation in the Big Bend area of Texas, and NFRAQS studied visibility in the area around Denver. While not focused on PM in the West, the Southern Appalachians Mountains Initiative (SAMI) study (SAMI, 2002) is relevant here because it addressed many of the same issues, except for the focus on Class I areas in the southeastern United States.

Within California, a number of programs are available for providing information on particulate matter in various regions. First, a number of Class I areas in the state do have IMPROVE monitors, which provide both a long term record of PM composition, as well as a means of comparing, directly, levels in California with those in other states. In addition, California has conducted a number of additional, intensive efforts, most notably in the Los Angeles area and the Central Valley. In the Los Angeles (or South Coast) Basin, two studies are of particular note: the Southern California Air Quality Study (SCAQS) and the Southern California Ozone Study, 1997 (SCOS97). There have been a number of additional studies as well, notably those by Cass and coworkers (e.g., Hildemann et al., (1984); Gard et al., 1998), and the current studies associated with the Supersite (e.g., Sioutas et al., 2003). In the Central Valley, the San Jaoquin Valley/Atmospheric Utility Signature Prediction Experiment (SJV/AUSPEX), the California Regional Particulate Matter Air Quality Study (CRPAQS) and the Fresno Supersite are providing

### IV-5 detailed information on the air quality and sources in that region. The two Supersite studies, however, are more focused on urban air quality, and less focused on visibility in protected areas.

A number of publications and reports discuss the results of the IMPROVE program, documenting the composition and trends and their relationship to visibility. A recent manuscript by Malm et al. (2003) presents the annual average fine particulate matter composition in each of 30 IMPROVE regions. In general, sulfate levels in the West are significantly below those in the East. Ammonium nitrate is high in southern California and the Lower Central Valley, with very low concentrations most other locations in the West (generally less than 0.5 ug/m 3 

### except in isolated spots, Malm et al, 2003). It should be noted that ammonium nitrate is actually not measured, but inferred from the nitrate measurements. As they note, nitrate can also be found in other forms, some of which are thermally stable (e.g., from the reaction of nitric acid with soil or sea salt, Malm et al., 1994; Gard et al., 1998 ). Organic carbon, regionally, typically runs between 0.5 and 2 ug/m 3 

### . Elemental carbon levels are low, typically below 0.5 ug/m 3 

### on average, but can be an important component in terms of visibility reduction. A recent trends report from IMPROVE (Malm, 2000, also see Sisler et al., 2000 and Malm et al., 2002) shows that trends in PM levels are mixed throughout the West. For example, Sisler et al., (2000) found that of the western sites where a significant trend was found, not quite two thirds reported improvements. In some cases, decreases of one component (e.g., sulfate) were off set by another (e.g., organic carbon), as found at Jarbridge Wilderness area. At the Guadalupe Mountains NM, organics are going down, but nitrate and fine soil are going up, with no real change in visibility.

In the Mt. Zirkel Visibility Study (Watson et al., 2001), the major components that impaired visibility were found to be sulfate, organic carbon and crustal material, similar to the results form IMPROVE monitors in the region. Nitrate was a small contributor. Greater amounts of nitrate were found during the NFRAQS study, presumably because of the more concentrated sources of oxidized nitrogen in an urban area, and the proximity of confined animal operations.

Given the use of regional PM modeling, it is instructive to compare the modeling conducted here with similar studies, in particular BRAVO and SAMI, as well as other applications of PM regional models. In the SAMI study, the Urban-to-Regional, Multiscale (URM) model was used (Odman et al., 2002), and used the Decoupled, Direct Method (Yang et al., 1997) to assess source impacts and response to controls. They also assessed the response of PM levels to emissions changes corresponding to varying levels of controls. Results of their modeling was used to calculate the expected changes in visibility, stream health and ozone damage (SAMI, 2002). Model simulations led to FPM mass having an normalized error of under 50%. Sulfate and elemental and organic carbon simulations also found errors on the same order, but nitrate predictions were high. Seigneur (2003) recently completed a report discussing regional modeling applications of CMAQ and REMSAD, two of the more commonly used regional PM models. The focus of this review was the model performance in the BRAVO, WRAP, Southeast US and various EPA studies. In general, model performance in the studies outside of the WRAP found PM predictions with a normalized error of 35-90%. Nitrate predictions had the largest

error.

SAMI air quality modeling dealt with many of the same issues being addressed currently by the WRAP (Odman et al., 2002). Specific issues addressed were quantifying the relationship

### IV-6 between emissions and various air quality endpoints, including PM levels, deposition and ozone. PM results, which were by species, were used for visibility calculations. Specific results of relevance here include:

• PM reductions were sub-linear to controls, and that the degree of sub-linearity increased as PM concentrations decreased. For example, when sulfate concentrations were highest, a 10% reduction in SO2 emissions resulted in an approximately 8-9% reduction in sulfate. At lower sulfate levels, the same 10% reduction led to a smaller percentage change. For nitrate, the sub-linear response was greater. A 10% reduction in NOx led to about a 5% reduction in nitrate, averaged over the year.

• Reductions in sulfate led to an increase in nitrate levels.

• Increases in ammonia led to an increase in nitrate.

• Nitrate formation was generally ammonia-limited.

These findings are important both individually and collectively. Over the next few years, SO2 emissions are expected to decrease and ammonia emissions are expected to increase, both leading to increases in nitrate. SAMI results suggest that these increases will be relatively small, but non-zero. However, in many locations, they offset the 27-63% reductions in NOx, such that nitrate actually increased. It is difficult to translate how similar changes will impact the WRAP regions, particularly since the WRAP regions are more heterogeneous. However, the preliminary results from the CMAQ modeling suggest that nitrate formation is ammonia-limited in a large part of the West. The sub-linear response suggests that controls will not get as much reduction as might originally be expected. However, the greatest fractional improvements will occur on the most heavily impacted days.

A final reference that provides a good overview of the issue is the NARSTO Assessment (NARSTO, 2003). It provides a more thorough discussion of many of the issues contained here, as well as conceptual models of PM dynamics in a number of areas of the United States.

Conceptual Model of Primary PM and Nitrate Dynamics in Western Airsheds

Here, conceptual models are developed to help elucidate the dynamics of both primary and nitrate PM in various western airsheds, starting with primary coarse and fine PM, which are not as involved with gas-to-particle conversion and less complicated. Note, secondary species can condense on primary PM, so even primary species can impact the formation and properties of secondary material.

Coarse PM is typically emitted by mechanical processes, e.g., grinding operations, transport of solid materials, road dust and wind blown dust. Further, CPM is typically emitted near the ground, not from tall stacks. In part, this is due to controls on large point sources. CPM has a relatively short lifetime, on the order of a few hours, though particles at the upper end of the coarse mode will have very short lifetime. For wind blown dust, this is much of the mass. Primary CPM can be attacked by nitric acid, and because of the shorter lifetime, act as a sink of

### IV-7 nitrate PM. Given total primary CPM emissions of 70 tons per year (tpy) (1/2 of the total PM10 emissions), one can develop a first order estimate of the contribution to total PM in the region by dividing by the approximate volume of the boundary layer in the WRAP area (~10 15 

### m 3 

### ), and multiply (~1 hr) by the lifetime. This leads to an average contribution of large point sources to PM of 0.005 ug/m 3 

### , a small fraction, again, on average. However, high levels of CPM are often very episodic (dust storms) or very local: i.e., within a few km of the source. Further downwind, the emissions have deposited and been diluted.

A portion of the CPM can be secondary, e.g., due to reaction of nitric acid on the surface of the aerosol, or condensation. Measurements suggest that a non-insignificant fraction of the nitrate in the regions outside of the California valleys is coarse. As discussed below, the existence of CPM nitrate is important from a control point of view. CPM nitrate is less likely to be reduced from reductions in ammonia as compared to FPM nitrate.

From this conceptual model of CPM, driving points are:

• CPM is predominantly primary, with a fraction due to gas-to-particle conversion, e.g., by the reaction of nitric acid with pre-existing particles,

• CPM has a relatively short lifetime,

• CPM can act as a sink for nitrate, and

• CPM is typically episodic, often occurring during periods with large amounts of windblown dust.

Primary FPM is emitted, often as a combustion by-product, in to the atmosphere, where it undergoes transport, growth, deposition, rain-out and a variety of other processes. The size of such emissions are typically in the ultrafine region, though from some processes the average particle size can be larger, e.g., as fine and coarse PM (e.g., cement manufacture). If emitted as an ultrafine, the small particles will likely grow in to the accumulation mode via condensation of other compounds to it (primarily) and coagulation with other particles, staying as FPM.

Primary FPM is transported very efficiently, essentially as a gas, since its sedimentation velocity (the rate at which it falls due to gravity) is very slow. As such, it will follow the prevailing winds and be distributed vertically and horizontally due to atmospheric turbulence. Removal of FPM occurs due to wash-out (e.g., rain and snow) and dry deposition. Dry deposition is slow, slower than many gases, due to the slow transport of FPM across the fluid dynamic boundary layer near solid surfaces (gases diffuse much more rapidly than particles) and low sedimentation velocities. As an example, for a 1 um particle, the deposition velocity is on the order of 5x10 -4 

### m

s -1 

### . Using a boundary layer height (e.g., the well mixed portion of the atmosphere near the earth’s surface) of 1000m, this leads to an atmospheric lifetime of about 3 weeks, and the particles will be transported out of the region before depositing. Larger particles will deposit somewhat faster as their sedimentation velocity is higher (the particles are heavier), and very small particles will as well since they diffuse faster. With such long lifetimes, wash-out can be very important, particularly in areas that have frequent rains. Depending on the intensity of the

### IV-8 rain, FPM can be very effectively removed, such that the lifetime of the FPM is very directly linked to the frequency of rain. Without rain, FPM is generally transported out of the airshed or, as will be discussed for nitrate, be lost due to some other process. The lifetime due to transport in the region is on the order of 10 days. Using this, along with assuming that one half of the primary PM emissions from stationary sources (Seignuer et al., 2003) are fine, one calculates that the average primary FPM levels would be on the order of 1 ug/m 3 

### . This is somewhat above what is measured as crustals in most locations, and more in line with the measured organic carbon. However, organic carbon would be due more to wood boilers and internal combustion engines. Using just those emissions, the average contribution to the organics would be less than 0.1 ug/m 3 

### . This is in line with source apportionments that suggest a large fraction of the organic carbon is due to biomass burning and other processes (e.g. Maykut et al., 2003). The stationary source emissions estimates would suggest that primary FPM from stationary sources may have a regionally significant impact, though this calculation is conservative and does not take in to account rainout and other loss processes.

If the primary FPM is emitted from the stack of a large point source, it will be transported in the plume with the gaseous pollutants and can undergo somewhat more rapid growth due to the concentration of condensable compounds. It may also be transported above the well mixed boundary layer, delaying the dry deposition loss mechanism, at least temporarily. When the mixed layer grows to capture the plume, the FPM will be diffused downwards. Given the cloud heights relative to the typical effective plume height, washout will typically remove FPM from plumes.

During transport, primary FPM can grow. Growth will depend upon the particle size and composition. Of particular importance is the hygroscopicity of the compounds in the particles. Some compounds will readily absorb water, such that in a humid environment, they will grow significantly, e.g., doubling in size. If the compound is hydrophobic, they will undergo more slow growth due to condensation of other compounds. Water is not the only compound that will be selective as to which particles are most readily absorbed. Semi-volatile organic gases can have a preference for particles with similar-structured organic matter already present. SO 2 

### (g) can be absorbed in to particles that already contain water, and then oxidized to form sulfate. Nitric acid will prefer non-acidic particulate matter. Important here is to recognize that a primary particle will interact with its environment, and end up as having both primary and secondary components. From a visibility standpoint, this is important since the growth can make the particles more efficient at degrading visibility. While the argument could be made that the condensable species would find some other process to form particulate matter without direct emissions (e.g., nucleation, followed by condensation), there is an abundance of water that would not necessarily do so. Further, as compounds such as sulfate condense on primary FPM, they can become more hygroscopic. Since primary emissions of FPM can undergo atmospheric growth, it is not directly apparent that decreases in FPM emissions will lead to the same level of decrease in FPM in the atmosphere. Indeed, greater reductions may be realized if the nuclei provided by the primary FPM is a limiting factor in the formation of secondary FPM. On the other hand, the observed effects may not be as enhanced since the condensable species will find other particles.

### IV-9 From this conceptual model of primary FPM, driving points are:

• FPM has potentially long lifetimes in the atmosphere,

• Wash-out is an important loss mechanism,

• Ultrafine primary FPM can grow in to a size range that is efficient at scattering light,

• Hygroscopic FPM can pick up water and become diffusive, and

• Even if emitted from tall stacks, primary FPM can be diffused downwards to the surface.

Particulate nitrate dynamics is significantly more complex than for primary PM because of the added chemistry and gas-to-particle/particle-to-gas conversion. While there is a small amount of primary nitrate emissions, most of the particulate nitrate in the troposphere starts out as NO x 

### which was emitted from a combustion process. NO x 

### , which is well known for its role in the formation of ozone, can be oxidized to nitric acid via two important pathways. During the day, NO 2 

### is oxidized by the hydroxyl radical:

3 2 

### HNO OH NO →

 +



### This reaction is responsible for most of the nitric acid formation. A second route takes place mostly at night. First, NO 2 

### is oxidized by ozone to the nitrate radical, NO 3 

### :

2 3 3 2 

### O NO O NO + →

 +

(The nitrate radical should not be confused with the nitrate ion, NO 3 - 

### ). Next, the nitrate radical reacts with NO 2 

### to form dinitrogen pentoxide, N 2 

### O 5 

### :

5 2 3 2 

### O N NO NO →

 +

N 2 

### O 5 

### then reacts with water to form two nitric acid molecules:

3 2 5 2 

### 2 HNO O H O N →

 +



### This reaction is slow in the gas phase, but can occur rapidly on the surface of a particle that contains water. However, the rate of this reaction is very uncertain, and it is believed that the rate used by CMAQ in the past may be too high (Dennis, 2003, personal communication), leading to an over prediction of PM nitrate. NO 3 

### photolyzes very rapidly, and during the daytime it is found at very, very low levels, blocking this formation route when the sun is up.

The nitric acid gas formed from the above reactions can dry-deposit out, be washed out, or undergo gas-to-particle conversion. Nitric acid reacts very rapidly with surfaces, and deposits out rapidly. It’s lifetime to dry deposition is on the order of a few hours. Nitric acid is also very soluble, and is removed effectively by rain.

### IV-10 In terms of particulate matter formation, nitric acid is a strong gas and can attack pre-existing particles, being adsorbed or displacing other compounds present. For example, nitric acid gas can displace chlorine in a sea salt-derived particle, leading to sodium nitrate and HCl(g). Likewise, it can react with alikilinic crustal material to form PM nitrate (e.g., Malm et al., 2003). In both such cases, the particulate nitrate formed is in the coarse fraction because the original particle was in the coarse mode. In many regions, the route to forming FPM nitrate is via the gas phase reaction between nitric acid and ammonia (NH 3 

### ): ) aerosol ( NO NH ) g ( NH ) g ( HNO 3 4 3 3 

### →

 +

followed by gas to particle conversion. The reaction is reversible, and the ammonium nitrate can thermally decompose. The forward and backward reactions are fast enough such that the two reactions are often considered to be in equilibrium:
) aerosol ( NO NH K ) g ( NH ) g ( HNO 3 4 3 3 

### → ← +



### where K is the equilibrium constant. Thus, the fraction of nitrate formed is very sensitive to the abundance of ammonia available, as probed later. In areas with substantial quantities of ammonia, large amounts of nitrate can be formed (e.g., in areas with confined animal operations). In areas with relatively little ammonia, or where the ammonia available is bound as ammonium sulfate (or ammonium bisulfate), very little nitrate is present. Another factor is that the equilibrium constant is very temperature dependent, and at higher temperatures, the gas phases of the two compounds is preferred. The equilibrium makes the formation of ammonium nitrate very nonlinear. In some cases, e.g., in an environment rich in ammonia but with little nitric acid, the ammonium nitrate levels are governed almost solely by the available nitrate (e.g., nitric acid formation), and ammonia reductions will have little impact. If ammonia is low, it is the controlling species

Surprisingly, nitrate levels, locally, may go up when NOx emissions are decreased. This is analogous to the disbenefit found in the response of ozone to NOx emissions. Regionally, NO x 

### reductions will reduce ozone because NO2 is needed to form ozone. However, locally, reducing NO x 

### can lead to local increases in ozone for two reasons. The most easily understood is that NO x 

### is primarily emitted as NO, which titrates ozone. This is important at night. During the day, NO 2 

### reacts with the hydroxyl radical, significantly lowering OH levels. This decreases the rate of VOC oxidation, which reduces the rate of NO oxidation to NO 2 

### , which reduces ozone formation. Most of the hydroxyl radical formed comes from ozone photolysis, so lower ozone reduces OH formation. Thus, there is a positive feedback. NO x 

### emissions increases decrease ozone, decrease OH, and decrease the rate at which NO 2 

### is oxidized to nitrate, locally. Regionally, more nitric acid will be formed. In the SAMI study, this appeared to be a second order effect.

Complicating the nitrate formation issue is the presence of other condensed phase species, in particular sulfate. As noted above, ammonium nitrate formation is very sensitive to the availability of ammonia. SO 2 

### oxidation, which is faster in the summer when hydroxyl levels are highest, leads to the formation of sulfuric acid, H 2 

### SO 4 

### . Sulfuric acid reacts with ammonia to form ammonium bisulfate [(NH 4 

### )HSO 4 

### ], and if enough ammonia is present, ammonium sulfate

### IV-11 [(NH 4 

### ) 2 

### SO 4 

### ]. Ammonia will preferentially react with sulfate to form the above two species before reacting with nitric acid to form ammonium nitrate. As such, the presence of sulfate will reduce the amount of ammonia available to form ammonium nitrate. In many cases, there is so little free ammonia that ammonium nitrate is not formed. On the other hand, nitric acid that has reacted with sea salt or crustal material to form sodium/calcium nitrate does not require ammonia, so there can be some aerosol nitrate even in high sulfate areas, though typically not as much as in high ammonia/low sulfate areas.

The interaction between sulfate, nitric acid and ammonia has implications for the “lifetime” of nitrate in the atmosphere as sulfate is reduced: decreasing sulfate will make more ammonia available to form PM nitrate, reducing nitric acid gas levels. The PM nitrate deposits much less rapidly than nitric acid, so the total abundance of nitrate in the atmosphere will increase. Thus, decreasing sulfate levels may lead to somewhat more nitrate than is expected from just considering the amount of nitric acid currently available to form PM nitrate.

Sulfur dioxide reductions will lead to the reduction of sulfate particulate matter, and hence, can lead to more ammonium being available to form ammonium nitrate, leading to what is referred to as the “rebound effect”. In this case, the sulfur dioxide controls will not lead to the expected (or desired) reductions in particulate matter because as sulfate decreases, nitrate increases due to the availability of ammonia in a condition where nitrate formation was ammonia limited. This was found to be true in the SAMI study to a limited degree.

One issue that should be addressed is the impact of certain NOx controls on increasing ammonia emissions, e.g., SCR and SNCR. Compared to other sources of emissions, such controls would represent a very small fraction of the total ammonia emissions. However, in the plume, the ammonia emissions might be high enough to lead to an increase in ammonium nitrate, and hence impact visibility in concentrated plumes.

Washout is very important to nitrate levels. Not only will rain remove the nitrate aerosol, but will also remove nitric acid gas and ammonia very effectively. Clouds can also increase the oxidation of SO2 to sulfate, which captures ammonia, and is also washed out. Some of the lowest FPM levels are found following a rain storm.

From this conceptual model of PM nitrate, driving points are:

• PM nitrate formation is due to both gas and heterogeneous reactions forming nitric acid from nitrogen oxide emissions, followed by gas-to-particle conversion,

• FPM nitrate is largely due to reaction with ammonia, while CPM nitrate is due to reactions of nitric acid on a preexisting particle,

• Reducing ammonia can reduce nitrate formation in areas that are “ammonia limited”, but may have little impact in areas where there is an abundance of ammonia, and

### IV-12 • NOx controls can reduce nitrate in areas where ammonium nitrate formation is nitrate limited, as well as areas where nitrate is formed from the reaction of nitric acid on pre-existing particles.

This conceptual model is diagrammed in the figure below. It should be noted that this figure, or the discussion above, does not have all of the complexities leading to nitrate formation. The atmospheric chemistry involves hundreds of compounds, and thousands of reactions. Describing the physical processes is equally complex. The systems of equations governing the pollutant evolution are non-linear. Pollutants evolve spatially and temporally. For such reasons, complex computer models are generally used to study the details of the pollutant dynamics. However, a good picture of the system dynamics, and an understanding of the importance of various processes can be developed from a simplified, zero-dimensional model.

While very simplified, a zero-dimensional model can be used to demonstrate the important features and resulting formation and loss of particulate nitrate. In this case, the model includes the formation of nitric acid, peaking during the day, an increase in temperature during the day, going from 10 to 30 C, the increase in the equilibrium constant with temperature, deposition of nitric acid, and a constant level of ammonia/ammonium. The result is that the highest levels of PM nitrate occur at night and the early morning, going to zero during the hottest parts of the day. Nitric acid peaks during the day when all of the ammonium nitrate has dissociated. Most of the nitrate deposits during the day since nitric acid is so reactive with surfaces. In the SAMI project, the deposition of oxidized nitrogen due to nitric acid was about an order of magnitude higher than for PM nitrate, due both to the higher nitric acid levels and deposition velocities.

One of the important features of this system is that while ammonium nitrate does not deposit rapidly, nitric acid does. Thus, an ammonium nitrate aerosol will disappear relatively rapidly in a continual, two-step process: the nitric acid gas deposits rapidly as a gas. The ammonium nitrate will thermally decompose to replace the lost nitric acid. The nitric acid released will then deposit out, etc.. At higher temperatures, i.e., when a significant amount of the nitrate is in the

### IV-13 gas phase, this process can be rapid. In cold areas, almost all of the nitrate will be bound as ammonium nitrate, and the thermal decomposition is slow, so the process is inhibited.

A multi-day observation of aerosol nitrate levels is shown in Figure 2, along with the temperature trace. As shown, nitrate goes up in the morning due to NOx oxidation along with low temperatures. As the temperature increases, the nitrate decreases and goes to near zero during the day. While not shown, sulfate also increases during the day, scavenging ammonia and further decreasing nitrate levels.

Particles and Visibility

As noted previously, particles can degrade visibility. The three primary mechanisms are Mie, Rayleigh and Geometric scattering, and absorption. Only a few types of particles absorb visible light effectively. Most notably is elemental carbon. Mie scattering occurs from a complex interaction between light waves and particles of a size similar to the wavelength of light (visible light ranges from about 0.2 to 0.8 um). Larger particles scatter and block light. Air molecules also scatter light (Rayleigh scattering), limiting visibility on even the cleanest days.

Visibility, or visual range, x v 

### , is often calculated using the Koschmeider formula:

ext v 

### b x 912

. 3

=

where b ext 

### is called the extinction coefficient, and is generally given in Mm -1 

### . The extinction coefficient is calculated by accounting for all of the processes scattering and absorbing light. While very complex formulas have been derived, a useful parameterization that corresponds to he air quality data usually available from IMPROVE and other sites is:

] [ 10 ] [ 6

. 0 ] [ ] )[ ( 4 ]) [ ] )([ ( 3 LAC CPM Soil Organic RH f Nitrate Sulfate RH f b org T ext 

### + + + + + =

### IV-14 where f T 

### (RH) is a function to account for sulfate and nitrate absorbing water (f org 

### (RH) is a similar function for organic material), [Sulfate], [Nitrate], [Organic] and [Soil], are the measured masses of the corresponding fine PM constituents, and [LAC] is the measured mass of the “light absorbing carbon” similar to EC, (depending on measurement technique). The latter term accounts for absorption. At relative humidities (RH) above 40%, f T 

### (RH) is greater than one, going up to above 5. However, f org 

### (RH) is taken as one. Given this, one sees that, on a mass basis, sulfate and nitrate are usually more effective at scattering light than organics, soil and CPM. LAC is very effective at absorbing light, and a small amount can lead to significant light extinction. Another measure of visibility impairment is the deciview (Pitchford and Malm, 1993). It is proportional to the log of the extinction coefficient and relates to the perception of haziness. Given the non-linear nature of the relationship between deciviews and extinction coefficient, but the linear relationship between extinction and PM composition, for the purposes of this report, it is easier to consider extinction.

Regional Conceptual Models

The above description of the formation and fate of primary FPM and nitrate was done for a general case, without consideration of regional differences in either the processes impacting primary FPM and nitrate. In the West, many such regions exist. To provide a better understanding of how such differences manifest themselves, four sub-regions of the WRAP are identified based on their meteorological and FPM characteristics. The four regions are: wet coastal, dry mountainous, southwest desert, and California valleys. Wet coastal regions include the coastal regions starting in northern California to the Olympic Peninsula, and include the coastal mountains. The dry mountainous sub-region includes the Rockies, the Sierras, and other drier mountainous areas. The southwest desert region would include non-mountainous areas in Arizona, New Mexico, Colorado and Nevada. California valleys include the Los Angeles basin and the surroundings (including the mountainous and desert areas downwind) and the Central Valley and surrounding mountains. A fifth case, considered separately, but not as a separate region, “in-and-near,”., i.e., those regions that have significant sources of PM either directly within or nearby. For example, a Class I area near a major city or facility with very large emissions, or if the activities within a Class I area led to significant emissions. The IMPROVE investigators have dissected the west in to 15 regions, which is more than is needed for developing the conceptual models as done below. However, which “IMPROVE” regions fall in to each of the four given below are noted.

Wet, Coastal Subregion

This subregion occurs along the Pacific coast and the Puget Sound, in to the coastal mountains and the Cascades. As such, it includes the IMPROVE Pacific Coastal and Cascade Mountains. As the name implies, this region tends to be wet, and is known for rain, and can also experience intense coastal storms. The temperatures tend to be cool. There are a few population centers in this region (e.g., Portland and Seattle).

PM levels in the coastal region tend to be low, e.g., on the order of a 3-4 ug/m 3 

### average over the year (Malm et al., 2003). Average levels of nitrate and primary FPM are very low: 0.2-0.8 ug/m 3 

### , though nitrate is higher in the Puget Sound and Columbia Gorge areas (Malm et al.,

### IV-15 2003). The rain removes FPM and its precursors and coastal winds ventilate the region. The cloudiness of the area inhibits the rate of oxidation of NO2 to nitric acid. There are relatively fewer sources of FPM and precursors in the region. Higher levels of FPM are experienced in the population centers. In the Class I areas, FPM tends to be primarily sulfate and OC, with little nitrate and primary material. Biomass burning (e.g., forest fires) appears to be a major contributor in some areas, as suggested by high OC levels, particularly during some very high events. In terms of the general conceptual model, discussed above, particulate nitrate can be formed from the reaction of nitric acid with sea salt. Ammonium nitrate formation in the area appears to be limited by the presence of both free nitrate and ammonium. On the other hand, the cool temperatures promote converting what little available nitric acid and ammonia is available in to ammonium nitrate. Without further investigation (e.g., longer term, detailed modeling) it is difficult to tell how nitrate will respond to controls, but it is likely that the formation is limited by NOx emissions, not ammonia. Results from the WRAP modeling suggest that part of Oregon is ammonia sensitive (Tonneson, 2003).

The days with the most severe visibility impairment appear to be impacted most heavily by organics (particularly during severe episodes) and sulfate.

Dry, Mountainous Subregion

This region includes the more inland mountains, and would contain the Sierra Nevada, Wasatch, Northern Rocky, Sierra-Humboldt and Central Rocky Mountain IMPROVE regions. These areas are much drier than the coastal mountains. While not immune to rain and storms, they are less frequent, particularly during the summer. Temperatures tend to get hotter during the summer. During the winter, temperatures can get quite low. The area has a relatively low population density, and few major source regions, though is relatively agricultural. Major point sources include utility boilers, and smelting operations. Confined animal operations can lead to areas of very high ammonia. Forest fires, particularly in the northern mountainous areas (e.g., Montana and Idaho) and the Sierras can lead to very large PM concentrations during episodes. In such cases, OC dominates mass.

FPM levels in this region are low, around 2-5 ug/m 3 

### in Class I areas. Again, cities have higher levels. Nitrate and primary FPM levels are a small fraction of the total (0.1 to 0.4 ug/m 3 

### , except in the regions of the Sierra Nevada that are influenced by emissions in the Central Valley), particularly during the some of the most polluted events that are dominated by sulfate. Given the low levels of nitrate, and the likely higher ammonia emissions, nitrate formation is likely limited by nitric acid formation from NO 2 

### . Simulations by UCR tend to suggest a mixture of sensitivities (Tonneson, 2003).

The days with the most severe visibility impairment appear to be impacted most heavily by organic matter or sulfate, though some events have very high levels of coarse mass as well. Nitrate tends to be a relatively small contributor, which is to be expected when sulfate is high. Because the measurements can not distinguish as to the source of primary PM, it is not immediately apparent as to the source of the coarse mass, but given the episodic nature, it is likely that the primary PM is natural in origin.

### IV-16 Southwest

This region includes the far eastern part of southern California, Arizona, New Mexico, southern Colorado and Nevada. IMPROVE regions corresponding to this region are the Great Basin of Nevada, the Colorado Plateau and Sonoran Desert. The Southwest has features similar to the Dry Mountainous subregion, being dry and having low FPM levels. It differs in that temperatures tend to be higher, and there is a greater abundance of major point sources of NOx and FPM. Biogenic sources in much of the southwest are very small, but appear to be a major component of the OC nonetheless (Brown et al., 2000). Ammonia emissions are less dense, though crustal material can be higher from wind blow dust as this area finds higher soil concentrations than the others (Malm et al., 2003).. While more detailed modeling is needed, it would appear that the higher levels of sulfate measured, and the apparently lower levels of ammonia emissions, would make this area ammonia limited much of the time.

The days with the most severe visibility impairment appear to be impacted most heavily by sulfate, OC and nitrate, though some of the events with the lowest visibility have very high levels of coarse mass, likely associated with dust storms. There are periods with very high levels of OC, indicative of major biomass burning events (forest fires).

California Valleys

This subregion is the most distinct of the four, and includes California’s Los Angeles Basin and the Central Valley, and the areas most directly impacted by transport from these regions (e.g., downwind of Los Angeles and the mountains directly along the valley, including part of the Sierra Nevada). This region is relatively dry and warm. There are periods of significant stagnation. Most importantly, this region has greater emission densities of the pollutants impacting nitrate PM, in particular both NOx and ammonia. These characteristics lead to substantially higher FPM levels, especially for nitrate. Nationally, this region has the highest nitrate levels.

Of all the regions, most is known about the dynamics of PM here due to a history of studies being sponsored by the state of California, industries and others. In Los Angeles, the high nitrate levels are due to the large emissions of NOx, e.g., from mobile sources, confined animal operations leading to high ammonia emissions, low ventilation rates concentrating both sets of emissions, and plentiful sun, oxidizing the NO2. In parts of the basin, e.g., before the air masses pass over the confined animal operations, nitrate formation is ammonia limited. Further downwind, the formation becomes nitrate-limited as there are plentiful ammonia emissions and the nitric acid continues to deposit out. The highest nitrate levels are found in the fall when the sunlight still leads to rapid oxidation of NO2, winds are light, there is little rain, and the temperatures are lower favoring the formation of ammonium nitrate. On hot summer days, the ammonium nitrate thermally decomposes, though large amounts of nitrate can be present during the cooler hours.

The Central valley shares some of the characteristics of the LA basin, but has some unique features. First, the sources of NOx differ, having a larger non-mobile component, and being less dense. There are widespread agricultural and animal operations leading to ammonia emissions

### IV-17 throughout the valley. There can be long stagnation events with fog and very little ventilation. During these stagnation events, nitrate levels can build.

An interesting study of the NOx-nitrate relationship was recently completed for the San Joaquin Valley using a box model (Stockwell et al., 2000). They found that for each gram of NOx emission, approximately 0.6 grams of nitrate is formed. This is a high ammonia region, so while those results are in general agreement with field measurements in the region, the extrapolation of those results elsewhere is limited.

For both areas, the days with the greatest visibility impairment are high in nitrate, OC and sulfate, with episodes of coarse material.

In and Near

A few Class I areas lie very near a major source region (e.g., a city) or specific source (e.g., a major highway, mining operation or power plant). In this case, the PM levels can be higher than experienced by the rest of the region, and have a different composition. Examples that are near source regions include San Gorgonio (downwind of Los Angeles) and Casa Grande and Tonto National Monuments near Phoenix. In this case, the PM takes on a characteristic that is a blend between these in the urban area and the regional background. For example, this can lead to elevated nitrate, as particularly found in San Gorgonio, and organic and elemental carbon. For areas near major sources, the PM can be enriched in the compounds being directly emitted by the source. Secondary pollutants, particularly sulfate, take longer to form, so there is less of a direct impact, but some enrichment is likely (e.g. Grand Canyon Visibility Transport Commission, 1996; Pitchford et al., 1999). Pollutant dispersion reduces the apparent source impact relatively rapidly, so after a few 10s of km, the impact from that source is reduced by an order of magnitude or so. This is particularly true for CPM which also deposits rapidly. Also, human activities within a protected area (e.g., driving, fires, etc.) can contribute to locally higher PM levels. However, these sources are outside of the subject of this study, do not appear to be a significant contributor to visibility degradation regionally, and are not dealt with further here.

Particulate Matter Modeling



### Currently, the most scientifically well-founded approach to assessing how future emissions changes will impact air quality is to use a physically and chemically comprehensive air quality model that describes the evolution of pollutants in the atmosphere. Such models (actually, multiple models are used) are complex, and are run on fast computers. The WRAP is now using such an approach. In particular, the WRAP is using the Models-3 suite of models, including SMOKE for emissions, MM5 for meteorology and CMAQ for air quality, including particulate matter. MM5 is one of the most widely used meteorological models, and CMAQ is an increasingly popular air quality model.

MM5 solves the equations governing the motions of the atmosphere. These equations are very complex and non-linear, and sensitive to boundary and initial conditions. The model uses a variety of parameterizations to simulate various processes. For some processes, MM5 has more than one choice of parameterization since no one approach appears to be universally best. This,

### IV-18 in part, shows the complexity of meteorological models, and that modeling errors can be expected. Errors can grow with time, degrading performance in longer simulations if nothing is done to constrain the growth. For this reason, data assimilation is used where observations are used to adjust the results as the fields evolve. As such, the model results are sensitive to model inputs (including initial and boundary conditions), model parameterizations and errors in the data used in the assimilation. While MM5 often achieves very good performance, there are events where good performance is elusive.

CMAQ is a comprehensive chemical transport model, developed primarily by the US EPA and funding from that agency. It represents the state-of-the-science in most aspects, and has been developed for use by the modeling community. Its use by the community is, in part, to help it evolve and continuously improve. CMAQ contains processes describing gas phase chemistry, aerosol dynamics, dry and wet deposition, pollutant transport and more. A common configuration of CMAQ uses CB-IV, a rather older, simplified chemical mechanism, though versions exist with RADM-II and SAPRC-99, two of the newer, most comprehensive and well tested mechanisms.

All three models have been used in a variety of efforts in the past. MM5 and CMAQ, the two predictive models, have been able to show good performance, at least for some species, though performance can vary from site to site and study to study. Since CMAQ uses the results from MM5, poor performance by MM5 can lead to similarly poor performance from CMAQ. However, even with ostensibly good performance from MM5, CMAQ may not perform well due to poor emissions inputs and/or problems with CMAQ itself, e.g., how it treats various processes. Further, here, CMAQ is being applied using a 36 km grid resolution. Such large grids are not appropriate for assessing the impact of a point source of CPM on nearby areas because of the rapid deposition of the larger particles, and the artificially large dilution of the emissions over the 36x36 km grid.

Model Performance Issues

Confidence in using such a model is derived from successful evaluation of the results. What constitutes good model performance varies by pollutants, and for FPM there is no standard criteria. Recent modeling efforts have found errors for sulfate to be within about 50%, OC within a similar range, and nitrate within about 100% (Seignuer, 2003). However, current model performance found for the WRAP effort suggests poor model performance for some species, particularly nitrate (up to a factor of 10 high in the winter, but some days with essentially no nitrate formation simulated in regions where nitrate is monitored to be present). It is difficult to assess the model performance for primary FPM from stationary sources since the measurements and the model results are not able to support such an evaluation. How does poor model performance affect the use of the results, in particular for quantifying the likely impact of emissions changes?

First, it is important to understand the likely reasons for the poor nitrate performance. It is unlikely that the NOx emissions estimates are very far off, so other problems likely exist. Ammonia emissions are much more uncertain, and can be part of the problem. Also suspect is the deposition rate used for nitric acid (too low) and the nighttime, heterogeneous oxidation of

### IV-19 NOx to nitric acid (too high), both leading to higher levels of nitrate. The reasons for having too little nitrate during the summer (e.g., no nitrate is sometimes predicted when some is observed)may be because the nitrate present is particulate nitrate formed from nitric acid attacking preexisting particles to form a thermally stable form of particulate nitrate (e.g., soil material and salt), slight overestimates in the amount of sulfate formed or underestimates in the ammonia emissions. Monitoring has found that a significant amount of the nitrate in Class I areas outside of southern California is larger FPM or coarse, suggesting that it is formed from nitric acid attacking pre-existing aerosol forming a thermally stable form of nitrate. If this is the reason for the discrepancy, and that ammonium nitrate is not present, then the modeled sensitivity to emissions reductions will be very different than would occur. In particular, an area that might appear to be ammonia limited from the modeling, may be nitrate-limited, and most sensitive to NOx emissions.

A large error indicates that either the sensitivity to emissions changes is in error, or there is a large error in the emissions. If the latter were true, the model results could be used to scale observed levels to get a reasonably good approximation of how the ambient levels would respond. The decision was made, in advance, in SAMI to use scaling, even for the species where very good performance was found. Note, if performance is perfect, the same results are found if one uses scaling or the model results directly. Thus, the approach is asymptotically correct.

If model performance is poor, scaling the observations with model results becomes more questionable. Given the very large errors found for nitrate, the low correlation between observed and simulated levels, and that NOx emissions are relatively well known (probably well within a factor of two), the modeled sensitivity of nitrate levels to NOx emissions could be well off. Indeed, the very low observed nitrate, versus that simulated, suggest that much of the time the model is in a different regime than the actual atmosphere (e.g., the case where the two species, ammonia and nitric acid, are in sufficient supply to form aerosol nitrate vs. the case where one or both are at concentrations low enough to negate ammonium nitrate formation, and what little nitrate found is due to reactions of nitric acid with a crustal material or sea salt). Performance is worst during the winter, but during the summer there are days where no nitrate is predicted, though some is observed. In this case, NOx controls will not lead to any change in predicted nitrate, so scaling will not show any benefit. Given the performance problems, it is difficult to suggest if the sensitivity of either the annual nitrate levels, or the nitrate levels on the days with the most limited visibility, is adequately represented by the model.

One issue concerning the use of scaling is that it does not account for spatial inhomogeneities in the controls. For example, control at a specific source, even though it is a very small fraction of the total inventory, will have an enhanced local impact, though little impact further away. This issue can be dealt with by using the model to develop source-receptor relationships, and use those results to help guide the scaling.

For primary fine and coarse PM, the response of ambient PM is likely to be quite linear (though not totally due to particle growth), so scaling should work relatively well, as long as the issue of spatial inhomogeneities in the emissions controls is adequately addressed. This can be relatively easily tested using a single model simulation.

### IV-20 At present, the simulations have not been conducted to provide a complete source apportionment of the PM. By this, one means exercising the model to show how each source (or group of sources) impacts PM at specific receptors (e.g., the Class I areas). Such a calculation can be very helpful in suggesting controls. Further, it is important to understand the magnitude of the problem with which we are dealing, and how to interpret model results and observations. In particular, this is important for primary PM. At most Class I areas, FPM is dominated by secondary species (nitrate, ammonium, sulfate and a fraction of the OC), and primary EC and OC. Other compounds are a relatively small contributor to both FPM mass and visibility. One question, for which the model can be used to help understand, is if a significant fraction of the PM is from stationary sources. If not, i.e., that stationary sources are a small fraction of the primary PM at Class I areas, and that primary PM is a small fraction of the total PM, reductions in primary PM emissions will have a rather small impact.

Effectiveness of PM and NOx Controls on PM levels and Visibility in the West



### As discussed above, nitrate is a major contributor to PM levels and visibility extinction in a few areas of the West, notably in California, and to a lesser amount the Columbia Gorge. In the southern half of California, nitrate can be the major constituent. In most other areas, nitrate is found at relatively small concentrations, around 5-20% of the total FPM. Likewise, point source primary emissions of PM, both coarse and fine, are a small contributor, regionally, as well. Thus, controls on point source emissions of NOx and PM will have a relatively limited effect on both PM and visibility in much of the West, all else being equal. The latter clause is important because, as SO2 emissions are reduced, and ammonia emissions increase (as is forecast in many areas), aerosol nitrate may become a more significant contributor, as was found in SAMI.

In and around the California valleys, nitrate formation appears to be nitrate limited. As noted above, Stockwell et al., (2000) found that one gets, roughly, about 0.6 grams of nitrate (as ammonium nitrate) per gram of NOx emissions. This would suggest that, in these areas, NO x 

### controls will reduce nitrate levels. The exact level of benefit will have to come from either analysis of the measurements or modeling after performance improves. The California inventory suggests that about 478 tons per day (tpd), or about 14% of the 3441 tpd statewide, of NOx come from stationary sources. Assuming that stationary sources have a similar impact on nitrate formation (SAMI results suggest this is not totally true, Odman et al., (2002)), this puts an upper bound on the likely benefits of around 15%, and the results of the SAMI study suggest that the actual impact on nitrate mass is more around 7%. This translates in to approximately 2% of the total FPM in areas around Los Angeles where nitrate makes up about 30% of the total FPM and 1% in areas of California, such as the Sierras east of the Central Valley where nitrate is about 15% of the total FPM. In other areas, the stationary source contribution, on average, would be smaller, on average. Three considerations would increase the importance somewhat: on days with the worst visibility in these areas, nitrate makes up a larger fraction of the total (in some cases, over 50%) on days with the highest levels of nitrate, a greater fractional response to NOx reductions is suggested and if the receptor is directly downwind of a major point source, the impact would be increased. The first two considerations might lead to an increased impact of up to 5%. The latter consideration would be very site and meteorology dependent.

### IV-21 Elsewhere in the West, nitrate levels are relatively small: usually less than a ug/m 3 

### , and from 5- 10% of the total PM. The days with the worst visibility tend to be dominated by one of three cases: high CPM and crustal (indicative of dust storms), high organic and elemental carbon (which can indicate forest fires) or high sulfate, which tends to be elevated much of the time, and increases during stagnation. Thus, unless the increasing ammonia and decreasing sulfate lead to significant nitrate increases, stationary point sources will lead to only about 2% (or less) of the visibility extinction, except in areas significantly impacted by major sources. SAMI modeling suggested that there w ill be small additional benefits of NOx controls in reducing sulfate due to decreased sulfur dioxide oxidation. Thus, NOx controls will have a relatively small impact on PM and visibility in the West.

The impacts of primary PM controls on point sources are more difficult to assess at this time since the available data is less specific as to the fraction of PM from point sources. As noted above, CPM has such a short lifetime that reductions will have a small impact on PM levels and visibility, except very near the source. Primary stationary source FPM, while longer lived, still appears to be relatively minor, contributing less than 0.1 ug/m 3 

### , so controls on FPM would also have a minor impact on PM levels and visibility. This is in line with the results from studies such as those conducted at Mt. Zirkel (Watson et al., 1996). Total removal would lead to a decrease in extinction of about 0.4 Mm-1, or less than about 0.5% of the total extinction on a day with relatively bad visibility of about 20 miles.

The above analysis suggests that primary PM and NOx controls will have limited impact on visibility in the West in the near term, except in areas of California and areas directly impacted by specific stationary sources being controlled. Near-field impacts of sources needs to be conducted on a site-by-site basis. However, as sulfate levels come down, the impact of NOx controls will increase, both because nitrate levels will increase and due to the non-linear relationship between visibility and extinction. Locations whose visibility is currently dominated by sulfate may find that nitrate becomes the species of concern. Looking towards the future, it is prudent to identify the types of controls and mechanisms to increase their cost effectiveness.

Emissions Trading



### Emissions trading is viewed as an economically efficient approach to air quality management, as has been experienced through the acid rain program. However, when trading pollutant emissions, the economic efficiencies tend to decrease as limits are placed on trading, e.g., spatially, temporally, across sectors, and across pollutants. There are issues associated with each. Allowing spatially diverse trades can shift emissions reductions and the resulting air quality improvements.

Temporal trading can lead to decreased (or enhanced) benefits. For example, sulfate tends to be higher in the summer due to more rapid oxidation. If the trading results in greater reductions during the winter, average sulfate levels may decrease less than if the reductions were more uniform. On the other hand, if the SO2 reductions are greater in the summer, the benefits could be enhanced. This may be more critical for nitrate which, as discussed above, is very sensitive to temperature, and is thus found predominantly in the winter. Primary emissions would not be affected as much.

### IV-22 Trading across source sectors may be impacted by (1) the spatial and temporal trading concerns identified above, (2) that sources can emit at different elevations above the ground, and (3) that different sectors do not have the same PM characteristics. Emissions from a tall stack are in to a very different environment than a more dispersed ground level source. First, elevated emissions, e.g., from utilities, tend to be very concentrated in NOx, and the plumes can stay very NOx rich for significant distances. Ground level sources tend to be more disperse and in to environments with higher levels of VOCs. In recent field experiments, this has been found to have an impact on ozone formation efficiencies (e.g., Ryerson et al., 2001). Recent modeling has also found this to be the case for ozone and acid deposition, and nitrate FPM (Odman et al., 2002), though the differences were not as large as that measured for ozone. For primary FPM, this is likely a small impact, though ground level FPM emitted in populated areas would likely lead to a greater exposure than if emitted higher up. It is likely that the spatial and temporal issues are of greater concern. A final concern is that trading primary PM emissions between sectors can lead to a different type (e.g., predominant size) of PM being emitted. For example, utility emissions are likely going to be more fine than, say, cement production or mining emissions (as well as being emitted at different levels). CPM deposits faster, and impacts visibility less. Thus, removing a ton of CPM would not have the same benefit as removing a ton of FPM, all else equal. In this way, trading primary PM emissions between sectors is much like trading pollutant types, with the issues discussed below.

Scientifically, the most challenging type of trade is across pollutant types, e.g., SO2 for NOx, primary PM for NOx, etc. This is because it is difficult to quantify how much of one pollutant can be traded for another and have equal air quality benefits. The possibility of displacement reactions further clouds how such trades can be weighted. For example, reducing SO2 will lead to sulfate aerosol reductions. However, this can free up ammonium to react with nitric acid, leading to increased nitrate. While this was found to be the case in SAMI modeling, the “rebound effect” was not large. Finally, the different species will have different impacts, e.g., in terms of visibility reduction. For example, each fraction of the PM has a different impact on visibility per mass. Nitrate and sulfate have a greater impact, on a per mass basis, than soil or CPM. Further, sulfate and nitrate both have a greater impact on visibility at higher humidities, other constituents do not, generally leading those two constituents to have a bigger impact on visibility on a per mass basis than (say) organics. Conversely, elemental carbon is very effective at absorbing light. If one can correctly account for the relationships between emissions and the resulting concentrations, it is straightforward to account for the visibility impairment differences, though the relationships can change with time. For example, as SO2 emissions are reduced in the future, and ammonia emissions increase, the area could become more sensitive to NOx emissions. Thus, one ton of NOx reduction may become more valuable in relationship to one ton of primary FPM.

A final issue is that reducing NOx emissions will impact both secondary sulfate and OC formation. This is because NOx is central to the formation of ozone and increasing the oxidizing capacity of the atmosphere. Modeling as part of SAMI suggested that this secondary effect is small, but non-zero, impacting mainly the formation of sulfate. Typically, reducing NOx also reduced sulfate formation slightly, but in some locations NOx reductions led to small sulfate increases due to increasing H2O2 formation and the heterogeneous oxidation of SO2, as well as

### IV-23 increasing OH levels. In general, these secondary impacts will slightly enhance the effects of NOx emissions reductions, but can be ignored for now due to the larger uncertainties in quantifying the NOx-aerosol nitrate system response.

Given the complexities, the question arises is, if emissions trading is to be done, how should trading equity be established. If the trades are somewhat restricted to the point that there are no obvious resulting inequities (e.g., limited spatially and not across pollutants, and that there is little likelihood that there would be little temporal or elevation differences), policy makers could likely proceed without the use of some more extensive approach. However, this would severely restrict the market and the associated economic benefits. Dealing with the issues identified is ideally tackled using a comprehensive air quality modeling effort, such as is being done by the WRAP. In this case, the model could be exercised to identify the appropriate trading ratios and the inequities resulting from various trades.

A major problem at this time, as discussed above, is that confidence in a model’s use can only be developed through successful evaluation and good model performance for the species of interest. In the case of the WRAP modeling, nitrate performance was poor, and it would be difficult to use such results to assess how to make trades equitable, e.g., to develop trading ratios across pollutants. While less of an issue, using the model to assess trading SO2 for FPM is also difficult because of the rebound effect. When model performance is such that the WRAP is comfortable that the model is adequately capturing the physics and chemistry affecting pollutant evolution of the compounds of interest, then the model, presumably, can be used to determine how to make trades equitable. Note, this does not mean that performance for all species has to be good. Having poor performance for crustal species would not significantly impact the use of the model for comparing SO2 and NOx trades.

Given the successes achieved from emissions trading, it is important to identify model performance problems such that trading guidelines can be established in a sound fashion. None of the issues identified above are “show stoppers”. However, given the level of uncertainty in the modeling results at present, inter-pollutant trading would have the potential to jeopardize visibility improvements in the region.

Suggested Model Simulations



### At present, a few sensitivity simulations have been conducted using CMAQ. While conducted, in part, to understand model performance, they are providing insight into PM dynamics in the West. In particular, the cases where NH 3 

### emissions are being changed to find areas that are most sensitive to NH 3 

### emissions. Such sensitivity calculations are key to addressing trading issues and identifying effective control strategies.

After model performance is judged to be adequate, a number of calculations are suggested. A first set of calculations is to conduct a comprehensive source apportionment by source type (e.g., point, area and mobile), pollutant (SO2, NO x 

### , NH 3 

### , CPM and FPM), and location (e.g., state or region). The resulting matrix (a total of about 45 sensitivities) can be used to guide trading, assessing the impact of transport, identifying important source regions to pristine areas, and guiding control simulations. While 45 simulations may appear prohibitive, various tools exist to

### IV-24 facilitate the process. For example, SAMI used DDM-3D. The results of these sensitivities should be stratified into days with very good and poor visibility, and the annual average. The aggregation of days will tend to suggest a more local impact of sources than looking at a typical day.

A second set of simulations would be to explore specific control issues, e.g., the imposition of certain sets of controls. A particular interest would be to explore future PM levels as the NO x 

### and SO2 emissions are decreased, but NH 3 

### emissions increase. The interest would be to assess if there is the possibility of increased nitrate formation due to the higher NH 3 

### and lower sulfate in spite of lower NOx emissions, as was found in the SAMI study. In some areas, this may lead to nitrate replacing sulfate as the major contributor to visibility reduction, greatly increasing the impact of NO x 

### controls on visibility.

A third calculation would look at how SCR or SNCR controls would impact visibility in a point source plume. The ammonia in such a plume might lead to locally increased ammonium nitrate formation. While, regionally, ammonia emissions from such control technologies are small compared to animal waste decomposition and fertilizer, on a very local scale there may be increased PM formation. Such a calculation may require a finer grid being employed in locations to capture the finer scale impacts of the plume where, presumably, both NO x 

### and NH 3 

### would be elevated.

Summary



### The states that are part of the WRAP have a very diverse chemical/PM “climatology”, represented by extremes ranging from the dry, high nitrate areas in Southern California to the wet, low PM northern coastal mountains, to the dry mountains and deserts inland. Typically, the major constituents of the visibility-impairing PM are fine PM sulfate, OC and, at times, nitrate, though there are episodes of high coarse material.

Doing a simple, approximate, mass-lifetime balance on coarse PM emissions from primary sources suggests that, on average, primary CPM emissions from point sources will contribute a very small fraction of the total PM. This is borne out in the observations. Near the source (within a few 10s of km), however, the sources may be significant. FPM is much longer lived than CPM, and is predominantly secondary, being composed primarily of sulfate, OC and nitrate.

Primary FPM from point sources is estimated to be a small contributor to FPM mass and light extinction on a regional basis. First, the total amount is small relative to other components of the FPM. Second, it has a lower impact, on a per mass basis, than other constituents. Third, periods of highest extinction do not appear to have significant amounts of point source-derived, primary FPM as compared to the other components, particularly CPM during dust storms, organic and elemental carbon during fires, sulfate during stagnation events, and nitrate in areas of high ammonia.

Nitrate is formed from emissions of NO x 

### that react to form nitric acid, which then can undergo gas-to-particle conversion. Much, but not all, of the nitrate is fine, and higher observed concentrations are formed from the reaction between nitric acid and ammonia to form

### IV-25ammonium nitrate. A fraction of the nitrate will be formed from nitric acid attacking preexisting PM (coarse or fine). Ammonium nitrate levels can be reduced by either reducing nitric acid formation or ammonia emissions, with the greatest sensitivity to reducing the precursor that is least abundant (on a mole basis). Thus, some parts of the region will be ammonia-limited, others will be nitrate-limited (e.g., areas with high ammonia, such as near confined feeding and intense agricultural operations). The fraction that is formed from nitrate attacking pre-existing PM will not be very ammonia sensitive, responding more to NO x 

### controls. Modeling currently suggests that much of the domain is ammonia-limited (in terms of nitrate formation). However, CMAQ does not include the capability to simulate the nitric acid attacking pre-existing PM, so this may be an artifact. What this suggests is that it is important to get model performance to the point where one is confident that the nitrate formation mechanisms are quantitatively reliable.

In areas where nitrate formation is nitric acid-limited, NO x 

### controls will generally reduce PM (with a few local exceptions). However, one ton of emissions reductions will not lead to one less ton of PM being formed. NO, NO 2 

### and nitric acid all deposit out (dry or wet). Indeed, nitric acid deposits very rapidly, and simulations suggest that most of the mass will be removed this way. The WRAP model can develop the response of nitrate PM to NOx emissions.

Trading emissions of primary FPM from one source to another would be relatively straightforward compared to other types of trades. The relative height of emission will have little impact on far downwind receptors. As with trading any type of emissions, trades across sources in very different locations may lead to one area receiving greater air quality benefits than another. Trading emissions of point source CPM would be especially sensitive to location in that the major impact is very near the source, dropping dramatically within 10 km.

NOx emissions trading to reduce PM formation would be more complex. First, as noted above, some (if not most) regions are likely ammonia-limited, so NOx controls will have relatively smaller impacts on nitrate than might be expected. Second, the oxidation of NOx to nitric acid will depend on emission height and the intensity of emissions (e.g., the concentration of NOx in a plume). Third, reducing NOx will slightly impact the formation of sulfate and OC. Further complicating the issue is that an equitable trade (in terms of visibility) today may not be equitable in the future. Again, trading across large spatial areas may lead to issues in terms of which areas benefit most.

Trading between pollutants is more involved yet, and a major concern is that the relationship between NOx emissions and nitrate formation is not well quantified at present. As model performance improves, there is no reason that it would not be practical to use the model to set trading relationships between pollutants. In so doing, one must account for the differing impact on visibility on a mass basis and the response to humidity.

### IV-26 References

Brown SG, Herckes P, Ashbaugh L, et al. (2002) Characterization of organic aerosol in Big Bend National Park, Texas , Atmos. Environ,: 5807-5818

Edgerton, E. (2002) personal communication.

Finlayson-Pitts B. J., Pitts J. N., Atmospheric Chemistry: Fundamentals and Experimental Techniques, WileyInterscience, New York, 1986

Friedlander S. K., Smoke, Dust and Haze: Fundamentals of Aerosol Behavior, Wiley-Interscience, New York, 1977

Grand Canyon Visibility Transport Commission (1996) Grand Canyon Visibility Transport Commission: Recommendations for Improving Western Vistas, http://www.westgov.org/wga/publicat/epafin.htm , June, 1996

Gard EE, Kleeman MJ, Gross DS, et al. (1998) Direct observation of heterogeneous chemistry in the atmosphere Science 279, 1184-1187

van de Hulst. HC (1957) Light Scattering by Small Particles, Wiley, New York.

Malm, W.C.; Sisler,J.F.;. Pitchford, M.L.; Scruggs, M.; Ames, R.; Copeland, S.; Gebhart, K.A.; Day, D.E.; IMPROVE (Interagency Monitoring of Protected Visual Environments): Spatial and Seasonal Patterns and Temporal Variability of Haze and its Constituents in the United States: Report III, Colorado State University: Fort Collins, CO, ISSN: 0737-5352-47, 2000.

Malm, W. C.;. Sisler, J. F.; Huffman, D.; Eldred, R. A.; Cahill, T. A. Spatial and Seasonal Trends in Particle Concentration and Optical Extinction in the U.S., J. of Geophys. Res,, 1994, 99, 1347-1370.

Malm, W.C .; Schichtel, B.A..; Ames, R.B.; Gebhart, K.A. A Ten-Year Spatial and Temporal Trend of Sulfate across the United States. J. of Geophys. Res., 2002, 107 (D22).

NARSTO (2003) Particulate Matter Science for Policy Makers: A NARSTO Assessment, Electric Power Research Institute, Menlo Park, CA, February.

Russell AG, Cass GR, 1986, Verifiction of a Mathematical Model for Aerosol Nitrate and Nitric Acid Formation, and Its Use for Control Measure Evaluation, Atmospheric Environment, 20, pp. 2011-2025

Seigneur, C. (2003) “Review of CMAQ and REMSAD Performance for Regional PM Modeling” AER, San Ramon, CA.

Seinfeld, JH and Pandis, SN (1998) “Atmospheric Chemistry and Physics: from Air Pollution to Climate Change” Wiley Interscience, New York.

Sisler, J. F.; Malm, W. C. Interpretation of Trends of PM2.5 & Reconstructed Visibility from the Improve Network, J. Air & Waste Manage. Assoc., 2000, 50, 775-789.

Stelson, AW and Seinfeld, JH (1982) Relative Humidity and Temperature Dependence of the ammonium nitrate dissociation Constant, Atmos. Environ., 15, 671-679.

SAMI (2002) Southern Appalachian Mountains Initiative Final Report, Asheville, NC, August, 2002

Tonneson, G. (2003) Presentation, March 27, Denver, CO.

### IV-27 Watson, J., E. Fujita, J.C. Chow, B. Zielinska, L. Richards, W. Neff, and D. Dietrich (1998). Northern Front Range Air Quality Study. Final report prepared for Colorado State University, Fort Collins, CO, June 30.

Yang Y. J., Wilkinson J. G., Russell A. G., Fast, Direct Sensitivity Analysis of Multi-dimensional Photochemical Models, Environment Science and Technology, 31, pp. 2859-2868, 1997

### V-1 

## SECTION V: SUMMARY OF AIR QUALITY MODELING RESULTS

Context



### The modeling performed for this report is best described as a “sensitivity analysis.” The intent is to get a preliminary assessment of the general atmospheric response to changes in NOx and PM emissions from stationary sources. A secondary objective is to “practice” this type of modeling to get a better understanding of the key technical issues and to identify the most effective ways at evaluating and displaying model results. The results presented here are the best available predictions at this time, but forthcoming improvements to the modeling system may affect the results in ways that alter the policy implications. For this reason, results are discussed in a fairly broad and qualitative manner – i.e., spatial patterns and relative changes. As the modeling system improves and specific strategies are contemplated, additional emission scenarios will be designed and modeled.

Modeling System



### The WRAP’s regional-scale air quality modeling system used to support other aspects of the Section 309 plans was also used to provide information for this report. A description of the modeling system – in addition to model performance statistics, input files, and detailed model results – is available at http://pah.cert.ucr.edu/rmc

.

Emission Scenarios



### Three emission scenarios were simulated:

 

### A 50 percent decrease in NOx emissions from plants with NOx emissions > 100 tpy,

 

### A 50 percent decrease in PM 10 

### emissions from plants with PM 10 

### emission > 100 tpy, and

 

### A 25 percent increase in NOx and PM 10 

### emissions from all stationary sources.

The first two scenarios are meant to address the regional haze rule’s requirement to “assesses emissions control strategies for stationary source NOx and PM, and the degree of visibility improvement that would result from such strategies.” As discussed in Section VI of this report, many commercially-available technologies (and various combinations of such technologies) are capable of achieving a 50% or greater NOx emission reduction without having to switch fuels. Hence, the 50% reduction, although intended primarily to gauge the general atmospheric response to NOx reductions, is not an unreasonable level of control to assume for this exercise in terms of technical feasibility. Again with technical (and administrative) feasibility in mind, emission reductions were limited to plants with emissions greater than 100 tpy, similar to the approach in the Annex. The third scenario is meant to address the rule’s requirement to “evaluate and discuss the need to establish emission milestones for NOx and PM to avoid any net increase in these pollutants from stationary sources within the transport region.” Hence, a 25 percent increase from all stationary sources was assumed to simulate potential growth in the

### V-2 economy and/or disproportionate growth in high-emitting sectors such as energy development, fossil-fueled electricity generation, and mineral processing.

For reasons implied in the rule, the emission changes in the scenarios described above were limited to the nine-state GCVTR 12 

### . Also, the emission changes were applied to the 2018 inventory, which includes reductions expected from full implementation of the Annex. This provides a basis for comparing results to other strategies being modeled by the WRAP.

Model Performance and Future Improvements



### Nitrate concentrations are poorly predicted by the current modeling system, especially in the winter. For this reason, results for nitrate (and all other species) for the NOx and PM sensitivity runs are only presented for the three month period of July – September.

Several aspects of the modeling system are being improved and evaluated, which should improve confidence in future model predictions, both in the summer and winter. These improvements and evaluations involve the chemical mechanisms, the ammonia inventory, a more robustmeteorological database (2002 vs 1996), enhanced grid resolution (12 km vs 36 km), plume-ingrid capabilities, the introduction of an inventory for wind-blown dust emissions, and better temporal allocation and chemical speciation of point and area source emissions. A source apportionment mechanism is also expected to be included with the model.

Model Results



### As stated above, results are presented in a fairly broad and qualitative manner – i.e., spatial patterns and relative changes. Relative (percent) changes are of particular interest because their errors are believed to be smaller than those of the absolute concentrations. It is not clear how the seasonal limitation of this analysis (July – September) may affect the relative changes, but it is likely to reduce them to some extent. First, nitrate concentrations tend to be lower in the summer than in the winter, especially in areas where nitrate concentrations are highest and the potential for change the greatest. Second, results are averaged over a full three-month period. Typically, visibility effects are measured by averaging conditions over the worst 20 percent of the days observed per year at an ambient monitoring site, which is approximately 22 days. But in this analysis, because it is limited to the July-September timeframe, the results are averaged over 92 consecutive days and do not represent a measure of the worst conditions, again when the potential for change is the greatest. Thus, while there are many uncertainties surrounding the model’s nitrate predictions, the limitation of this study to July – September will tend to limit the apparent impacts from the NOx (and to some extent) PM 10 

### emission changes.

On a ton-per-ton basis, reductions in stationary source PM 10 

### emissions appear to yield greater regional haze benefits than reductions in NOx emissions. For instance, when stationary source PM 10 

### emissions are reduced by 98,000 tpy (a 50 percent reduction from GCVTR facilities > 100 tpy), the average summer-time visibility improvement across all Class I areas in the GCVTR (in Mm -1 

### ) is about 0.4 percent. When stationary source NOx emissions are reduced by

12 In 1996, stationary sources in the GCVTR emitted about 75 percent and 83 percent of the NOx and PM 10 emissions, respectively, in the13-state WRAP region.

### V-3 412,000 tpy (a 50 percent reduction from GCVTR facilities > 100 tpy), the visibility improvement is only somewhat greater, at 0.5 percent. 13 

### Hence, on a purely technical basis (without considering existing controls, costs, or other implementation issues), reductions in PM emissions might be more effective at improving regional haze than reductions in NOx emissions.

Nevertheless, the 50 percent NOx reduction scenario tends to produce slightly greater regional haze benefits than the 50 percent PM 10 

### reduction scenario. This is because stationary sources comprise 33 percent of the total NOx inventory but only 7 percent of the total PM 10 

### inventory. So even though much of the NOx is never converted to the particulate phase, the sheer volume of NOx emission reductions relative to PM 10 

### reductions and the fact that nitrate (mostly in the fine mode) scatters light more efficiently than primary PM (mostly in the coarse mode) make the NOx reduction scenario more meaningful in terms of regional haze benefits than the PM 10 

### reduction scenario. The fact that stationary source NOx emissions are not as well controlled as stationary source PM 10 

### emissions in the West actually lends some relevance to the outcome that NOx emissions are altered more in the sensitivity analysis than PM 10 

### emissions.

For the three-month summer period examined in this analysis, NOx changes have very little effect on aerosol concentrations beyond changes in nitrate. Other species that could be indirectly affected – e.g., ozone concentrations and subsequent oxidation of SO 2 

### and organic gases into the particulate phase – do not appear influenced by the levels of NOx reductions (16 percent of the total inventory) assumed in this analysis. This finding may change after implementing all the model improvements noted above, but since nitrate currently appears as the largest responder to NOx changes, and given the information above regarding the NOx and PM scenarios, the maps, tables, and discussion below place somewhat more emphasis on nitrate and the results of the 50 percent NOx reduction scenario than on other species and scenarios.

Figures V-1 and V-2 

### show the model-predicted 2018 base case (Annex included) surface-layer concentrations of ammonium nitrate (NH4NO3) and PM 10, 

### respectively, averaged over the three month period of July-September. The values in these maps should not be construed as the expected ammonium nitrate and PM 10 

### concentrations in 2018, which are determined by scaling the ambient monitoring data by the relative changes predicted by the model. Rather, these maps are intended to provide a sense of the spatial variability and span of concentrations, which are useful for interpreting the following maps of relative (percent) changes – e.g., a high percentage change in a low-concentration area may be less meaningful than a moderate percentage change in a high concentration area.

Figures V-3 and V-4 

### show the absolute and percentage change, respectively, in NH4NO3 concentrations from a 50 percent reduction in stationary source NOx emissions from facilities in the GCVTR greater than 100 tpy. The largest absolute changes occur in southern CA, where concentrations in Class I areas are predicted to decrease by 0.15 to 0.25 ug/m 3 

### . A second area of reductions is predicted in the central-east Rocky Mountains, especially in north-central CO. Although the reductions are not as large as in southern CA (0.04 to 0.11 ug/m 3 

### ), they are larger than average across the domain and exhibit the largest percentage reduction (10 to 20 percent).

13 In some Class I areas, the visibility improvement can be two to five percent on some days.

### V-4 It is interesting to compare these results with those simulating the effects of the SO 2 

### backstop emissions trading program, or Annex. In the case of the Annex, an SO 2 

### emission reduction of 15 percent (132,000 tons) in the GCVTR produced a sulfate reduction of 4 percent averaged across all Class I areas in the GCVTR on the 20% worst modeled days. In the case of the NOx sensitivity run, a NOx emission reduction of 15 percent (412,000 tons) in the GCVTR produceda nitrate reduction of 5 percent averaged across all Class I areas in the GCVTR on the JulySeptember modeled days. The nitrate reduction does not produce as much visibility benefit at most Class I areas because its concentrations are much smaller, but the response of nitrate to NOx reductions is similar in proportion to the response of sulfate to SO 2 

### reductions.

Figures V-5 and V-6 

### show the absolute and percentage change, respectively, in NH4NO3 concentrations from a 25 percent increase in stationary source NOx and PM 10 

### emissions from all stationary sources in the GCVTR. The spatial pattern of changes is very similar to that in the 50 percent NOx reduction scenario, although the magnitude of changes are about half. Again, it is interesting to see some proportionality in the modeling results – i.e., an emission change that is half as large produces aerosol changes that are about half as large. The percent increase in NH4NO3 concentrations and visibility impairment (in Mm -1 

### ) in this scenario is 2 percent and0.5 percent, respectively, when averaged over all Class I areas in the GCVTR for JulySeptember.

Figures V-7 and V-8 

### show the absolute and percentage change, respectively, in PM 10 

### concentrations from a 50 percent reduction in stationary source PM 10 

### emissions from facilities in the GCVTR greater than 100 tpy. Maximum reductions in PM 10 

### are about 0.1 to 0.5 ug/m 3 

### , or about 4 to 8 percent. Compared to the NOx reduction scenario, reductions in ambient PM 10 

### are more dispersed, with a greater number of local maximums. This may reflect the fact that there are a fewer number of large PM 10 

### sources than large NOx sources and that much of the PM 10 

### emissions are coarse particles, with shorter transport distances.

Figures V-9 and V-10 

### show the absolute and percentage change, respectively, in PM 10 

### concentrations from a 25 percent increase in stationary source NOx and PM 10 

### emissions from all stationary sources in the GCVTR. The spatial pattern of changes reflects where both relatively large NH4NO3 changes (southern CA and central-east Rockies) and PM 10 

### changes (additional areas) are predicted. The largest PM 10 

### increases are about 0.1 to 0.3 ug/m 3 

### , or 2 to 3 percent. Less than half of this is NH4NO3.

Table V-1 

### shows the predicted change in light extinction and NH4NO3 at each Class I area in the GCVTR averaged over the July-September period as a result of reducing NOx emissions by 50 percent from stationary sources with emissions greater than 100 tpy in the GCVTR. 14 

### As shown in the maps, the greatest impacts occur in southern CA, followed by areas in CO. The average improvements in light extinction in these areas is about 0.3 to 1.5 Mm -1 

### (1 to 2.5 percent). The average improvement in NH4NO3 is about 0.05 to 0.25 ug/m 3 

### (3 to 20 percent).

14 Tabular, site-specific data for other scenarios is available upon request. Tabulay presentation of results was limitted to this scenario since others tend to produce smaller changes in visibility.

### V-5 Figure V-1. Base Case Ammonium Nitrate Concentrations ( 

### μ g/m 3 

### ) – for purposes of illustrating spatial patterns, not magnitudes.

Figure V-2. Base Case PM 10 

### Concentrations ( 

### μ g/m 3 

### ) – for purposes of illustrating spatial patterns, not magnitudes.

### V-6 Figure V-3. Change in Ammonium Nitrate Concentrations Resulting from a 50% Reduction in Stationary Source NOx Emissions > 100 tpy.

Figure V-4. Relative Change in Ammonium Nitrate Concentrations Resulting from a 50% Reduction in Stationary Source NOx Emissions > 100 tpy.

### V-7 Figure V-5. Change in Ammonium Nitrate Concentrations Resulting from a 25% Increase in Stationary Source NOx and PM 10 

### Emissions.

Figure V-6. Relative Change in Ammonium Nitrate Concentrations Resulting from a 25% Increase in Stationary Source NOx and PM 10 

### Emissions.

### V-8 Figure V-7. Change in PM 10 

### Concentrations Resulting from a 50% Reduction in Stationary Source PM 10 

### Emissions > 100 tpy.

Figure V-8. Relative Change in PM 10 

### Concentrations Resulting from a 50% Reduction in Stationary Source PM 10 

### Emissions > 100 tpy.

### V-9 Figure V-9. Change in PM 10 

### Concentrations Resulting from a 25% Increase in Stationary Source NOx and PM 10 

### Emissions.

Figure V-10. Relative Change in PM 10 

### Concentrations Resulting from a 25% Increase in Stationary Source NOx and PM 10 

### Emissions.

### V-10 Table V-1. Light Extinction and Ammonium Nitrate Changes Resulting from a 50% Reduction in Stationary Source NOx Emissions > 100 tpy, Sorted by Average Light Extinction.

Light Extinction NH4NO3 State GCVTR Class I Area ∆ Mm -1 ∆ % ∆ μ g/m 3 ∆ % CA Cucamonga Wilderness -1.59 -1.37 -0.25 -3.25
CA San Jacinto Wilderness -1.13 -1.18 -0.19 -2.97
CA San Gabriel Wilderness -0.83 -0.82 -0.13 -3.06 CA Agua Tibia Wilderness -0.81 -1.05 -0.12 -2.77 CA San Gorgonio Wilderness -0.80 -0.93 -0.16 -2.65
CO Rawah Wilderness -0.69 -2.41 -0.11 -16.84
CO Mount Zirkel Wilderness -0.61 -2.28 -0.09 -20.86 CO Rocky Mountain NP -0.57 -1.68 -0.09 -14.14
CA Joshua Tree NP -0.47 -0.77 -0.13 -3.69 CO Eagles Nest Wilderness -0.45 -1.41 -0.07 -11.97
CO Great Sand Dunes NM -0.43 -1.57 -0.06 -13.87
NM White Mountain Wild. -0.36 -1.11 -0.05 -10.51 CO Flat Tops Wilderness -0.34 -1.28 -0.05 -13.82
CO La Garita Wilderness -0.34 -1.27 -0.05 -12.15
CO West Elk Wilderness -0.33 -1.19 -0.05 -12.09 CO Black Canyon of Gunnison -0.31 -0.97 -0.04 -14.83
CO Weminuche Wilderness -0.29 -1.14 -0.04 -13.02
CO Maroon Bells-Snowmass -0.29 -1.00 -0.04 -10.62
CA Dome Land Wilderness -0.27 -0.46 -0.04 -4.48
CA Pinnacles NM -0.26 -0.86 -0.04 -5.93
NM Wheeler Peak Wilderness -0.24 -0.91 -0.03 -8.94 AZ Mount Baldy Wilderness -0.22 -0.64 -0.03 -6.25
NM Salt Creek Wilderness -0.22 -0.71 -0.02 -7.75
AZ Petrified Forest NP -0.21 -0.73 -0.01 -6.88 WY Bridger Wilderness -0.20 -0.77 -0.03 -7.51
CA Hoover Wilderness -0.20 -0.19 -0.04 -2.60 CA Emigrant Wilderness -0.19 -0.25 -0.03 -3.08
NM Gila Wilderness -0.18 -0.34 -0.02 -3.81
CA Minarets -0.18 -0.23 -0.03 -2.71
OR Mount Jefferson Wild. -0.17 -0.28 -0.02 -2.59
NM San Pedro Parks Wild. -0.17 -0.64 -0.02 -10.43
NM Bandelier NM -0.17 -0.58 -0.02 -7.42 AZ Superstition Wilderness -0.16 -0.40 -0.02 -2.04 OR Mount Washington Wild. -0.16 -0.30 -0.02 -2.55
OR Mount Hood Wilderness -0.14 -0.22 -0.03 -1.83
CA Kaiser Wilderness -0.14 -0.19 -0.02 -2.63 CA Kings Canyon NP -0.14 -0.22 -0.02 -2.83
CA John Muir Wilderness -0.14 -0.23 -0.02 -2.69
CA San Rafael Wilderness -0.14 -0.32 -0.01 -5.40
AZ Sierra Ancha Wilderness -0.13 -0.35 -0.01 -1.76 CA Sequoia NP -0.13 -0.24 -0.02 -4.56
CA Yosemite NP -0.13 -0.17 -0.02 -2.63
UT Arches NP -0.13 -0.51 -0.01 -14.82

### V-11 Light Extinction NH4NO3 State GCVTR Class I Area ∆ Mm -1 ∆ % ∆ μ g/m 3 ∆ %
NM Pecos Wilderness -0.12 -0.44 -0.03 -7.29 WY Fitzpatrick Wilderness -0.12 -0.46 -0.02 -4.83 NM Bosque del Apache Wild. -0.12 -0.44 -0.01 -8.65 OR Kalmiopsis Wilderness -0.11 -0.34 -0.01 -3.05 OR Eagle Cap Wilderness -0.11 -0.31 -0.02 -4.29
OR Three Sisters Wilderness -0.11 -0.24 -0.02 -2.55 AZ Grand Canyon NP -0.11 -0.40 -0.01 -7.36 UT Capitol Reef NP -0.11 -0.45 -0.01 -8.21
WY Grand Teton NP -0.11 -0.36 -0.02 -3.47
WY Teton Wilderness -0.10 -0.36 -0.02 -3.56
OR Crater Lake NP -0.10 -0.21 -0.01 -2.09 ID Hells Canyon Wilderness -0.10 -0.13 -0.02 -3.87 OR Strawberry Mountain Wild. -0.10 -0.15 -0.01 -2.89 AZ Sycamore Canyon Wild. -0.10 -0.32 -0.01 -5.25
CA Marble Mountain Wild. -0.10 -0.23 -0.01 -2.57
AZ Chiricahua NM -0.10 -0.36 0.00 -6.65
AZ Chiricahua Wilderness -0.10 -0.36 0.00 -6.65
AZ Galiuro Wilderness -0.10 -0.30 -0.01 -4.30 UT Canyonlands NP -0.09 -0.42 -0.01 -10.61
OR Diamond Peak Wild. -0.09 -0.18 -0.01 -2.20 AZ Saguaro Wilderness -0.09 -0.28 -0.01 -6.84 UT Bryce Canyon NP -0.08 -0.32 -0.01 -6.14
AZ Pine Mountain Wild. -0.08 -0.24 -0.01 -2.82
AZ Mazatzal Wilderness -0.08 -0.23 -0.01 -2.82
NM Carlsbad Caverns NP -0.08 -0.26 -0.01 -4.03
OR Mountain Lakes Wild. -0.07 -0.18 -0.01 -2.43
UT Zion NP -0.07 -0.21 -0.01 -7.22
CO Mesa Verde NP -0.07 -0.21 -0.03 -17.68
CA Lava Beds Wilderness -0.06 -0.15 -0.01 -2.09
WY Yellowstone NP -0.06 -0.20 -0.01 -2.50
CA South Warner Wilderness -0.06 -0.19 -0.01 -3.77 ID Selway-Bitterroot Wild. -0.05 -0.12 -0.01 -2.19
WY North Absaroka Wild. -0.05 -0.19 -0.01 -2.43
WY Washakie Wilderness -0.05 -0.19 -0.01 -2.43 CA Point Reyes NS -0.05 -0.15 0.00 -2.80
ID Craters of The Moon Wild. -0.04 -0.14 -0.01 -3.89
OR Gearhart Mountain Wild. -0.04 -0.13 0.00 -2.24
CA Caribou Wilderness -0.04 -0.11 0.00 -3.38
CA Thousand Lakes Wild. -0.03 -0.09 0.00 -2.30
CA Lassen Volcanic NP -0.03 -0.07 0.00 -2.28 CA Yolla Bolly Middle Eel Wild. -0.03 -0.09 0.00 -1.13 NV Jarbridge Wilderness -0.03 -0.13 0.00 -4.49
CA Ventana Wilderness -0.02 -0.12 0.00 -5.24
CA Redwood NP -0.02 -0.06 0.00 -2.92 Average -0.21 -0.51 -0.03 -5.79

## SECTION VI: SUMMARY OF EMISSION CONTROLS AVAILABLE FOR LARGE STATIO NARY SOURCES OF NOx AND PM



## Final Report

Prepared for:

Lee Alter Western Governors’ Association 1515 Cleveland Place, Suite 200 Denver, CO 80202-5114

Prepared by:

Constance Senior, Brooke Shiley, Bradley Adams Reaction Engineeri ng International 77 West 200 South, Suite 210

Salt Lake City, UT 84101

Rui Afonso Energy & Environmental Strategies 50 Old Faith Road Shrewsbury, MA 01545

June 30, 2003http://www.reaction-eng.com 

### VI-i

INTERNATION AL REACTION

ENGINEERING 

### TABLE OF CONTENTS

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

1.1 B ACKGROUND

............................................................................................................................... .................1 1.2 O BJECTIVES

............................................................................................................................... .....................1 1.3 D EFINITIONS AND M ETHODOLOGY .................................................................................................................2

2 NO X AND PM SOURCES IN THE WESTERN UNITED STATES ..............................................................6

2.1 C HARACTERIZATION OF NO X S OURCES ..........................................................................................................6 2.2 C OMPARISON WITH O THER D ATABASES FOR NO X C ONTROL T ECHNOLOGIES ..............................................13 2.3 T RENDS IN NO X E MISSIONS AND C ONTROLS FOR C OAL -F IRED U TILITY B OILERS , 1995-2000. ....................16 2.4 C HARACTERIZATION OF S OURCES OF P ARTICULATE M ATTER (PM).............................................................17 2.4 C HARACTERIZATION OF S OURCES OF P ARTICULATE M ATTER (PM).............................................................18 2.5 C OMPARISON WITH O THER D ATABASES FOR PM C ONTROL T ECHNOLOGIES ...............................................22

3 NO X CONTROL TEC HNOLOGIES.......................................................................................................... .....24

3.1 O VERVIEW

............................................................................................................................... .....................24 3.2 C OAL -F IRED B OILERS

............................................................................................................................... ...39 3.3 R ECIPROCATING E NGINES ............................................................................................................................42 3.4 C EMENT K ILNS

............................................................................................................................... ..............43 3.5 N ATURAL G AS AND O IL F IRED B OILERS ......................................................................................................43 3.6 T URBINES

............................................................................................................................... ......................44

4 PM CONTROL TECHNOL OGIES ........................................................................................................ ........46

4.1 O VERVIEW

............................................................................................................................... .....................46 4.2 PM C ONTROL FOR C OAL -F IRED B OILERS AND O THER C OMBUSTION S OURCES ...........................................47 4.3 O THER D EVELOPMENTS

............................................................................................................................... 48 4.4 C OSTS

............................................................................................................................... ............................49

5 MULTI-POLLUTANT CONT ROL TECHNOLOGIES ...............................................................................51

5.1 P ROPOSED M ULTI

- POLLUTANT E MISSION R EGULATIONS FROM U TILITY B OILERS .......................................51 5.2 M ULTI

- POLLUTANT C ONTROL T ECHNOLOGIES .............................................................................................52

6 SUMMARY AND RECOMMENDATIONS...................................................................................................5 6

6.1 NO X AND PM S OURCES

............................................................................................................................... .56 6.2 C ONTROLS FOR NO X AND PM.......................................................................................................................57 6.3 W HAT ’ S ON THE HORIZON ? W HAT TRENDS WILL INFLUENCE EMISSIONS AND CONTROL TECHNOLOGIES ?...58 6.4 R ECOMMENDATIONS FOR F UTURE W ORK ....................................................................................................59

7 REFERENCES ..................................................................................................................... .............................60

APPENDIX A: BREAKDOWN OF NO X EMISSIONS BY STATE

APPENDIX B: BREAKDOWN OF PM EMISSIONS BY STATE

APPENDIX C: NO X CONTROL TECHNOLOGY SUMMARIES

APPENDIX D: PM CONTROL TECHNOLOGY SUMMARIEShttp://www.reaction-eng.com 

### VI-ii

INTERNATION AL REACTION

ENGINEERING 

### LIST OF ACRONYMS, ABBREVIATIONS AND SYMBOLS

ACFM Actual cubic feet per minute AFBC Atmospheric fluidized bed combustor BART Best available retrofit technology DLN Dry Low NO x 

### EIA Energy Information Administration EPA United States Environmental Protection Agency GCVTC Grand Canyon Visibility Transport Commission GCVTR Grand Canyon Visibility Transport Region FGR Flue Gas Recirculation Hg Mercury ICE Internal Combustion Engine LEC Low Emission Combustion LNB Low-NO x 

### burner MBtu Millions of British Thermal Units MTF Market Trading Forum NG Natural Gas NO x 

### Nitrogen oxides NSCR Non-selective catalytic reduction NSPS New Source Performance Standard O&M Operating and Maintenance OFA Overfire air PM Particulate matter PM10 Particulate matter less than 10 microns PM2.5 Particulate matter less than 2.5 microns SCC Source Classification Code SCR Selective catalytic reduction SIP State Implementation Plan SNCR Selective non-catalytic reduction SO 2 

### Sulfur dioxide TPY Tons per year WGA Western Governors’ Association WRAP Western Regional Air Partnershiphttp://www.reaction-eng.com 

### VI-iii

INTERNATION AL REACTION

ENGINEERING 

### ACKNOWLEDGEMENTS

We are grateful to Dr. Praveen Amar for providing help in loca ting the most recent sources of information on control technologies, as well as for external review of the report from the perspective of making it relevant to readership in the state governments/regional entities.http://www.reaction-eng.com 

### VI-1

INTERNATION AL REACTION

ENGINEERING 

### 1 INTRODUCTION 1.1 Background

The Western Regional Air Partne rship (WRAP) has undertaken a program to assess emissions control technologies and strategies for large stationary sources of NO x 

### and PM emissions in the western states region. The WRAP is a collabor ative effort of tribal governments, state governments, and various federal agencies to implement the recommendations of the Grand Canyon Visibility Transport Commission (GCVTC) a nd to develop the tec hnical and policy tools needed by western states and tribes to comply with the U.S. Environmental Protection Agency’s (EPA) Regional Haze Rule.

The WRAP established the Market Trading Fo rum (MTF), in large part, to develop and recommend emission control strategi es for stationary sources of air pollution. A major focus of the MTF has been the establishment of regiona l emission milestones for sulfur dioxide (SO 2 

### ) and a regional backstop cap- and-trade program for SO 2 

### to be triggered if the milestones are not met voluntarily.

The MTF is also responsible for generating a re port required in 40 CF R 51.309(d)(4)(v) of the Regional Haze Rule. The report must assess em ission control technologies and strategies for stationary source NO x 

### and PM emissions and the degree of visibility impairment that would result from such strategies. It must also evaluate the need for NO x 

### and PM milestones to avoid any net emissions increase and to support possible multi-pollutant and multi-source control programs. Finally, this year several states must submit state implementation plans (SIPs) to EPA and must commit to a 2008 revision containing a ny necessary long-term strategies and Best Available Retrofit Technology (BART) re quirements for stationary source NO x 

### and PM.

This project is essentially a starting poi nt for addressing st ationary source NO x 

### and PM emission sources over the next four years, at which point local and/or regional emission control program(s) may be implemented. Future work by the WRAP will investigate these issues further and will attempt more detailed cost estimates and emission reductions achievable in the WRAP region given the nature of its s ources and existi ng controls. 1.2 Objectives

The main objectives of this pr oject are to identify and briefl y describe for large stationary sources in the western United States:

• The universe of modern commercially-available or near-available stationary source NO x 

### and PM controls (either technologi es or best management practices);

• Trends in such controls;

• Their approximate capital and operating co sts, control efficiencies, and cost effectiveness;

• Secondary environmental impacts, such as control of other air pollutants and generation of solid or hazardous waste;

• Real-world experience at facilities implementing or testing such controls;http://www.reaction-eng.com 

### VI-2

INTERNATION AL REACTION

ENGINEERING 

### • Future opportunities for improveme nts and demonstrations; and

• Recommendations for future work.

1.3 Definitions and Methodology

The work plan for the project consisted of the following tasks:

Task 1. Inventory of Stationa ry Sources in the WRAP Region. This task involved a review of the 1996 WRAP stationary source emissions invent ory (version 3, in MS Access format), as well as other recent and relevant databases to determ ine the number/type of stationary sources with emissions greater than 100 tons per year (TPY ) and the type and performance of air pollution control devices installed on those sour ces. Two subsets were created for NO x 

### and PM emissions, respectively, based on the following criteria:

• Sources (defined as emission units, or record s, in the database) having annual emissions of the pollutant of interest greater than 100 TPY; and

• Sources located in the thirteen-state regi on: AZ, CA, CO, ID, MT, ND, NM, NV, OR, SD, UT, WA, WY (See Figure 1).

Table 1 lists the fields extracte d from the WRAP database.

Figure 1. Thirteen-state region cons idered in the technology assessment.http://www.reaction-eng.com 

### VI-3

INTERNATION AL REACTION

ENGINEERING 

### The source classification codes (SCCs) used to ca tegorize sources served as general guidelines for choosing the categories in Task 1. The similarities (or differe nces) in the control technologies applicable to specific SCCs were al so factors in grouping sources. For example, a category called “Coal-fired boilers” was created containing emissions data from utility and industrial boilers (of differe nt boiler types) burning coal because the same NO x 

### and PM control technologies can be applied to most of these s ources. With this in mind, Table 2 gives the categories created for characteri zation of the WRAP emissions a nd a description of the WRAP categories (i.e., SCC codes) used to de fine the categories in this report.

For electric utility point sources, additional da tabases were used to determine boiler capacity (MBtu/yr), enhance and update information on cont rol technologies in pl ace, and verify other source information. These databases were: EPA CEMs database for 1996 and 2001 [1], EPA EGRID database for 1996 and 2000 [2] and the EIA-767 database for 1996 [3].

The results of Task 1 are discusse d in Section 2 of this report. Table 1. WRAP database fields used in the technology assessment.

Field Description
FIPST FIP State Code
POINTID NAPAP Point ID Code
STACKID Stack Number
BLRID Boiler ID Code Code (utility only) SEGMENT Segment Number ORISID ORIS Plant ID (utility only)
PLANT Plant Name
SCC Source Classification Code SCC1_DESC General category (e.g., External Combustion Boiler) SCC3_DESC Major industrial gr oup within general category SCC6_DESC Specific indust ry or emission source SCC8_DESC Particular emitti ng process or fuel type NOX_ANN Annual NO x 

### Emissions, tons per year PM10_ANN Annual PM Emissions, tons per year CO_ANN Annual CO Emissions, tons per year SO2_ANN Annual SO 2 

### Emissions, tons per year NOX_CPRI Primary Control Equipment Code - NO x 

### PM_CPRI Primary Control Equipment Code - PM CONTROL_DEVICE_DESC Control Device Description (either NO x 

### or PM)

Note: Codes taken from the 1996 National Emi ssion Trends (NET) PC Inventory File Formathttp://www.reaction-eng.com 

### VI-4

INTERNATION AL REACTION

ENGINEERING Table 2. List of Categories Used to Characterize Point Sources



### Category WRAP Sources (based on SCC Codes contained with the category)
Coal-Fired Boilers All coal-fired external combustion boilers Reciprocating Engines A ll reciprocating ICE’s NG Natural gas-fired ICE’s, including 2- and 4-cycle
Diesel Diesel- fired ICE’s, includi ng large-bore engines Process Gas Unspecified process gas-fired ICE’s Cement Kilns All cement kilns (wet and dry process) Oil/NG Boilers External combustion boilers firing oil or natural gas
Turbines All fired turbines NG Natural gas-fired turbines Diesel Diesel-fired turbines

Mineral Processing Cement crushing, grinding and dryi ng, asphalt, other drying applications

Petrochemical Flares, cat.crackers, nitric acid plants, unspecified process gas operations, does not include process heaters NG Compressor Technology (reciprocating engine or turbine) not specified Pulp and Paper Recovery boilers, lime kilns, drying and smelting
Wood Boilers Wood waste and/or ba rk boilers, technology unspecified Refinery Process Heaters Process heaters Glass Manufacture Glass melting furnaces

Primary Metal Production Electric arc furnaces, reheat furnaces, material handling and unspecified Waste Combustion Liquid waste (Dakot a gasifier) and solid waste (WTE) Refinery Unspecified refinery emissions In-process Fuel Use Unspecified combustion systems at glass and cement plants Jet Engine Testing Jet engine testing
Oil and Gas Production Flares and unspecified processes Smelting Operations Copper and aluminum smelting Sugar Beet Processing Sugar beet processing Secondary Metal Produc tion Steel foundries Turbines, Steam Geothermal power productionhttp://www.reaction-eng.com 

### VI-5

INTERNATION AL REACTION

ENGINEERING 

### Task 2. Survey and Documentati on of Emission Control Technologies. In this task, we focused on the identification and compilati on of control technologies for NO x 

### and PM (main focus) and for SO 2 

### and Hg (secondary focus). Sources identi fied in Task 1 that represented minor contributions to the emissions profile of the regi on, either due to their small number, uniqueness, or size, were considered in a more cursory fash ion if their control tec hnology options fell outside of the range of the more comm on/available technologies. This effort consisted mainly of literature reviews, on-line searches and pers onal (telephone) contacts and interviews.

The following information was collect ed on each technology or process:

• Type and fundamentals of technology or process;

• Projected performance;

• Costs (capital and O&M or cost effectivene ss in $/ton of pollutant removed) or cost projections;

• Status of development and opportunities fo r or barriers to further development; and

• Applicability to category (or categories) of WRAP sources identified in Task 1.

The results of this task are presented in Sections 3 and 4.

Task 3. Control Technology Analysis and Discussion. This task was the main focus of the project, in which a thorough evaluation and di scussion of the many iden tified technologies was conducted. A summary cont aining the following information was created for each technology:

• Process name

• For each source category to which the technology was applicable, the following information was tabulated:

o Total annual NO x 

### or PM emissions from s ources greater than 100 TPY

o Percentage NO x 

### and PM reduction

o Cost ($/ton or $/ACFM)

o Development status

• Detailed descriptions were prepared for the following:

o Process description

o Achievable NO x 

### or PM reduction

o Cost information

o Development status

o Practical considerations

o Compatibility with other air pollution control technologies

o Secondary environmental impacts

• References The results of this task are pr esented in Appendices C and D.

Task 4. Final Report. The draft version of the final report was submitted to WRAP on 25 April 2003. The final report was submitted on 30 June 2003.http://www.reaction-eng.com 

### VI-6

INTERNATION AL REACTION

ENGINEERING 

### 2 NO x 

### AND PM SOURCES IN THE WESTERN UNITED STATES

2.1 Characterization of NO x 

### Sources

Table 3 gives the annual NO x 

### emissions in the GCVTR as well as in thirteen-state region for sources (defined as emission units, or records, in the WRAP database) exceeding 100 TPY. The cut-off of 100 TPY captures 84% of the stationary source NO x 

### emissions in the WRAP database for the thirteen-state region. Figure 2 shows the distribution of annual NO x 

### emissions (greater than 100 TPY) as a function of state.

The largest source category by far in the thirteen-s tate region is coal-fired boilers (69%); the top five categories (coal-fired boilers , internal combustion engines, cement kilns, turbines and oil and natural gas boilers) account for almost 90% of the NO x 

### emissions. Therefore, this report concentrates on control technologies applic able to these major process categories.

The states with the largest NO x 

### emissions are AZ, CA, ND, NM, UT, and WY. Since all these states except ND are in the GCVTR, it is not surpri sing that emissions from the nine states in the GCVTR (AZ, CA, CO, ID, NM, NV, OR, UT, WY) account for 75% of the thirteen-state emissions greater than 100 TP Y. Appendix A contains NO x 

### emissions by process category and by state.

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000

AZ CA CO ID MT ND NM NV OR SD UT WA WYAnnual NOx Emissions, TPY



### Figure 2. Annual NO x 

### emissions from sources with emi ssions greater than 100 TPY for the thirteen-state region.http://www.reaction-eng.com 

### VI-7

INTERNATION AL REACTION

ENGINEERING 

### Table 3. A comparison of annual emissions of NO x 

### from sources with emissions greater than 100 TPY between the thirteen-state region and the GCVTR.

13-States GCVTR

Category # Units Total NO x TPY (>100 TPY) # Units Total NO x TPY (>100 TPY) % NO x in GCVTR
Coal-Fired Boilers 151 607,748 117 436,882 72% Reciprocating Engines 423 86,210 394 78,092 91% Cement Kilns 39 41,009 31 32,503 79% Oil/NG Boilers 112 32,910 80 26,116 79% Turbines 86 25,278 78 23,955 95%
Mineral Processing, Other 34 16,250 25 13,342 82% Petrochemical 48 13,719 31 8,326 61% NG Compressor 16 10,959 16 10,959 100% Pulp and Paper 39 10,010 20 4,619 46% Wood Boilers 48 9,776 36 6,864 70% Refinery Process Heaters 38 9,311 29 7,302 78% Glass Manufacture 14 5,033 12 4,379 87% Primary Metal Production 17 3,476 16 3,360 97% Waste Combustion 6 3,309 2 339 10% Fugitive 8 3,256 8 3,256 100% In-process Fuel Use 9 2,605 8 2,016 77% Fixed Wing Aircraft 4 2,297 4 2,297 100% Oil and Gas Production 7 1,140 5 792 70% Smelting Operations 3 961 2 852 89% Food and Agriculture 3 730 1 111 15% Secondary Metal Production 4 507 0 0 0% Turbines, Steam 1 165 1 165 100% Total (> 100 TPY) 1,110 886,659 916 666,527 75%http://www.reaction-eng.com 

### VI-8

INTERNATION AL REACTION

ENGINEERING 

### With few exceptions, the distribution of NO x 

### sources is similar in the thirteen-state region as compared to the GCVTR. ICE’s (reciprocating engines and turbine) are predominantly in the GCVTR, while pulp and paper emissions are mostly outside the GCVTR. As a result of this similarity, the scope of this project was expande d to include additional WRAP states at minimal
cost.
The achievable NO x 

### emission rate depends on the fuel t ype. For coal-fired boilers, lower NO x 

### emission rates are obtained when firing subbituminous coal as compared to bituminous coal. Thus, it is useful to look at the distribution of coals in use in th e thirteen-state region. Figure 3 shows the distribution of coals burned in utility bo ilers as a function of boi ler type and coal rank. Most coal burned in the West is burned close to the mine; this di stribution of coal rank reflects the native coals in the West.

0 50,000 100,000 150,000 200,000 250,000 300,000

Dry Bottom (Wall-fired) Dry Bottom (Tangential) Wet Bottom Stoker Cyclone AFBCNOx, tons per year Lignite
Subituminous
Bituminous



### Figure 3. NO x 

### emissions from coal-fired utility bo ilers as a function of boiler type and coal rank for thirteen-state region from WRAP 1996 database.http://www.reaction-eng.com 

### VI-9

INTERNATION AL REACTION

ENGINEERING 

### For ICE’s, the application of NO x 

### control technology can depend on the type of fuel. More so than with utility boilers, the design and operation of the engine is often determined by the primary fuel. Most of the st ationary ICE’s with annual emissions greater than 100 TPY burn natural gas, as shown in Figure 4.

As long as a source category consists of prim arily large sources, the cut-off of 100 TPY will include most of the NO x 

### emission sources. The 100-TPY cut-off captures 84% of the NO x 

### emissions in the WRAP database as a whole. However, certain source cat egories contain a very large number of small sources. For ICE’s (recipr ocating engines and turb ines) the 100-TPY cutoff only captures about 56% of the emissions as shown in Figures 5 and 6, although this is by far the second largest source categ ory of stationary source NO x 

### emissions. Thus, NO x 

### control programs for sources in this ca tegory will require careful consid eration of population attributes (e.g., controlling a large nu mber of small sources). 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000

Reciprocating Engines TurbinesNOxEmissions, tons per year Process Gas
Diesel
NG



### Figure 4. NO x 

### emissions from Internal Combustion Engines as a function of engine type and fuel for thirteen-state region from WRAP 1996 database.http://www.reaction-eng.com 

### VI-10

INTERNATION AL REACTION

ENGINEERING 40, 78.0%

100, 55.6% 30, 82.4%

50, 73.9%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

0 500 1000 1500 2000 2500 3000 3500 4000
TPY/sourcesCumulative NOx Emissions



### Figure 5. Cumulative NO x 

### emissions from ICE’s in the thirteen-state region as a function of a nnual emission per source.

100TPY, 55.6% 50 TPY, 73.9%

40 TPY, 78.0% 30 TPY, 82.4% 53.00 19.20 9.54 4.19 1.84 0.52 0.10 0.00

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

0 1000 2000 3000 4000 5000 6000 7000 8000 Number of Sources (in order of decreasing TPY/source)Cumulative NOx Emissions TPY/source



### Figure 6. Cumulative NO x 

### emissions from ICE’s in the thirteen-state region as a function of number of sources (in order of decreasing annual emission per source.)http://www.reaction-eng.com 

### VI-11

INTERNATION AL REACTION

ENGINEERING 

### The 1996 WRAP database contains information on control technologies for the pollutants of interest. According to the 1996 data for sources greater th an 100 TPY, few sources had NO x 

### controls, as shown in Table 4. Ov erall, just above 4% of the NO x 

### sources greater than 100 TPY in the WRAP 1996 database had installed controls. Coal-fired boilers were the most frequently controlled (15% of the units), fo llowed by petrochemical processe s (about 13% of the units). Note that control technologies listed in the right-hand column are as reported in the WRAP database. In a few cases, the description of the control technology doe s not seem correct (e.g., fabric filter or electrostatic precipitator) for NO x 

### control; this is a limitation of the data available and it is outside the scope of this program to de termine the accuracy of the data in the WRAP database.http://www.reaction-eng.com 

### VI-12

INTERNATION AL REACTION

ENGINEERINGNOxControl Technology(number of applications inparentheses)Ammonia Injection(2), Fluid Bed Dry Scrubber(1), Low ExcessAir Firing(3) , Modified Furnace OrBurner Design(13), Misc.(4)Catalytic Reduction(1),Process Change(2)Electrostatic Precipitator – High Efficiency(2)Low Excess Air Firing(3),SNCR(1)Steam Or Water Injection(5)Fabric Filter - High Temperature,i.e. T>250F(1)Catalytic Afterburner(1), Catalytic Afterburner With HeatExchanger(1), Catalytic Reduction(1), Staged Combustion(2),Tray-Type Gas Absorption Column(1)NoneNoneAmmonia Injection(1)NoneNoneProcess Enclosed(1)NoneNoneNoneNoneNoneNoneNoneNoneNoneAvg NOxTPY/Unit4,0252041,052294294478286685257204245360204552407289574163320243127165799Total NOxTPY607,74886,21041,00932,91025,27816,25013,71910,95910,0109,7769,3115,0333,4763,3093,2562,6052,2971,140961730507165886,660UnitsControlled2332451600100100000000046# Units151423391128634481639483814176894733411,110CategoryCoal-Fired BoilersReciprocatingEnginesCement KilnsOil/NG BoilersTurbinesMineral ProcessingPetrochemicalNG CompressorPulp and PaperWood BoilersRefineryProcess HeatersGlass ManufacturePrimaryMetal ProductionWaste CombustionRefineryIn-process Fuel UseJet Engine TestingOil and Gas ProductionSmeltingOperationsSugar Beet ProcessingSecondaryMetalTurbines,SteamTotalTable 4. NOxControl Technologies in use in 1996 on Sources Greaterthan 100 TPY from 1996 WRAP database.http://www.reaction-eng.com 

### VI-13

INTERNATION AL REACTION

ENGINEERING 

### 2.2 Comparison with Other Databases for NO x 

### Control Technologies

The level of control for coal-fir ed boilers in the WRAP database seemed low, even for 1996. Therefore, the 1996 WRAP database was compared w ith the data available for utility boilers in the 1996 CEMS and E-GRID databases. The EIA-767 database was also searched for NO x 

### control technologies. The E-GRID database shou ld contain the information in the other two databases since it contains data from 24 differe nt federal data sources , including EIA data and other EPA data. Only coal-fired utility boilers were included in this comparison, not all coalfired boilers. However, only 3% of the WRAP NO x 

### emissions from coal-fired boilers in the thirteen-state region were from non-utility boilers.

It is worthwhile to take a closer look at utility boilers for two reasons. First, they are by far the largest source of NO x 

### emissions, accounting for 68% of the em issions from sources greater than 100 TPY. Second, the effectiveness of NO x 

### control technologies on boilers depends on the type of the boiler as well as on the fuel burned.

For this exercise, the EPA data bases (CEMs and E-GRID) were que ried to obtain information on capacity (MBtu per year) and control technologie s. Data from 1996 was used in order to compare with the WRAP 1996 database. EPA a nd WRAP records were matched using ORIS Plant ID numbers and plant names. For matching r ecords, control technologies not listed in the WRAP database were added, capacity (MBtu) entries were added, and NO x 

### emissions were replaced from the EPA databases.

A comparison of Tables 5 and 6, which contain, respectively, the WRAP data and the WRAP data augmented by the other databases, shows th at the combination of the WRAP data and the EPA and EIA data suggests that 44% of the utility boilers had NO x 

### control (in 1996), as compared to only 12% when considering only th e WRAP data by itself. The EPA databases probably undergo a more thor ough QA/QC procedure than was used to create the WRAP database. Thus, the E-GRID and other federal databases might be expected to have more complete information.http://www.reaction-eng.com 

### VI-14

INTERNATION AL REACTION

ENGINEERINGNOxControl TechnologyModified Furnace/Burner Design(13), Low Excess Air Firing(1)Low Excess Air Firing(1)NoneLow Excess Air Firing(3)NoneNoneNoneNoneAverageEmissions(Tons/Source)4,94514,6949,8443922969772993,694NOxEmissions(TPY)489,58073,46819,68818,8131,7791,954598605,881ControlledUnits1410301019Number ofUnits995248622164Dry BottomCycloneWet BottomNG BoilerStokerCoal-fired AFBCWood BoilerOil BoilersTotalTable 5. NOxEmissions and Control Technologies for Utility Boilers in the Thirteen-State Region from WRAP 1996 Database.Table 6.NOxEmissions and NOxControl Technologies for Utility Boilers inthe Thirteen-State Region from WRAP 1996Database Combined with EPA and EIA Databases.NOxControl TechnologyModified Furnace/Burner Design(13) , Low Excess Air Firing(1),Low NOx Burner(21), OFA(3), Misc.(7)Low Excess Air Firing(1)Low NOx Burner(3)Low Excess Air Firing(3), SCR(2), SNCR(3), Misc.(14)NoneLow Excess Air Firing(1), Misc.(1)NoneNoneAverageEmissions(Tons/Source)5,38014,7067,8034246659773191103,963NOxEmissions(TPY)538,00373,52823,40919,9173,9871,954957110661,866ControlledUnits451322020073Number ofUnits10053476231167Dry BottomCycloneWet BottomNG BoilerStokerCoal-fired AFBCWood BoilerOil BoilersTotalhttp://www.reaction-eng.com 

### VI-15

INTERNATION AL REACTION

ENGINEERING 

### The achievable NO x 

### emission rate depends on the boiler-f uel combination. The largest general class of utility boilers (in term s of number and capacity) is th e dry bottom boiler. Dry bottom boilers can further be subdivided into wall-fire d and tangential. Natural gas boilers emit less NO x 

### than coal-fired boilers per un it of fuel consumed. Of coal -fired boilers, tangential-fired units have the lowest emission rate and cyclones have the highest. The controls in the WRAP database are almost entirely low-NO x 

### burners or other combustion modifications. Figure 7 compares the range of NO x 

### emission rates for all boilers and fuels.

Application of low-NO x 

### burners and other combustion modifications can reduce NO x 

### emissions significantly; this can be seen in the large range of NO x 

### emission that is due, in part, to the use of NO x 

### controls on some of the boilers in each subset. Substantial NO x 

### reductions can also be achieved on coal-fired boilers just with combustion modifications.

Since 1996, low-NO x 

### burners have continued to improve; currently there are vendors who will guarantee NO x 

### emissions as low as 0.15 lb/MBtu from low-NO x 

### burners or low-NO x 

### firing systems. Furthermore, options have been de veloped for other combustion modifications, and SCR has begun to be applied to coal-fir ed boilers. Thus, the potential for NO x 

### control on coalfired boilers is significantly better today than in 1996.

0 0.1 0.2 0.3 0.4 0.5 0.6

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
NOx, lb/MBtufraction of occurrences

Natural Gas Tangential

Wall-fired Cyclone



### Figure 7. Distribution of NO x 

### emission rates for utility bo ilers in the thirteen-state region, combination of WRAP and EPA/EIA databases for 1996.http://www.reaction-eng.com 

### VI-16

INTERNATION AL REACTION

ENGINEERING 

### 2.3 Trends in NO x 

### Emissions and Controls for C oal-Fired Utility Boilers, 1995-2000.

The most recent data available from the EPA data bases for electric utility boilers are from 2000. In this section, we compare the 1996 data on NO x 

### emissions and controls discussed in the previous section with data from 2000.

Table 7 presents the data for 2000 derived from the EPA E-GRID and CEMS databases; this should be compared with Table 6 for 1996. The cap acity of electric util ity boilers increased by 37%, from 3,019,873,933 MBtu/yr in 1996 to 4,130,818,353 MBtu/yr in 2000, but the total NO x 

### emissions decreased by 7%. Figure 9 shows that the average annual emissions from dry bottom coal boilers (the largest category) decreased. Overall there was a decrease in emissions and an increase in the number of un its that were controlled.

The number of sources increased, pa rticularly the number of natu ral gas boilers, which increased from 47 to 82. The percent of natural gas boilers having NO x 

### controls decreased from 47% to 30%. During the time from 1996 to 2000, low-NO x 

### burners were added to natural gas units; there was also a small increase in S CR and SNCR on these types of boilers.

NO x 

### control on dry-bottom boilers increased from 47% to 71% from 1996 to 2000, resulting in a 9% decrease in total NO x 

### emissions from these boilers. The number of units with low-NO x 

### burners doubled. Overfire air (OFA) installations, t hough small in number, tripled. There were no SCR or SNCR installations on coal-fired boilers in 2000.

Thus, there was a modest reduction in NO x 

### emissions from electric utility boilers from 1996 to 2000, accompanied by a substantial incr ease in generating capacity. NO x 

### control increased, particularly on coal-fired boilers. The added NO x 

### control technologies were primarily low-NO x 

### burners and OFA.http://www.reaction-eng.com 

### VI-17

INTERNATION AL REACTION

ENGINEERINGNOxControl TechnologyModified Furnace/Burner Design(13), Low Excess Air Firing(1),Low NOx Burner(41), OFA(9), Misc.(4)Low Excess Air Firing(1), OFA(1)Low Excess Air Firing(4), Low NOx Burner(8), OFA(4), SCR(5),SNCR(4)Low NOx Burner(2)Low Excess Air Firing(1), Misc.(1)NoneNoneNoneAverageEmissions(Tons/Source)5,10113,20348015,5191,0592993352163,207NOxEmissions(TPY)489,68066,01339,38114,1592,118598335216612,500ControlledUnits682252200099Number ofUnits9658222211191Dry BottomCycloneNG BoilerWet BottomCoal-fired AFBCWood BoilerStokerOil BoilersTotalTable 7. NOxEmissions and NOxControl Technologies for Utility Boilers inthe Thirteen-State Region combined with EPAand EIA Databases for 2000.http://www.reaction-eng.com 

### VI-18

INTERNATION AL REACTION

ENGINEERING 

### 2.4 Characterization of Sources of Particulate Matter (PM)

Table 8 gives the annual PM emissions for all PM sources in the thirteen-state region with emissions greater than 100 TPY. The cut-off of 100 TPY captures 60% of the PM emissions in the 1996 WRAP database for the thirteen-state re gion. With few exceptions, the distribution of PM sources is similar in the thirteen-state regi on as compared to the GCVTR. (Primary metal production emissions are mos tly outside the GCVTR.) As a result of this similar ity, the scope of this project was expanded to include a dditional WRAP states at minimal cost.

The largest source category (for those sources with emissions greater than 100 TPY) in the thirteen-state region is coal-fired boilers (40%); the top ei ght categories account for 92% of the PM emissions. Therefore, this report will fo cus on control technologies applicable to these process categories.

The state with the largest PM emissions is WY , followed by AZ, ID, and NM (Figure 9). Since all these states are in the GCVTR, it is not surprising that emissions from the nine states of the GCVTR (AZ, CA, CO, ID, NM, NV, OR, UT, WY) account for 83% of the total stationary source emissions greater than 100 TPY, as s hown in Figure 10. Appendix B contains PM emissions by process category and by state.

Table 8. Annual Emissions of PM from Sources with Greater than 100 TPY.

. Category 13-States GCVTR

# Units Total PM TPY (>100 TPY) # Units Total PM TPY (>100 TPY) % PM in GCVTR Coal-Fired Boilers 88 46,010 67 35,137 76% Mineral Processing 85 24,499 75 21,824 89% Petrochemical 42 10,836 37 9,716 90% Wood Boilers 24 5,718 20 5,210 91% Refinery Emissions 11 5,631 7 5,011 89% Primary Metal Production 20 4,697 11 2,244 48% Pulp and Paper 15 4,476 13 4,119 92% Smelting Operations 8 3,555 7 3,397 96% Miscellaneous 1 2,456 1 2,456 100% Oil/NG Boilers 5 1,379 5 1,379 100% Sugar Beet Processing 5 1,150 3 750 65% Cooling Tower 4 932 4 932 100% Cement Kilns 4 641 3 524 82% Turbines 2 838 2 838 100% Secondary Metal Production 1 537 1 537 100% Jet Engine Testing 2 535 2 535 100% Reciprocating Engines 3 525 3 525 100% Refinery Process Heaters 1 176 1 176 100% Total 321 114,589 262 95,308 83%http://www.reaction-eng.com 

### VI-19

INTERNATION AL REACTION

ENGINEERING 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000

Dry Bottom Cyclone NG Boiler Wet Bottom Coalfired AFBC Wood Boiler Stoker Oil BoilersAverage Emission per Source, TPY 1996

2000



### Figure 8. Average Annual NO x 

### Emissions (greater than 100 TPY) from Electricity Generating Boilers: Comparison of 1996 and 2000 data from EPA Databases.http://www.reaction-eng.com 

### VI-20

INTERNATION AL REACTION

ENGINEERING 

### Table 9 lists the control technologi es in use in the 1996 WRAP data base for particulate matter. 72% of coal-fired boilers, the largest category of emissions, had some form of PM control. Overall, though, only 38% of sources with em issions greater than 100 TPY had controls. 0 5,000 10,000 15,000 20,000 25,000 30,000

AZ CA CO ID MT ND NM NV OR SD UT WA WYAnnual PM Emissions, TPY



### Figure 9. Annual PM Emissions from So urces with Emissions Greater than 100 TPY for the Thirteen-State Region.http://www.reaction-eng.com 

### VI-21

INTERNATION AL REACTION

ENGINEERINGPM Control TechnologyCentrifugal Collector (Cyclone)(2), Electrostatic Precipitator(35),Fabric Filter(12), Multiple Cyclone(4), MultipleCyclone/Electrostatic Precipitator(2), Multiple Cyclone/WetScrubber(1), Wet Scrubber(8)Centrifugal Collector (Cyclone)(2), Dust Suppression by ChemicalStabilizers or Wetting(5), Dust Suppression by Water Sprays(16),Fabric Filter(1), Water Curtain(1), Wet Scrubber(4)Centrifugal Collector (Cyclone)(3), Sulfuric Acid Plant - ContactProcess(2), Wet Scrubber(2)Centrifugal Collector (Cyclone)(1), Wet Scrubber(1)Dust Suppression by Water Sprays(2), Fabric Filter(1)Alkalized Alumina(2), Dust Suppression by Water Sprays(1), WetScrubber(3), Misc.(1)Centrifugal Collector (Cyclone)(1), Wet Scrubber(1)NoneNoneElectrostatic Precipitator(4)Centrifugal Collector (Cyclone)(1)NoneNoneElectrostatic Precipitator(1)NoneNoneNoneNoneAvg PM(TPY/Source)5232882582385122352984442,456276230233419160537267175176357Total PM(TPY)46,01024,49910,8365,7185,6314,6974,4763,5552,4561,3791,150932838641537535525176114,590ControlledUnits64297337300410010000122Numberof Units8885422411201581554241231321Coal-Fired BoilersMineral ProcessingPetrochemicalWood BoilersRefinery EmissionsPrimary Metal ProductionPulp and PaperSmelting OperationsMiscellaneousOil/NG BoilersSugar Beet ProcessingCooling TowerTurbinesCement KilnsSecondary Metal ProductionJet Engine TestingReciprocating EnginesRefinery Process HeatersTotalTable 9. PM control technologies in use on sourcesgreater than 100 TPY from 1996 WRAP database.http://www.reaction-eng.com 

### VI-22

INTERNATION AL REACTION

ENGINEERING 

### 2.5 Comparison with Other Databases for PM Control Technologies

The 1996 WRAP database was compared with the data available for utility boilers in the 1996 CEMS and E-GRID databases. The EIA-767 da tabase was also searched for PM control technologies. The E-GRID data base should contain the informa tion in the other two databases since it contains data from 24 di fferent federal data sources, including EIA data and other EPA data.

EPA and WRAP records for 1996 were matched usi ng ORIS Plant ID numbers and plant names. For matching records, control technologies no t listed in the WRAP database were added, capacity (MBtu) entries were added, and PM emissi ons were replaced from the EPA databases. The EIA-767 database reported PM emissions as lb PM/MBtu, from which we calculated PM emissions in tons per year.

PM emissions data in the EPA databases do not agree with data in the WRAP database, suggesting that the data were obtained from different measurem ent and/or estimation methods. The differences, illustrated by a few sample r ecords in Table 10, follow no general trend from plant to plant.

A comparison of Tables 11 and 12, which contain, respectively, the WRAP data and the WRAP data augmented by the other databases, shows th at the combination of the WRAP data and the EPA and EIA data suggests that about 94% of the utility boilers had PM control (in 1996), as compared to only 53% when considering only th e WRAP data by itself. The EPA databases probably undergo a more thor ough QA/QC procedure than was used to create the WRAP database. Thus, the E-GRID and other federal databases might be expected to have more complete information. Table 10. Sample PM Records from WRAP 1996 and EPA 1996 databases.

Boiler Capacity (MBtu/yr) PM Emissions Rate, EPA (PM/MBtu) PM Emissions Rate, WRAP (PM/MBtu) PM Emissions, EPA (TPY) PM Emissions,

WRAP (TPY) Four Corners 1 (NM) 16,530,550 0.03 0.13 248 1,048 Four Corners 2 (NM) 9,369,730 0.03 0.13 141 618 Four Corners 3 (NM) 18,823,220 0.03 0.13 282 1,243 Four Corners 4 (NM) 58,100,720 0.01 0.03 291 883 Four Corners 5 (NM) 52,759,010 0.01 0.03 264 789 Reid Gardner 1 (NV) 9,599,371 0.05 0.05 240 222 Reid Gardner 2 (NV) 23,152,788 0.05 0.01 579 128 Reid Gardner 3 (NV) 30,579,084 0.05 0.02 764 278 Reid Gardner 4 (NV) 42,514,192 0.05 0.01 1,063 245http://www.reaction-eng.com 

### VI-23

INTERNATION AL REACTION

ENGINEERINGPM Control TechnologyMultiple Cyclone(3), Fabric Filter(8), WetScrubber(7), Electrostatic Precipitator(12)Electrostatic Precipitator(4)Electrostatic Precipitator(3)NoneMultiple Cyclone(1)NoneAverageEmissions(TPY/Source)615309234190381102554PMEmissions(TPY)36,8891,23570257138110239,880ControlledUnits304301038Number ofUnits604331172Dry BottomNG BoilerCycloneStokerCoal-fired AFBCWet BottomTotalPM Control TechnologyMultiple Cyclone(3), Fabric Filter(15), WetScrubber(8), Electrostatic Precipitator(44), MultipleCyclone/Electrostatic Precipitator(3), MultipleCyclone/Wet Scrubber(2),Electrostatic Precipitator(4), Fabric Filter(1)Electrostatic Precipitator(4)Fabric Filter(2)NoneMultiple Cyclone/Electrostatic Precipitator(1),Fabric Filter(1)AverageEmissions(TPY/Source)1,093327309232190137942PMEmissions(TPY)84,1401,6331,23569757127488,549ControlledUnits755420288Number ofUnits775433294Dry BottomCycloneNG BoilerWet BottomStokerCoal-fired AFBCTotalTable 11. PM Emissions and Control Technologies for Utility Boilers in the Thirteen-State Region from WRAP 1996 Database.Table 12.PM Emissions and Control Technologies for Utility Boilers in the Thirteen-StateRegion from WRAP 1996Database Combined with EPA and EIA Databases.http://www.reaction-eng.com 

### VI-24

INTERNATION AL REACTION

ENGINEERING 

### 3 NO x 

### CONTROL TECHNOLOGIES

3.1 Overview
As discussed in Section 2, the NO x 

### emissions greater than 100 TP Y in the thirteen-state region come predominantly from coal-fired boilers. We have concentrated on obtaining detailed information on NO x 

### control technologies for the top five categories, which account for 90% of the emission, although in some cases, where in formation was readily available, we have collected information for other source categorie s (refinery process heat ers, glass melters, and wood-fired boilers). Table 13 show s that these source ca tegories together ac count for 92% of the NO x 

### emissions greater than 100 TPY.

In this section, the information is organized in two formats. First, Table 14 lists all the technologies considered. For the most part, thes e are commercial techno logies, in that vendors are offering these technologies. Not all technologies listed in Ta ble 14 have demonstrated longterm operation, however. Table 14 gives the fo llowing information about each technology:

• Name of the technology

• Source categories to which th e technology can be applied

• Was a summary prepared? (Yes/No). If ye s, technology summaries are contained in Appendix C.

Second, Tables 15 through 22 summarize the NO x 

### control options for major source categories for ease of comparison. More detailed informati on, particularly on the range of cost and NO x 

### control, is given in Appendix C. These tables contain the following information:

• Name of Technology

• Process Description

• Applicability to units in the source category

• Range of performance (NO x 

### removal efficiency)

• Range of costs ($/ton of NO x 

### removed, levelized annual cost)

• Commercial status Table 13. Annual NO x 

### emissions greater than 100 TPY from major source categories.

Category # Units Total NO x TPY % of NO x Emissions Coal-Fired Boilers 151 607,748 68% Reciprocating Engines 423 86,210 10% Cement Kilns 39 41,009 5% Oil/NG Boilers 112 32,910 4% Turbines 86 25,278 3% Wood Boilers 48 9,776 1% Refinery Process Heaters 38 9,311 1% Glass Manufacture 14 5,033 1% Others 199 69,385 8% Total 1,110 886,660http://www.reaction-eng.com 

### VI-25

INTERNATION AL REACTION

ENGINEERING 

### Table 14. NO x 

### Control Technologies.

Technology Applicability Summary in Appendix C (Y/N)

1 Air or fuel staging Coal-fired boilers, Cement kilns Y

2 Batch/Cullet Preheating Glass Melters Y

3 Biosolids injection Cement kilns N (not common)

4 Burner Modifications Coal-fired boilers N (see LNB)

5 Catalytic combustion Gas Turbines Y

6 DLN (fuel-lean combustion) Gas Turbines Y

7 Electric Boost Glass Melters N (too expensive)

8 Flue Gas Recirculation (FGR) Oil/Nat'l Gas Boilers Y

9 Fuel Reburn Coal-fired boilers, Wood/biomass boilers, Glass Melters Y

10 High Energy Ignition Reciprocating Engines Y

11 High-Pressure Fuel Injection Reciprocating Engines Y

12 Hybrid Reburn + SNCR Coal-fired boilers N (see Reburn, SNCR)

13 Hybrid SNCR + SCR Coal-fired boilers N (see SNCR, SCR)

14 Hydrocarbon-enhanced SNCR Coal-fired boilers N (see SNCR)

15 Intelligent controls Coal-fired boilers, Oil/NG boilers, Wood/biomass boilers Y

16 Iron addition (CemStar) Cement kilns Yhttp://www.reaction-eng.com 

### VI-26

INTERNATION AL REACTION

ENGINEERING Technology Applicability Summary in Appendix C (Y/N)

17 Kiln dust insufflation Cement kilns N (see O 2 - enhanced combustion)

18 Kiln temperature control Cement kilns Y

19 LNB + FGR Coal-fired boilers, Oil/NG boilers, Process heaters, Pyrolysis furnaces N (see LNB, FGR)

20 Low-Emission Combustion (LEC) Reciprocating Engines Y

21 Low NO x Burners Coal-fired boilers, Oil/NG boilers, Glass Melters, Pyrolysis furnaces, Process heaters, Cement kilns Y

22 Low-NO x Calciner Cement kilns Y

23 Mid-kiln or tower tire injection Cement kilns Y

24 Non-Selective Catalytic Reduction (NSCR) Reciprocating Engines Y

25 NOxTech Reciprocating Engines Y

26 Overfire Air Coal-fired boilers, Wood/Biomass boilers. Oil/Nat'l Gas Boilers Y

27 Oxy-Fuel Firing Glass Melters Y

28 Oxygen-enhanced Combustion Modifications Coal-fired boilers, Cement kilns, Glass Melters Y

29 Pre-stratified Charge Reciprocating Engines Y

30 Rich Reagent Injection (RRI) Coal-fired boilers N (see SNCR)

31 SCONOX Oil/Nat'l Gas Boilers, Reciprocating Engines, Gas Turbines Y

32 SCR Coal-fired boilers, Oil/NG boilers, Glass Melters, Pyrolysis furnaces, Process heaters, Reciprocating Engines, Gas Turbines Yhttp://www.reaction-eng.com 

### VI-27

INTERNATION AL REACTION

ENGINEERING Technology Applicability Summary in Appendix C (Y/N)

33 SNCR Coal-fired boilers, Wood/Biomass boilers Oil/NG b oilers, Glass Melters, Pyrolysis furnaces, Cement kilns, Reciprocating Engines, Gas Turbines Y

34 Tempering (Steam, water or air injection) Gas turbines, Process heat ers, Pyrolysis furnaces Yhttp://www.reaction-eng.com 

### VI-28

INTERNATION AL REACTION

ENGINEERINGCommercialYYYYYYYYCost, $/T100-200500-2000(Highlydependenton cost ofreburn fuel)300-600800-2000500-1000<100-300200-1000250-600Performance10 to 30% NOxreduction20 to 30% NOxreductionfor Fuel-Lean GasReburning (no OFA), and30 to 60% reduction forconventional reburning.50-70%50 to 90% NOxreduction,de-pending on how muchcatalyst is installed.40 to 60% NOxreduction0 to 30% NOxreduction.30-50% NOxreduction.20 to 40% NOxreduction.ApplicabilityMost units.Most units. Furnaceheight (residencetime) may restrictsome applicationsSame as individualtechnologies.Same as individualtechnologies.Most units. Can usemore NH3with lessslip.Available for allunitsMost boilers alreadyhave LNB.Most units. Furnaceheight may restrictsome applicationsDescriptionBurner air and/or fuel modificationsto improve air/fuel interactionInject portion of the fuel into thefurnace downstream of burner zone.Usually requires OFA to completecombustionCo-inject reburning fuel and SNCRreagent.Overfeed reagent into the furnace, andallow ammonia carryover to furtherreduce NOxover a catalystdownstream.Inject small amount of natural gas tocreate radicals that enhance SNCReffectiveness at 1700 to 2000 °F.Emerging technology.Sensors and software optimize air-fuelratio to burners.Burners designed to produce lowerNOxemissions – “staged” combustionForm of “staged” combustion. Divertportion of the air from the windbox toOFA ports installed above theburners.TechnologyBurnerModificationsFuel ReburnHybrid Reburn +SNCRHybrid SNCR +SCRHydrocarbonenhanced SNCR“Intelligent”ControlsLow-NOxburners(LNB)Overfire air (OFA)Table 15. Coal-Fired Boilers.http://www.reaction-eng.com 

### VI-29

INTERNATION AL REACTION

ENGINEERINGCommercialYYYYCost, $/T1000-2000800-15001500-2000800-1500Performance30-50% beyond OFA20 to 30% additional NOxreduction beyond OFA.70 to 90+% NOxreduction25 to 50% NOxreduction,depending on the furnacetemperature and time forreaction.ApplicabilityBest applied withnew OFA systemdesigned to achievestoichiometric airfuel ratio < 0.8.Most units.Modeling required todetermine injectionlocations.Most units. Spaceavailability mayconstrain someoptions. High sulfurfuels morechallengingMost. Residencetime and temperaturecharacteristics areimportant.DescriptionImprove effectiveness of OFAoperation by injecting O2into fuelrich flames. Operate more fuel-richwithout the problems. Emergingtechnology.SNCR applied to fuel-rich region ofOFA system.Ammonia added upstream of catalyticreactor installed upstream of airpreheater (conventional), downstreamof a hot ESP (low dust), ordownstream of the cold ESP (tailend).Inject ammonia-based reagent intoupper furnace (1700-2000 degrees F)to destroy NOx.TechnologyOxygen-enhancedcombustion modificationRich Reagent Injection(RRI)Selective CatalyticReduction (SCR)Selective Non-catalyticReduction (SNCR)Table 15. Coal-Fired Boilers (Continued).http://www.reaction-eng.com 

### VI-30

INTERNATION AL REACTION

ENGINEERINGCommercialYYYYYYCost, $/T115-200+Not available,but less thanLEC.190-700,depending onengine BHP.$6500 for 80BHP.<500~ 1000< 500Performance80% NOxreduction. Useof plasma ignition is new,so there is limitedoperating experience.~80%80-90% NOxreduction40-98% NOxreduction,depending on engine speed.Average of 95% reductionis achievable.90-95% NOxreduction, 60-80% particulate removal,50-70% CO removal, 90%hydrocarbon removal.80-95% NOxreduction.ApplicabilityFor lean-burn engines (tosupport ignition under verylean conditions)Same as LECNot available for allengines, some fuelefficiency decrease.Requires turbo-charging orinter-cooling upgrades.Requires rich-burn engine toproduce hydrocarbons usedfor NOxreduction.Applicable to all engines,but exhaust must be heatedfor most engines.For carbureted, rich-burnengines.DescriptionProvide continuous electrical dischargeat the spark plug gap for 10 to 90oofcrankshaft rotation. This extendedenergy delivery ensures combustion inthe leanest of conditions.Enhance mixing of fuel and air underlean conditionsRetrofit kits available to implement leanburn for new engines as well as retrofit.Install oxidation-reduction catalyst thatuses hydrocarbons in exhaust to destroyNOx.Inject chemical reagent into exhaust attemperatures of 1400 to 1500 °F.Inject air into intake manifold so that thepiston initially draws in air, followed bya fuel-rich air-fuel mixture.TechnologyHigh Energy IgnitionHigh-Pressure FuelInjectionLow-EmissionCombustion (LEC)Non-SelectiveCatalytic Reduction(NSCR)NOxTechPre-stratified ChargeTable 16. Reciprocating Engines.http://www.reaction-eng.com 

### VI-31

INTERNATION AL REACTION

ENGINEERINGCommercialYYCost, $/TNot available< 1000Performance95% reduction of NOx,CO, and hydrocarbons.75-90% NOx reductionApplicabilityTheoretically works for allengines. Catalystregeneration is difficult.Little operating dataavailable.All engine types(especially diesel), butdifficult to control if loadrange is wide.DescriptionAdd chemical reactor for NOxsorption, followed by regeneration.Inject ammonia upstream of a catalystthat operates at 300-900 °F.TechnologySCONOXSCRTable 16. Reciprocating Engines (Continued).http://www.reaction-eng.com 

### VI-32

INTERNATION AL REACTION

ENGINEERINGCommercialYYYYYYCost, $/T1000-2000100-5000-100100-300200-500500-1000Performance0 to 50% NOxreduction,depending on existingequipment.20 to 30% NOxreduction,but can reduce kilncapacity due to highmoisture content.20 to 30% NOxreduction,depending on cementspecifications0 to 20% NOxreduction inconjunction with a 0-5%kiln capacity increase.0 to 20% NOxreduction,and requires less operatorattention.0 to 20% NOxreduction;production may increase.ApplicabilityMore easily implemented intower kilns.Tried in long kilns andpreheater/precalciner kilns, buteffectiveness is limited bypoor combustion and increasedhydrocarbon or SO2emissions.Applicable to all kiln types,but may affect cement quality.Applicable to long kilns.Applicable to all kiln types,but risks unacceptable cementquality.Applicable to all kiln types.Can reduce cement quality onsome kilns.DescriptionInject portion of the fueldownstream of the main flame tocreate locally reducing conditionswhere NOxcan be destroyed.Sometimes includes installing a“NOxfan” to increase burnout.Add sewerage sludge to mid-kilnor tower for combined SNCR andfuel-staging affect.Change cement formulation byadding waste iron to lowerclinkering temperature andsuppress NOx.Re-inject cement kiln dust (CKD)into flame zone to lower peaktemperatures and increase clinkerproduction.Add temperature-monitoringdevice to kiln controls tominimize high-temperatureexcursions where more NOxisemitted.Replace open pipe burner withmulti-annular design. Usuallyaccompanied by installation of anindirect coal feed system toreduce coal transport airflow.TechnologyAir or fuel stagingBiosolids injectionIron addition(CemStar)Kiln dust insufflationKiln temperaturecontrolLow-NOxBurner(LNB)Table 17. Cement Kilns.http://www.reaction-eng.com 

### VI-33

INTERNATION AL REACTION

ENGINEERINGCommercialYYYYCost, $/T1000-50000-1000200-1000200-1000Performance30-50% NOx. Littleexperience15 to 30% NOxreduction;generate revenues.0 to 20% NOxreductionand potential for additionalcapacity.30 to 70% NOxreductions,depending on access totemperatures in 1600-1800°F range.ApplicabilityApplicable only topreheater/precalciner kilns.Injected mid-kiln in long kilns,and into lower tower forpreheater/precalciner kilns.Cement quality could be moredifficult to control.Applicable topreheater/precalciner kilns.DescriptionReplace calciner with new lowNOxdesign.Inject whole tires or shreddedtires downstream of the flame toreduce NOxformed in the burner.O2lance to decrease fuelrequirement for clinkerformation.Inject ammonia-based reagentinto upper furnace (1700-2000oF)to destroy NOx.TechnologyLow-NOxcalcinersMid-kiln or towertire injectionOxygenenrichmentSNCRTable 17. Cement Kilns (Continued).http://www.reaction-eng.com 

### VI-34

INTERNATION AL REACTION

ENGINEERINGCommercialYYYYYYCost, $/T500-3000200-10001000-2000Not available2000-100001300-3000Performance40-80% NOxreduction30-60% NOxreduction40-80% NOxreduction70-99% NOxreductionclaimed.70-90+% NOxreduction30-60% NOxreductionApplicabilityMost units, but could affectheat balance. Induced FGRrequires pressure part changes.Most boilers.Most units. Furnace heightmay restrict some applicationsSteam-hydrogen regenerationgas not practical for someboilers. Limited testing todate.Most units. Space availabilitymay constrain some options.High sulfur fuels morechallengingMost. Residence time andtemperature characteristics areimportant.DescriptionRecycle 15-25% of the fluegas to the windbox to reduceflame temperature. Can useeductors for induced FGRBurners designed to producelower NOxemissions –“staged” combustionForm of “staged”combustion. Divert portionof the air from the windboxto OFA ports installed aboveAdd chemical reactor forNOxsorption, followed byregeneration.Ammonia added upstream ofcatalytic reactor.Inject ammonia-basedreagent into upper furnace(1700-2000oF) to destroyNOx.TechnologyFlue GasRecirculation (FGR)Low-NOxBurnersOverfire Air (OFA)SCONOXSCRSNCRTable 18. Oil/Natural Gas-Fired Boilers.http://www.reaction-eng.com 

### VI-35

INTERNATION AL REACTION

ENGINEERINGTable 19. Turbines.CommercialYYYYYCost,$/T> 5001000-2000> 7000500-10000+2000-7000Performance0.05 lb/MBtu (80%reduction) has beenmeasured.0.1 lb/MBtu (70%reduction) can beguaranteed on new units.0.02 lb/MBtu (> 90%reduction) claimed.90 % reduction down to0.03 lb/MBtu.0.15 lb./MBtu (50%reduction) can beachieved.ApplicabilityLimited experience.Most turbines. Flameinstability a problem for somegas fuels.Reliability of system not yetproven.Applied to most turbinesCan be applied to mostturbines, but some willexperience slight efficiencyloss.DescriptionCatalytic combustor reducescombustion temperature belowthermal NOxlimit.Low NOxcombustor is GT“equivalent” of LNB.Add chemical reactor for NOxsorption, followed byregeneration.Add catalyst section to HRSGto destroy NOxat temperaturesof 600 to 900 °F.Spray water or steam intocombustor to suppress flametemperature.TechnologyCatalytic combustionDLN (fuel-leancombustion)SCONOXSCRTempering (Water/Steam Injection)http://www.reaction-eng.com 

### VI-36

INTERNATION AL REACTION

ENGINEERINGTable 20. Wood or Biomass-Fired Boilers.CommercialYYYYCost, $/T300-3000200-500200-2000900-2200Performance40-60% NOxreduction0-20 % NOxreduction20-60% NOxreduction40-80 % NOxreductionreportedApplicabilityStoker, water tubeWatertube boilersStoker, watertubeStoker, FBC, watertubeDescriptionInject portion of the fuel into thefurnace downstream of burnerzone. Usually requires OFA tocomplete combustionSensors and software optimizeair-fuel ratio to burners.Form of “staged” combustion.Divert portion of the air from thewindbox to OFA ports installedabove the burners.Inject ammonia-based reagentinto upper furnace (1700-2000oF) to destroy NOx.TechnologyFuel Reburn"Intelligent"ControlsOverfire air (OFA)Selective NonCatalytic Reduction(SNCR)http://www.reaction-eng.com 

### VI-37

INTERNATION AL REACTION

ENGINEERINGTable 21. Process Heaters.CommercialYYYYCost, $/TonGas: 1,720-2,480Oil: 2,390-2,910Gas: 1,210-1,820Oil: 1,200-2,340Gas: 810-1,280Oil: 400-1,440Gas: 5,130-10,600Oil: 3,710-6,490Gas: 1,470-2,640Oil: 1,230-2,350Performance50-60%30-50%Ultra-LNB: 50-80%75-90%50-70%ApplicabilityOil/gas fired, MDonlyOil/gas firedOil/gas firedOil/gas firedDescriptionStaged firing with fluegas mixed with precombustion airStaged firing; Combinesstaged firing withinduced flue gasrecirculationAmmonia addedupstream of catalyticreactor.Inject ammonia-basedreagent into upperfurnace (1700-2000oF)to destroy NOx.TechnologyLNB + FGRLow-NOxBurners,Ultra Low-NOxBurnersSCRSNCRhttp://www.reaction-eng.com 

### VI-38

INTERNATION AL REACTION

ENGINEERINGTable 22. Glass Melting Furnaces.CommercialYYYYYCost, $/Ton890-1,0402,600-9,900790-1,680moderate2,150-4,400Performance5-25%10-30%40%50-65%80-85%ApplicabilityAny glass meltingfurnace w/ >50% culletin batchOil/gas fired furnacesDescriptionResidual heat of waste gas usedto preheat batch materials/cullet(recycled glass)Burners designed to producelower NOxemissions – “staged”b tiInject portion of the fuel into thefurnace downstream of burnerzone.Oxygen used instead of air;requires different furnace designTechnologyBatch/CulletPreheatingElectric BoostLow-NOxBurnersNatural Gas ReburnOxy-Fuel Firinghttp://www.reaction-eng.com 

### VI-39

INTERNATION AL REACTION

ENGINEERING 

### The formation of NO x 

### is a byproduct of the combustion of fossil fuels. Nitrogen contained in fuels such as coal and oil, as well as the harm less nitrogen in the air, will react with oxygen during combustion to form nitrogen oxides (NO x 

### ). The degree to which this formation evolves is dependent on many factors, includi ng both the combustion process its elf and the properties of the particular fuel being burned. This explains w hy similar boilers firing di fferent fuels or similar fuels burned in different boile rs will yiel d different NO x 

### emissions.

As a result of these complex inte ractions in the formation of NO x 

### , an equally large number of approaches to minimize or reduce its emissions into the atmosphere have been and continue to be developed. A relatively simp le way of understanding the many technologies available for NO x 

### emission control is to divide them into two major categories: (1) those that minimize the formation of NO x 

### during the combustion process (e.g., smaller quantities of NO x 

### are formed); and (2) those that reduce NO x 

### after the combustion process. It is common to refer to the first approach as “combustion modifica tions” whereas technologies in th e second category are termed "post-combustion controls."

Within each of these categories, several tec hnologies and variations of the same technology exist. Finally, combinations of some of th ese technologies are not only possible but often desirable as they may produce more effective NO x 

### control than the application of a stand-alone technology.

The following summaries describe the major technologies in each category.

3.2 Coal-Fired Boilers Combustion modifications can vary from simple "tuning" or optimization efforts (similar to a "tune-up" of a car) to the deployment of dedicated technolog ies such as low-NO x 

### burners (LNB), Overfire air (OFA), or Reburn. All com bustion modification approaches face a common challenge: that of striki ng a balance between NO x 

### reduction and fuel effici ency. The concern is exemplified by the typically higher carbon levels in the fly ash, which reflect lower efficiency (more fuel needed for the same electrical output) and which may contaminate the fly ash itself, possibly making it unsuitable for reutiliza tion (e.g., cement and concrete production).

Combustion Optimization

Combustion optimization efforts can lead to reductions in NO x 

### emissions of 5%-15% or even higher in cases where a unit may be poorly "tune d." It is important to remember that optimization results are truly a function of the "pre -optimization" condition of the power plant or unit, and as such have limited opportunity for dr astic emission reductions. Recent development of "intelligent controls" - software -based systems that "learn" to operate a unit and then maintain its performance during normal operation may go a long way towards keeping plants well-tuned as they age.

LNB’s and OFA

LNB’s and OFA represent practical appro aches to minimizing the formation of NO x 

### during combustion. Simply, this is accomplished by cont rolling the quantities and the way in whichhttp://www.reaction-eng.com 

### VI-40

INTERNATION AL REACTION

ENGINEERING 

### fuel and air are introduced and mixe d in the boiler (usually referred to as "fuel or air staging"). These technologies are the most prevalent in the pow er industry at present. For example, plants that have had to comply with Phase I of Title IV of the CAAA of 1990 ha ve largely used these technologies for compliance. (Phase II of the Ti tle IV has required the use of post-combustion technologies to meet more st ringent requirements for both Group 1 and Group 2 boilers.) Competing manufacturers have pr oprietary designs, geared towa rds application in different boiler types, as well as reflecti ng their own design philosophies. LNB’s and OFA, which can be used separately or as a system, are capable of NO x 

### reductions of 40% - 60% from uncontrolled levels. Again, the type of boiler (e.g., dry vs . wet-bottom, wall- vs. tangential-fired, NSPS vs. pre-NSPS) and the type of fuel (e.g., bituminous vs. sub-bituminous) will influence the actual performance achieved. NO x 

### emission rates on the order of 0. 15 lb/MBtu can be achieved with low NO x 

### burners under circumstances, particularly in dry-bottom boilers burning low-rank coals.

LNB’s/OFA have little or no impact on operating costs, other than those noted above. As such, the economics of these technologies are driven by capital/retrofit costs which typically range from $10-$40/kW, with the lower range reflectin g easier "plug-in" application, whereas the higher costs are typically associ ated with more difficult and i nvolved retrofits (e.g., where new controls or other systems may be repl aced as part of the LNB retrofit).

From the standpoint of scheduling retrofits for existing units, LNB/OFA retrofit projects have "lead" times of 10-14 weeks and can require outages of 6-10 weeks, depending on factors such as scope of work, integration with ot her plant outage re quirements, etc.

Reburn

Reburn, while generically included in the "Combustion Modification" category, is different from the other technologies in this group (LNBs/OFA) in that it "destroys" NO x 

### through chemically reducing conditions shortly after it is formed rather than minimizing its formation as discussed previously. From a practical standpoint, this is accomplishe d by introducing the reburn fuel (theoretically any fossil fuel can be used, but natural gas is th e most common) into the boiler above the main burner region. Subsequently, th is "fuel-rich" environm ent reacts with and "destroys" the NO x 

### formed in the main burners. This technology has been implemented in the U.S. and overseas, and while not as common as LN B/OFA, it is commercial at this time. Owing to stricter compatibility criteria, reburn is not as universal as LNB/OFA in its applicability to the overall boiler population. Specific cr iteria such as boiler size, avai lability of natural gas, type and quality of the main fuel ar e all important in determining the suitability of a unit for this technology. One important feature of reburn is its compatibility with cy clone boilers, for which the previously mentioned tec hnologies are not particularly well suited. Cyclones boilers represent over 25,000 MW of capacity in the U.S.

Reburn performance has been shown to range from 35%-60% depending on such factors as reburn fuel type a nd quantity, initial NO x 

### level, boiler design, etc. Re burn can be thought of as a "dial-in" NO x 

### technology in that NO x 

### reductions are a function of the amount of reburn fuel. This feature may provide strategi c value in compliance scenarios.http://www.reaction-eng.com 

### VI-41

INTERNATION AL REACTION

ENGINEERING 

### With respect to cost, systems using natural gas as the reburn fuel range from $15/kW to $30/kW whereas those using coal for reburn range fr om $30/kW to $60/kW. Operating costs are primarily driven by the fuel cost differential in the case of gas reburn, while for coal or oil reburn fuel preparation costs (pulveri zation and atomization, respectiv ely) represent the dominating O&M costs. Countering these costs, part icularly in the gas reburn case, are SO 2 

### , particulates, and CO 2 

### co-benefits proportional to the fraction of gas used.

Project retrofit schedules for th is technology are on the order of 15 to 20 weeks with 6 to 10 weeks of outage time likely.

Recently, reburn technology has evolved into several variations of the original approach. One of these is “Fuel Lean Gas Reburn" (FLGR) de veloped for specific applications where NO x 

### reductions of around 30%-40% may be required. FLGR uses less gas than conventional reburn (3%-7% vs 15%-20%), and its capital cost is le ss than $10/kW, making it a potentially effective option in specific applications.

SCR and SNCR

Readily available post-combustion NO x 

### controls are limited to selective non-catalytic reduction (SNCR) and selective cata lytic reduction (SCR). They are funda mentally similar in that both use an ammonia-containing reag ent to react with the NO x 

### produced in the boil er and convert it to nitrogen and water. SNCR accomplishes this at higher temperatures (1700oF-2000oF) in the upper furnace region of the boiler, while SCR opera tes at lower temperatur es (about 600oF) and hence needs a catalyst to produce the de sired reaction between ammonia and NO x 

### .
While this difference between the two technolog ies may seem minor, it results in significant difference in performance and costs. This is beca use in the case of SNCR , the reaction occurs in a somewhat uncontrolled fashion (e.g., the existing upper furnace becomes the "makeshift" reactor, which is not what it was originally de signed to be), while in the SCR case, a dedicated reactor and the reaction-promoti ng catalyst ensure a highly contro lled, efficient reaction. In practice, this means that SNCR has lower capital costs (no need for a reactor/catalyst); higher operating costs (lower efficiency means that mo re reagent is needed to accomplish a given reduction in NO x 

### ); and finally, has limited NO x 

### reduction capability (t ypically 30%-40%, with some cases achieving reductions in the 50% rang e). SCR, on the other hand, has higher capital costs but offers lower operating cost s and the opportunity for very high NO x 

### reductions (up to 90%).

Capital costs range from $10 to $15/kW and $60 to $100/kW for SNCR and SCR, respectively. Operating costs are driven prim arily by the consumption of the chemical reagent – usually urea for SNCR and ammonia for SCR, which in turn is dependent upon the efficiency of the process (usually referred to in terms of reagen t utilization) as well as the initial NO x 

### level and the desired percent reduction. Two additional parameters important in the ove rall operating costs are (1) the potential contamination of fly ash by ammonia, making it unusable and (2) the life cycle of the catalyst due to fly ash.http://www.reaction-eng.com 

### VI-42

INTERNATION AL REACTION

ENGINEERING 

### Combined Approaches

In theory, most of these technologies can be used together. However, NO x 

### reductions are not necessarily additive, and more importantly, the “economics” of the combined technologies may or may not be cost-effective. Such analys es are highly site- a nd strategy-specific.

However, several such combinations of technol ogy are considered attr active and have or are gaining acceptance. For example, the combina tion of LNB/OFA with either SCR or SNCR is more prevalent than the applic ation of the post-combustion t echnologies alone. The economics of this approach are justified by the reduced chemical (SNCR) and capital costs (SCR – smaller reactor/catalyst) due to lower NO x 

### levels entering the SCR/SNCR system. Another example is the combination of Reburn with SNCR, driven by the synergisms between the two (similar location, temperatures in the boiler). This application may yield NO x 

### reductions of 60%-70% with capital costs in the $20- $30/kW range, but has a relatively high operating cost due to reagent and reburning fuel consumption.

3.3 Reciprocating Engines Several control technologies are av ailable for ICE’s, having a wide range of complexity, cost and performance.

Some in-cylinder methods offer low to moderate NO x 

### reductions at costs well below $1,000/ton. These include injection timing retard, and air/fuel ratio adjustment (with or without high-energy ignition). These methods ar e widely available, and NO x 

### performance will vary from one engine design to another. However, fuel efficiency can suffer as a result of these methods and emissions of products of incomplete combustion can increase.

Spark-ignited engines that can be retrofitte d with Low-Emission Combustion (LEC) technology can potentially achieve significant NO x 

### reductions (80 to 90%). LEC technology can be expensive to retrofit on some engines, and it may not be available from all engine manufacturers. For large, low-speed engines, LEC tec hnology is estimated to provide annual NO x 

### reductions of about 80% at under $1,000/ton under most conditions. LEC technology is estimated to be more cost effective on smaller, medium-speed engine s (under $500/ton for annual control under most conditions). It is estimated to be somewhat more expensive for dual-fuel engines (annual control at a capacity factor of 65% is estimated to cost under $1,000/ton).

SCR is the only commercially available choice fo r post-combustion control of diesel and leanburn spark-ignition engines. Experience in th e U.S. with SCR on these engines is growing, especially for diesel engines. SCR has been appl ied to approximately 30 diesel engines and to an equivalent number of constant -load lean burn ICE’s. Experience with SCR on variable-load engines is limited. In analysis using data from case studies, it was estimated that SCR provides annual NO x 

### reductions of as high as 90% at a cost below $1,000/ton in all cases, except for very low capacity factors (~10%), and it provides seas onal reductions at a cost of under $1,000/ton for engines operating at high capacity fa ctors (typically, 65% or greater).

Recent developments from the application of ur ea-SCR on mobile sources (diesel trucks) offer the possibility of reducing the size and capital cost of SCR systems for stationary ICE’s. Thishttp://www.reaction-eng.com 

### VI-43

INTERNATION AL REACTION

ENGINEERING 

### new technology, developed from efforts to apply SCR to mobile diesel engines, appears to make it possible to achieve much more cost-effective NO x 

### reduction on stationary ICE’s that operate for only a few hundreds of hours a year. NO x 

### reduction of about 75% is estimated to be possible for under $2,000/ton even for seasonal controls of some stationary ICE’s that operate only a few hundred hours each ozone season. Seasonal control at a cost of under $1,000/ton is estimated to be achievable for most applications w ith capacity factor greater than 45%.

3.4 Cement Kilns As with other combustion systems, modifying the combustion process is one strategy for reducing NO x 

### in cement kilns. However, the quality of the clinker produced by the kiln can be affected by combustion modifications so these must be undertaken carefully.

Monitoring temperature and excess air in the com bustion zone increases the efficiency of the cement-making process and can result in reduced NO x 

### emissions. Combustion modifications include staged combustion of air or fuel. Specifically designed low-NO x 

### burners are sometimes used. Even without low-NO x 

### burners, staging can be achieved by adding some of the fuel midkiln, as in mid-kiln injection of tires. Mid-kiln injec tion of fuel (most often tires) was in practice in twenty kilns in the U.S. in 2000.

Iron addition (CemStar process) ha s been used at about a dozen facilities in the U.S. This reduces the temperature needed in the kiln for formation of clinker and allows the combustion zone to operate cooler (and thus reducing NO x 

### ).

Post-combustion (post-kiln) NO x 

### controls include SCR and SNCR. SCR has not been used on cement kilns in the U.S.; pilot studies have been conducted in Europe. SNCR technology requires a specific temperature window and residence time; these are not attainable in all cement kilns. SNCR can be applied to preheater/precalcin er kilns. SNCR is widely practiced in Europe on cement kilns, but to date there have been only a handful of demonstrations in the U.S.

3.5 Natural Gas and Oil Fired Boilers

The menu of NO x 

### control options for gas and oil-fired boile rs is essentially the same as for coalfired boilers. One noted exception is the use of Flue Gas Recirculation (FGR), which is not effective in coal applications a nd hence, is not mentioned there.

While the control technologies are common to the coal-fired options, appl ication issues require different considerations and an alyses. Examples range from di fferences in the inherent NO x 

### formation amongst the fuels (thermal NO x 

### vs. “fuel”-NO x 

### ), which dictate that combustion-based technologies are designed accordingly for each fuel , to the fact that gas produces no PM or SO 2 

### /SO 3 

### and hence can afford some design changes from coal and oil applications. Equally important are the economics of the different fuels, which may favor different technology approaches.

In summary it can be said that the available menu of technologies is the same as for coal applications, but that (at least for gas), depl oyment of these technologies tends to be less constraining than for coal.http://www.reaction-eng.com 

### VI-44

INTERNATION AL REACTION

ENGINEERING 

### 3.6 Turbines There have been some important developments in gas turbine NO x 

### control technology, but wellestablished technologies continue to play an important role in reduction of NO x 

### . Dry Low NO x 

### (DLN), catalytic combustion, and some new post- combustion methods are making their way into the control technology market, while water or steam injection and SCR continue to be important technologies for reducing NO x 

### from gas turbines.

Many turbine manufacturers can co nvert or replace conventional co mbustors on existing turbines with DLN combustors. DLN combustion retr ofits have been made possible by recent developments in gas turbine combustor tec hnology. DLN technology offers the potential for substantial reduction of NO x 

### from turbines firing natural gas or other low-nitrogen fuels, as well as improved engine performance when compared to wet controls (water or steam injection). For turbines under about 15 MW in size, NO x 

### emissions of 25 ppm can be guaranteed for new turbines and emissions below 42 ppm can be gua ranteed for retrofitted turbines. For large turbines (75 MW and highe r in size), controlled NO x 

### emission levels of as low as 9 ppm have been guaranteed, even for retrofits.

DLN capital costs vary with the size of the turb ine and the specifics of the particular turbine being retrofitted. The baseline NO x 

### level significantly affects the estimate of cost per ton of NO x 

### reduced. Using expected baseline NO x 

### emissions levels provided by the turbine manufacturers and retrofit costs expected to be typical of most applications , retrofit of DLN on industrial turbines (about 3 to 10 MW) originally equipped with conv entional combusti on control is estimated to provide NO x 

### reductions under $2,000/ton for annua l controls with high capacity factors and at a higher cost for seasonal controls. For larger turbines (~75 MW), cost was estimated to be well below $1,000/t on for nearly all conditions.

Water injection and steam inj ection are two well-established technologies that can offer controlled NO x 

### emission levels below 42 ppm in many cas es. Because water or steam injection technologies frequently have lower capital cost than DLN but higher va riable costs, these technologies can be more attractive for peaki ng turbines or other turbines that operate infrequently. It was estimated that water injection installed on peaking units that operate 200 hours to 400 hours in the summer would reduce NO x 

### at a cost of about $2,500/ton to about $7,000/ton, depending upon the number of operating hours and the fuel used (gas or distillate oil).

SCR continues to be the most widely used post-combustion technology for gas turbines. Catalyst technology developments have made SCR viable over a wider temperature range. This makes SCR a viable control option in situations that were difficult in the past, such as simplecycle turbines that may now benefit from high- temperature SCR and combined-cycle turbines with duct burners that may now be nefit from low-temperature SCR.

The cost of NO x 

### reduction with SCR varies considerably according to application, turbine size, and the type of SCR technology that is appropriat e for the application. As in the case of the DLN cost estimates, expected baseline NO x 

### emissions levels provided by the turbine manufacturers were used as a basis for cost calculations. Conventional SCR on a large (~75MW) combined-cycle turbine with high cap acity factors was estimated to cost abouthttp://www.reaction-eng.com 

### VI-45

INTERNATION AL REACTION

ENGINEERING 

### $440/ton for annual controls and $870/ton for se asonal controls, for tu rbines equipped with conventional combustion technology (baseline NO x 

### emissions of 154 ppm). For turbines with lower baseline NO x 

### emissions (such as those equipped w ith DLN combustors having baseline NO x 

### emissions of 15 ppm), the cost per ton of additional NO x 

### removed was estimated to be greater, ranging from about $3,700/ ton (annual control, high capaci ty factor) to over $13,000/ton (seasonal controls, low capacity f actor). On smaller turbines (~ 5 MW), the cost of conventional SCR is estimated to be as low as $1,300/ton (with annual control and conventional combustion technology having baseline NO x 

### emissions of 142 ppm). Seasonal controls for smaller turbines are estimated at over $15,000/ton of NO x 

### removed at a low capacity factor (45%) with baseline NO x 

### emissions of 42 ppm.

For installations that may be better suited for high- or low-temperature SCR variants, such as simple-cycle turbines (high-temperature SCR) or combined-cycle turbines with limited space (low-temperature SCR), the cost of SCR is somewhat higher than for conventional SCR on a combined-cycle plant. A 75 MW turbine at a high capacity factor equi pped with conventional combustion technology (baseline NO x 

### emissions of 154 ppm) can be controlled annually with high- or low-temperature SCR for about $550/ton and for about $1,200/ton seasonally. As with conventional SCR, turbines with lower baseline NO x 

### emissions (such as those equipped with DLN combustors) showed a higher cost per ton of NO x 

### reduction. The estimated cost of NO x 

### reduction for a 75 MW turbine with baseline NO x 

### emissions of 15 ppm ranges from $5,170/ton (annual controls, high capacity fa ctor of 85%) to as high as $20,000/ton (seasonal controls, low capacity factor of 45%). On sm aller turbines (~5MW), the cost for high- or low-temperature SCR is estimated to be as low as $2,000/ton with annual control and conventional combustion technology (baseline NO x 

### emissions of 142 ppm). Cost is estimated to range from $6,750/ton (annual controls, high capacity factor of 85%) to about $27,0 00/ton (seasonal controls, low capacity factor of 45%) with baseline NO x 

### emissions of 42 ppm.

Emerging combustion technologies (such as catalytic combustion) and post-combustion technologies (such as SCONOx) offe r the potential for very low NO x 

### emission levels. Because there is much less experience with these technologies, available cost information is limited.http://www.reaction-eng.com 

### VI-46

INTERNATION AL REACTION

ENGINEERING 

### 4 PM CONTROL TECHNOLOGIES

4.1 Overview As discussed in Section 2, 8 source categories ma ke up about 92% of the PM emissions and are summarized in Table 23. Detailed information on PM control technologies has been obtained for industrial processes that generate particulate matter. We have not provided cost information on fugitive emissions, however, since costs of fugitive dust control are highly variable and it is difficult to find an adequate metric for costs and then quantify them.

Table 24 lists all the technologies considered. These are commercial technologies, in that vendors are offering these technologi es with demonstrated operati ng experience in a wide range of applications. Table 24 gives the following information about each technology:

• Name

• Source categories to which th e technology can be applied

• Summary prepared? (Y/N)

Technology summaries are cont ained in Appendix D. Table 23. PM emissions from top eight source categories.

# Units Total PM TPY % PM Emissions Coal-Fired Boilers 88 46,010 40% Mineral Processing 85 24,499 21% Petrochemical 42 10,836 9% Wood Boilers 24 5,718 5% Refinery Emissions 11 5,631 5% Primary Metal Production 20 4,697 4% Pulp and Paper 15 4,476 4% Smelting Operations 8 3,555 3% Others 28 9,168 8% Total (>100 TPY) 321 114,589http://www.reaction-eng.com 

### VI-47

INTERNATION AL REACTION

ENGINEERING 

### Table 24. PM Control Technologies

4.2 PM Control for Coal-Fired Boile rs and Other Combustion Sources Particulate matter is generated by a variety of physical and chemical processes. It is emitted to the atmosphere through combustion, industrial processes, fugitive emissions and natural sources. In combustion processes, the mineral matter (i norganic impurities) is converted to ash. The particles suspended in the flue gas are known as fly ash. Fly ash constitutes the primary particulate matter, which enters the particulate control device. Particulate matter is in general referred to as "PM", "PM10", "P M2.5" (particulate ma tter (PM) with an aerodynamic equivalent diameter of 10 microns or less and 2.5 microns or less, respectively).

Quantity and characteristics of the fly ash and particle size distribution depend on the mineral matter content of the fuel, combustion system , and operating conditions . Combustion technique mainly determines the particle size distribution in the fly ash and hence the final particulate emissions. Common combustion systems in pulve rized coal firing include dry bottom, wall (front, opposed) and corner (tangential) burners and wet bottom furnaces. In dry bottom boilers, 10-20% of the ash is discharged as dry, bottom ash. In wet bottom boilers, 50-60% of the ash is discharged at the bottom of the boiler as slag. Stokers or grat e-fired boilers are used to burn coal, wood and waste. The majority of the as h falls through the grate and is discharged as bottom ash. Mineral composition of the coal an d the amount of carbon in the fly ash determine the quantity, resistivity and cohesivity of the fly ash.

PM emissions from other point source proces ses involve similar phenomena where particulate matter is carried with the flue gas, in suspensi on to the stack. Hence, the general technologies applicable to one source are typically suitable fo r the others as well. Factors such as type and Technology Applicability Summary (Y/N)
1 Cyclones Coal-fired boilers, Oil/NG boilers, Wood/Biomass boilers, Cement kilns, Smelting Y

2 Electrostatic precipitator (ESP) Coal-fired boilers, Oil/NG boilers, Wood/Biomass boilers, Cement kilns Y

3 Fabric Filter Coal-fired boilers, Oil/NG boilers, Wood/Biomass boilers, Cement kilns Y

4 PM Scrubber Coal-fired boilers, Oil/NG boilers, Wood/Biomass boilers, Cement kilns, smelting Y

5 Surface modification

• Water

• Surfactants

• Shape Fugitive Emissions, Mineral Products N

6 Traffic operations Fugitive Emissions, Mineral Products Nhttp://www.reaction-eng.com 

### VI-48

INTERNATION AL REACTION

ENGINEERING 

### quantity of PM, characteristics of the process gas (temperature, moisture, other contaminants) will have a major influence on the selection and design of the PM control technology.

Without getting into the details of the various technologies, the following four major types of particulate controls technologies are common for a variety of applications:

• Wet scrubbers – scrubbers work on the prin ciple of rapid mixing and impingement of the particulate with the liquid droplets and subsequent removal with the liquid waste. For particulate controls the “venturi sc rubber” is an effective technology whose performance is directly related to the pre ssure loss across the venturi section of the scrubber. Venturi scrubbers are effective devi ces for particulate control. However, for higher collecting efficiencies a nd a wider range of particulat e sizes, higher pressures are required. High-energy scrubbers refer to designs operating at pressure losses of 50-70 inches of water. Of course, higher pressure translates to higher energy consumption. Performance of scrubbers varies significantly across particle size range with as little as 50% capture for small (<2 microns) sizes to 99% for larger (>5 microns) sizes.

• Electrostatic Precipitators (ESP) –ESP’s opera te on the principle of electrophoresis, by imparting a charge to the particulates a nd collecting them on opposed charged plates. Dry vs. wet refers to whether the gas is wate r cooled and saturated prior to entering the charged plate area, or is collected dry on the plates. In gases with high moisture content, dry ESP’s are not suitable because the wet ga s would severely limit the ability to collect the “sticky” particulates from the plates. The wet ESP technology is capable of very high removal efficiencies and is well-suited for the wet gas environments. Both types of ESP’s are capable of 99+% removals for particle sizes above 1 micron.

• Fabric Filters – These are esse ntially “giant” vacuum cleaners. As in the case of the dry ESP, Fabric Filters are not well suited for wet gas applications. However FFs are extremely efficient in collecting PM incl uding fine (submicron) size fractions.

• Cyclones – Cyclones are devices that separate particulates from the gas stream through aerodynamic/centrifugal forces. However, the technology is only effective in removing larger size particulates (great er than about five microns).

4.3 Other Developments

While the technologies above represent the major available options for particulate control from point sources, it is relevant to note that advancements and innovative appli cation of these technologies have and will continue to occur. Examples of these can vary from simple retrofits (e.g. new filter bag materials for Fabric Filters or newer spark control electronics on ESPs) to innovations including electrostatic ally- enhanced fabric filtra tion and hybrid concepts that combine attributes of various technologies.

The Electric Power Research Institute’s (EPRI) COHPAC process and the University of North Dakota Energy and Environmental Research Center ’s Advanced Hybrid Particulate Collectorhttp://www.reaction-eng.com 

### VI-49

INTERNATION AL REACTION

ENGINEERING 

### (AHPC) are examples of hybrid particulate co llectors. In COHPAC, an ESP is followed by a pulse-jet Fabric Filter either im mediately following it or actually integrated into the original casing of the ESP (in the case of larger older ESP’s), where the FF acts as a “polishing” device significantly increasing the overall and fine particulate collection efficiency of the ESP alone. The AHPC technology can be described as an ESP w ith alternating rows of electrode plates and highly efficient membrane filter bags. In this case, the technology benefits from good synergism between the ESP and FF during bag cleaning resu lting in very high performance levels, small sizes and operational flexibility.

4.4 Costs As with most control technologies, the costs of PM controls involve both capital and operating costs. A cost-effectiveness indicator such as $/ ton as is typically used for other technologies (e.g. NO x 

### and SO 2 

### ) is very difficult to address for generic PM control costs, as the range of PM reductions for different fuels and processes is wide that cost ra nges become useless. An attempt to summarize costs in terms of capital a nd O&M components is presented below.

Capital

While it is customary to indicate capital costs on a $/kW basis for power generation applications, this is not relevant for non-power applications since no electricity is generated. However, one of the main parameters dictating the “sizing” and he nce, the costs of a PM control device, is the quantity of flue gas it must handle. As a result, it is more appropr iate to generalize capital costs on a “$/ACFM” basis. The following values represent typical costs for several of these technologies (these numbers reflect unit sizes ranging from utility-s ize units up to about 2,000,000 ACFM to smaller process down to about 10,000 ACFM))

• Dry ESPs - $15 - $40/ACFM

• Wet ESPs - $15 - $40/ACFM

• Reverse Air Fabric Filter - $17 - $40/ACFM

• Pulse Jet Fabric Filter - $12 - $40/ACFM

• Venturi Scrubber - $5 - $20/ACFM

• Cyclone - $1 - $5/ACFM

O&M

O&M costs are difficult to generali ze for such a variety of technol ogies and applications, as they are affected by many parameters th at include type of fuel, type of process, local ash disposal options, local cost of power, etc. O&M costs include fixed costs (FOM) and variable costs (VOM). The costs provided below are presented in $/year-ACFM and reflect costs for coal based fuels but should reasonably a pply to other sources as well.

Fixed O&M

• Dry ESPs - $0.25 - $0.65/yr-ACFM

• Wet ESPs - $0.15- $0.50/yr-ACFM

• Reverse Air Fabric Fi lter - $0.35 - $0.75/yr-ACFMhttp://www.reaction-eng.com 

### VI-50

INTERNATION AL REACTION

ENGINEERING 

### • Pulse Jet Fabric Fi lter - $0.50 - $0.90/yr-ACFM

• Venturi Scrubber - $0.25 - $0.65/yr-ACFM

• Cyclone – Not applicable

Variable O&M

• Dry ESPs - $0.45 - $0.60/yr-ACFM

• Wet ESPs - $0.25 - $0.50/yr-ACFM

• Reverse Air Fabric Fi lter - $0.70 - $0.80/yr-ACFM

• Pulse Jet Fabric Fi lter - $.90 - $1.1/yr-ACFM

• Venturi Scrubber - $1.2 - $1.8/yr-ACFM

• Cyclone – Not applicablehttp://www.reaction-eng.com 

### VI-51

INTERNATION AL REACTION

ENGINEERING 

### 5 MULTI-POLLUTANT CONTROL TECHNOLOGIES Emerging environmental issues and proposed fe deral legislation (President’s Clear Skies Initiative, Carper Bill, Jeffords’ Bill) as well as state legislat ion (examples include MA, NY, NC, NH, CT) have driven interest in multi-polluta nt (as opposed to single pollutant) control technologies capable of addressi ng air pollutant emissions more comprehensively with greater flexibility and ultimately lower co st. Multi-pollutant control tec hnologies integrate in-situ and/or post-combustion controls of at least two of the following pollutants: SO 2 

### , NO x 

### , and Hg (and other hazardous air pollutants including cadmium, arsenic, and nickel), and CO 2 

### . Multi-pollutant controls are intended primarily for large utility coal -fired boilers since the complexity of some of these processes as well as regulatory drivers of ten limit them to larger, utility boilers. Since coal-fired boilers represent the si ngle largest source category for both NO x 

### (as well as SO 2 

### and Hg) and PM in the thirteen-sta te region, it is worth considerin g some of these technologies.

5.1 Proposed Multi-pollutant Emission Regulations from Utility Boilers In 2002 and 2003 three “multi-pollutant” bills were introduced in the US Congress that call for coordinated reductions in NO x 

### , SO 2 

### , and Hg from coal-fired power pl ants [26]. Some of the bills also include emission limits for CO 2 

### . The three bills are briefly summarized here.

• The Clean Power Act (CPA, Jeffords) would amend the CAA to require electric power generation sources greater than 15 MW. It is the most stringent of the three proposals. It will cap SO 2 

### emissions at 2.26 mm TPY in 2008 (0.28 mm TPY in the western region that includes WRAP states and MT, WY and CA; a nd 1.98 mm TPY in the eastern region). For NO x 

### , the cap of 1.51 mm TPY is to be met by 2008. The cap on Hg is at 5 TPY, also to be met by 2008. In addition, this bill sets a cap of 2.08 billion TPY for CO 2 

### to be met by 2008 (roughly 1990 levels). Except for Hg, national tr ading will be allowed to meet the caps.

• The Clear Skies Act (CSA) has been proposed by the Bush administration. It is the least stringent of the three pr oposals. It would cap SO 2 

### emissions at 4.5 mm TP Y in 2010 and at 3 mm TPY in 2018. The corr esponding limits for NO x 

### are 3 mm TPY (in 20 08) and 1.7 mm TPY in 2018. For Hg, the proposed national caps are at 26 TPY in 2010 and 15 TPY in 2018. There are no limits for CO 2 

### . A national trading prog ram similar to th e existing trading program for SO 2 

### emissions under Title IV of the Clean Air Act will be the implementation mechanism to achieve these caps. All electric generation sources greate r than 25 MW would fall under this program.

• The Clean Air Planning Act (CAPA, Carper,B reaux, Baucus, and Chafe)) was intended as middle ground between the CPA and CSA. For SO 2 

### , the caps are 4.5 mm TPY by 2008, 3.5 mm TPY by 2012, and 2.25 mm TPY by 2015. The caps for NO x 

### are 1.87 mm TPY by 2008 and 1.7 mm TPY by 2012. The Hg cap limits ar e 24 TPY by 2008, and a potential cap of 5- 16 TPY by 2012 (this cap to be set by EPA and im plies a control in the range of 79 to 93% from current Hg emission level). Cap and trade program will be the implementation mechanism for all four pollutants, except trading for Hg will be limited. In a “hybrid” approach, limited trading for Hg would be allo wed (each plant will be required to reduce its Hg emissions at site by at least 50% in 2008 and by 75% in 2012). For CO 2 

### , CAPA proposes to stabilize CO 2 

### emissions at 2005 levels (approximately 2.6 billion TPY) by 2008, and then stabilize to 2001 levels (appr oximately 2.4 billion TPY) by 2012.http://www.reaction-eng.com 

### VI-52

INTERNATION AL REACTION

ENGINEERING 

### All three bills recognize a nd incorporate the WRAP SO 2 

### trading program by setting separate caps on SO 2 

### emissions in the West. The CPA an d CAPA allow nationwide trading of NO x 

### , while the CSA divides the country into two zones for NO x 

### trading. The western zone includes the ND, SD, NE, OK, KS, western TX, the eleven states west of the Rockies, AK, HI and the U.S. territories. The largest differences among th e three bills are in the Hg emissions reduction requirements. The first-phase Hg emissions caps under CSA and CAPA are about the same, but compliance would come two years earlier unde r CAPA. CPA has the most stringent Hg reduction requirement: a cap of 5 TPY or about 90% control. The CSA would allow nationwide Hg trading, while the CAPA would allow partia l trading. There is no trading under CPA. Both CSA and the first phase of CAPA have mo dest Hg emission reductio n targets; these would make it possible in some cases to achieve reduc tion of Hg as a “co-ben efit” of other control technologies, for example, from the combination of an SCR and wet scrubber. If one of these bills were enacted, there might be some additi onal incentive to install an SCR and/or FGD on plants for which there might not be justif ication on the basis of a single pollutant. In terms of Hg co-benefits, the West is at a disadv antage as compared to the East. In the latter region, more utilities burn bituminous coals that ar e high in chlorine (which tends to increase the amount of oxidized Hg in flue gas) and in sulfur . Wet scrubbers are eff ective for the removal of oxidized Hg, but ineffective for removal of the elem ental Hg that is the predominant form of Hg in many western power plants. If all coal-fir ed power plants must reduce Hg emissions by upwards of 70%, the West will have a more diffi cult job than the East, owing to differences in coal composition. The bills that allow Hg trad ing (CSA and CAPA) would allow western power plants to deploy Hg control technology at plants were the highest emissi ons reductions are likely to be achieved.

If the CPA is enacted or if none of the three bills are enacted this year, it is likely that EPA will continue with the MACT process for Hg contro l, which does not allow trading and which will probably impose a Hg emission reduction target in the range of 70% to 90% (or an emission limit in the range of 0.2 to 0.6 pound of Hg per trilli on Btu input). In this case, coal-fired power plants will have to look at a pplication of activated carbon injection, the mo st mature technology for Hg control currently, or one of the multi-pol lutant processes under development. Activated carbon injection may require adding additional partic ulate control equipment (such as a polishing baghouse with high cloth to air ratio), which will lower PM as well as the emissions of other hazardous pollutants including arsenic, chro mium, lead, manganese, and nickel) as a
consequence.

5.2 Multi-pollutant Control Technologies A multi-pollutant control technology may be one integrated process or a combination of synergistic processes. In addi tion to in-situ and post-combustion control processes, options such as advanced power generation technologies, power plant reha bilitation-upgra ding-repowering, fuel switching or blending and power plant opt imization are sometimes included in the multipollutant control category. Emerging and commer cial processes for multi-pollutant control for coal-fired boilers are summarized in Table 25, wh ich is largely taken from Reference 4, with more recent information from the DOE-EPRI-U .S. EPA -A&WMA Combined Power Plant Air Pollutant Control Symposium in Washington, D.C., May 19-22, 2003.http://www.reaction-eng.com 

### VI-53

INTERNATION AL REACTION

ENGINEERING 

### Approximately half of the options listed in Table 25 are in commerci al and early commercial stages. However, nearly all the options in commercial stage are proven SO 2 

### control technologies, which also remove Hg, advan ced power generation op tions and power plant upgrading-fuel switching options. Nearly a ll in-situ and post-com bustion controls (SO 2 

### -NO x 

### or SO 2 

### -NO x 

### -Hg) are either in demonstration or p ilot-scale. Some technologies (e.g., SNO X 

### , SNRB, Advacate and CZD) have been tested either in pi lot or demonstration scal e in the early phase of the U.S. Department of Energy’s Clean Coal Technology (CCT) program, but have not been adopted by the industry. Some of these techno logies may become more cost-effective if additional controls are required. Most of the environmental c ontrol processes increase the auxiliary power requirements of th e plant (some up to 5%, but mostly in the range of 1 to 2%), increasing proportionally the CO 2 

### emissions.

Emerging post-combustion, multi-pollutant control technologies are being developed by a number of companies. The Elect ro-Catalytic Oxidation (ECO) sy stem is a four-stage pollution control process that inte grates established tec hnologies to remove SO 2 

### , NO x 

### , Hg and PM2.5. The system also produces a valuable fertilizer byproduct. The AIRborne process removes SO 2 

### and NO x 

### from plant emissions while turning the le ftover material into a high-quality granular fertilizer. EnviroScrub is a dry scrubbi ng system that results in control of SO 2 

### , NO x 

### , and possibly mercury and results in a byproduct that can be sold into the fertilizer, chemical, and/or explosives industry. None of these technologies controls emissions of CO 2


### . Capital costs of options cont rolling two pollutants (either SO 2 

### -NO x 

### or SO 2 

### -Hg) are projected to be in the 50-315 $/kW range, but there is significant uncertainty associated with these estimates because of their early stage of development. Al so, lack of information, especially associated with O&M costs, makes it difficult to compare th eir cost-effectiveness. Further monitoring and updating of cost-related information is needed. For reference, the costs of the combined commercial technologies, FGD and SCR are above 200-250 $/kW.

Advanced power generation technologies such as circulating fluidized bed (CFB), pressurized fluidized bed (PFBC) and integrated gasificati on combined cycle (IGCC) are potentially attractive options because they are revenue-generati ng options, while reducing significantly SO 2 

### and NO x 

### , and to a lesser extent CO 2 

### . These options are available main ly for new power plants. Also, supercritical pulverized coal boiler provides an attr active alternative to subcritical pulverized coal boiler for nearly the same investment and results in an additional 4-12% reduction of all emissions. While this may not seem to be a significant percen tage, their cost-effectiveness is attractive; also, the amount of CO 2 

### reduction (in tons or tons per year) is significant.

Of particular interest are options such as pow er plant optimization, fuel blending or switching and power plant upgrading. These options may play an important role in a flexible compliance regulatory framework and may result in significant savings for the utility industry compared to the implementation of control technology op tions. Optimization involves only operating changes, and while it results in only minor emission reductions, its co sts are very low and therefore it is an attrac tive option and should be pursued in al l power plants. Fuel blending or switching, and power plan t upgrading provide significant opport unities for emission control, but their site-specific nature makes it difficult to generalize regarding their emission reduction potential and cost-effectiveness. A more site-s pecific assessment is recommended to assess the potential for these options in a typical utility system.http://www.reaction-eng.com 

### VI-54

INTERNATION AL REACTION

ENGINEERINGTable 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion Boilers.Status: P =pilot stage;C = commercial;D = demonstrationIssuesHg removal can vary significantly withcoal type, operating conditionsPotential impacts on ESP or FFDemonstration on long-term basisneededNot used commercially, potentialimpacts on ESP or FFFull scale demonstration underway,insufficient information at presentFew application in power industry,potentially expensive alloys requiredHg removal may vary significantly withcoal type, operating conditions (similarto Spray Dryers)High costs and auxiliary powerrequirementsCost-effectivenessRequires demonstrationDemonstration in progress; capital costcomparable to FGD-SCRIn demonstrationApplicabilityLow to medium sulfur coalsUnits with ESP or FF forparticulate controlExisting plants, especially olderunits less than 300 MWUnits with ESP or FF forparticulate controlWet Scrubber PlantsIntegration with wet scrubbers,retrofit dry ESPs, new unitsNOX-Hg control for low tomedium sulfur coals(same asSpray Dryers)New and retrofitNew and retrofitNew and retrofitNew and retrofitNew and retrofitEmissions ReductionsSO2: >95%; NOx: NA; Hg: 5-85%SO2: 40-85%; NOx: NA; Hg: 0-90%SO2: 65-70%; NOx: NA; Hg:65-90%SO2: 40-85%; NOx: NA; Hg:50-90%SO2: 95%; NOx: NA; Hg:80+%SO2: 99%; NOx: NA; Hg:80+%SO2: 90-98%; NOx: NA; Hg:<90%SO2: 95+%; NOx: 50-90%; Hg:NASO2: 90+%; NOx: 50-90%; Hg:0%SO2: 80-90%; NOx: 50-90%;Hg: 0%SO2: 90->99%; NOx: 50-60%;Hg: 30-75%30 %SO2: 90-95%; NOx: 80-90%; Hg:NAStatusCP/CC/DP/CPC/PP/CC/DCPDDTechnologySO2/Mercury ControlDry Scrubbers (conventional)SO2sorbents, low temperatureSO2sorbents, furnaceinjectionActivated carbon with SO2sorbent processesWet FGD with mercuryoxidation processesWet FGD with wet ESPAdvanced Dry FGDSO2/NOxControlE-BEAMSNOXSNRBAIRborneThermal NOXhttp://www.reaction-eng.com 

### VI-55

INTERNATION AL REACTION

ENGINEERINGIssuesHigh costs, especially operating costsdue to high activated coke costsNot widely demonstrated at full scale,ash salability, ESP/FF performance,impact of mercury speciationDemonstration requiredDemonstration required; costsestimated to be 30-50% lower thanFGD-SCRDepends on Hg speciation in flue gas.ApplicabilityNew and retrofitRetrofit and new units with ESPan/or FFNew and RetrofitNew and retrofit.Plants with SCR and Wetscrubber technologiesEmissions ReductionsSO2: 90-98%; NOx: 60-80%;Hg: 90-99%Hg: 50-90%SO2: 95-98%; NOx: 90%; Hg:70+%SO2: 99+%; NOx: 99%;Hg: 60-70%SO2: 95%; NOx: 90-95%; Hg:0-80%StatusCP/CDDCTechnologySO2/NOx/Mercury ControlActivated CokeActivated carbon with particulatecontrolsElectro Catalytic OxidationEnviroScrubWet FGD and SCRTable 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion Boilers. [Continued]Status: P =pilot stage;C = commercial;D = demonstrationTable 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion Boilers. [Continued]http://www.reaction-eng.com 

### VI-56

INTERNATION AL REACTION

ENGINEERING 

### 6 SUMMARY AND RECOMMENDATIONS

6.1 NO x 

### and PM Sources

The main objectives of this project were to identify and briefly desc ribe the available (or emerging) technologies for control of NO x 

### and PM emissions that coul d be applied to sources in the western United States. The star ting point for this work was an an alysis of large (greater than 100 TPY) sources from the WRAP 1996 Emission Inventory (Version 3). Sources were limited to those from the thirteen-state region: AZ , CA, CO, ID, MT, ND, NM , NV, OR, SD, UT, WA, and WY.

The source profile from the thirteen-state region was compared with that from the nine-state GCVTR: AZ, CA, CO, ID, NM, NV, OR, UT, a nd WY. The GCVTR accounted for 75% of the NO x 

### emissions and 83% of the PM emissions with in the thirteen-state region. Generally, the distribution of sources was the same in the GCVT R as compared to the thirteen-state region. Thus, conclusions based on the thirteen-state region should therefore be valid for the GCVTR while achieving broader applicability to WRAP members.

The cut-off of 100 TPY captures 84% of the NO x 

### emissions in the 1996 WRAP database for the thirteen-state region. For ICE’ s (reciprocating engine s and turbines) the 100 TPY cut-off only captures about 56% of the emissions, though this category is the second largest category and responsible for 10% of stationa ry source emissions. Thus, NO x 

### control programs for sources in this category will require careful consideration of population attributes (e.g., a large number of small sources).

The largest source category for NO x 

### by far in the thirteen-state regi on is coal-fired boilers (68%); the top five categories (coal-fire d boilers, internal combustion engines, cement kilns, turbines and oil and natural gas boilers ) account for 90% of the NO x 

### emissions. The states with the largest stationary source NO x 

### emissions according to the 1996 WRAP database were AZ, CA, ND, NM, UT, and WY.

According to the WRAP 1996 (Version 3) stationary source emissions database, about 4% of the NO x 

### sources greater than 100 TPY ha d at least one type of contro l. Coal-fired boilers had the highest level of control (15%), followed by petrochemical processes (13%). The level of control for coal-fired boilers seemed low, even fo r 1996. Therefore, the 1996 WRAP database was compared with the data available for utility bo ilers in the 1996 CEMS a nd E-GRID databases. The EIA-767 database was also searched for NO x 

### control technologies. This comparison only looked at coal-fired utility boilers and not all coal-fired boilers. However, only 3% of the WRAP NO x 

### emissions from coal-fired boilers in the thir teen-state region were from non-utility boilers. WRAP data augmented by these other databases sugge sted that 44% of the utility boilers had at least one type of NO x 

### control in 1996, mostly low-NO x 

### burners.

The NO x 

### emission rate from external combustion bo ilers that is achievable with combustion modification depends on the fuel type . For coal-fired boilers, lower NO x 

### emission rates are obtained when firing subbituminous coal as comp ared to bituminous coal. Considering thehttp://www.reaction-eng.com 

### VI-57

INTERNATION AL REACTION

ENGINEERING 

### amount of subbituminous coal in the West, there is a fairly even split between bituminous and subbituminous coals as fuels for utility boilers. This may have shifted since 1996, however.

The cut-off of 100 TPY captures 60% of the PM emissions in the 1996 WRAP database for the thirteen-state region. Th e largest source category in the thirteen-state regi on is coal-fired boilers (40%); the top eight categories account for 92% of the PM emissions (g reater than 100 TPY): coal-fired boilers, mineral processing, petroc hemical, wood boilers, f ugitive, primary metal production, pulp and paper, and smelting operations. The state with the largest PM emissions is WY, followed by AZ, ID, and NM.

In the 1996 WRAP database, 72% of coal-fired boilers, the largest categ ory of emissions, had PM controls. Overall, though, only 38% of units had PM controls.

6.2 Controls for NO x 

### and PM

Many commercially available techno logies exist for control of NO x 

### and PM emissions from stationary sources. Twenty-five NO x 

### control technologies and four PM control technologies were summarized. Cost and performance inform ation was obtained for most technologies.

There are a lot more technologies available for NO x 

### control because of the different ways in which NO x 

### can be prevented or destroyed. In contra st, PM control on industrial processes is often done only at the back end of the process. This is not to say that process modification cannot be used to reduce PM emissions. Fugitive emissions, for example, can sometimes be controlled by process modificati on. Further work should be done to look into the details of important industrial processes to determine wh ere process modification will yield significant reductions in PM.

Most of the NO x 

### emissions from stationary sources are generated by combustion or by high temperature thermal processing. NO x 

### control technologies fall broa dly into two categories: combustion modifications and post-combustion re moval or destruction. Combustion systems differ, from internal combustion engines to ex ternal combustion boilers. Thus, there are many different strategies for modifying the combus tion process. Deciding on an appropriate NO x 

### control technology is highly depend ent on the process conditions and on the type of fuel. The existing NO x 

### control technology on a particular source will also influence what additional NO x 

### controls can be added succe ssfully. Post-combustion NO x 

### controls are not truly “back-end” technologies, like ESPs and baghouses for PM cont rol; some degree of pr ocess integration is required. Thus, not all post-combustion control processes can be applied to a given source.

There is no “one size fits all” solution for NO x 

### control. Deciding which technology to apply to a certain source depends on:

• The fuel type;

• The specific combustion process;

• Post-combustion characteristics: temperature, residence times, etc.;

• The type of NO x 

### control technology already in use; and

• The target NO x 

### emission rate.http://www.reaction-eng.com 

### VI-58

INTERNATION AL REACTION

ENGINEERING 

### Emerging environmental issues and regulatory change s have driven interest in multi-pollutant (as opposed to single pollutant) control technologies capable of addressing ai r pollutant emissions more comprehensively with greater flexibility a nd ultimately lower cost. Multi-pollutant control technologies integrate in-situ and/ or post-combustion controls of at least two of the following: SO 2 

### , NO x 

### , and mercury pollutants, and CO 2 

### emissions. Multi-polluta nt controls are intended primarily for external combustion boilers, particularly coal-fired boilers. The complexity of some of these processes as well as regulatory dr ivers often limit them to larger, power-generation boilers.

Emerging post-combustion, multi-pollutant control technologies are being developed for SO 2 

### , NO x 

### , and mercury that could be appl ied to stationary combustion sources in the western U.S. in the next five or ten years. These processes generally produce a saleable byproduct and have SO 2 

### removal rates of greater than 50%, and NO x 

### removal rates of greater th an 70%. Several of these processes are currently in pilot or full-scale demonstration. Co sts of options controlling two pollutants (either SO 2 

### -NO x 

### or SO 2 

### -Hg) are projected to be in th e 50-315 $/kW range, but there is significant uncertainty associated with these estimates because of their early stage of development. Also, lack of information, esp ecially associated with O&M costs, makes it difficult to compare their cost-effectiveness. Further monitoring and updating of cost-related information is needed. For reference, the cost s of the combined commercial technologies, FGD and SCR are above 200-250 $/kW.

6.3 What’s on the horizon? What tren ds will influence emissions and control technologies?

- The rate of advancement and use of multi-pollutant technologies (NO x 

### /Hg, SO 2 

### /Hg, PM/Hg, etc.) will depend on the levels of future mercury emissions reduction.

- Significant enhancements have been made in the ability of combus tion modifications to reduce NO x 

### formation, but they may be reachi ng their maximum potential given the theoretical limits within the combustion pro cess and given the nitrogen content of some fuels (e.g., coal). Determining how much NO x 

### emissions can be reduced in the West through this type of technology will require clos er examination of the types and vintages of combustion modificati ons already in place.

- There is (and always will be) uncertainty in the future mix of fuels for some combustion processes (e.g. electricity production). This influences the retirement of existing sources and the investment in new sources, which, in tu rn requires that a range of projections be made for future source distribution scenarios.

- Historically new technologies have had one major evaluation criteria in common: their performance improvement over the exis ting technology (e.g. SCR capable of 90% reductions over SNCR). As technologies push the potential control levels to 90% or more, we need to view them from a ne w perspective, one which includes greater emphasis on overall impacts, costs, inter-pollutant compatibility, etc.http://www.reaction-eng.com 

### VI-59

INTERNATION AL REACTION

ENGINEERING 

### 6.4 Recommendations for Future Work

Further work must be done in order to gene rate both accurate costs and reasonable control scenarios to be used in both regional-scale atmo spheric models and in evaluating regional control strategies, particularly in light of the multi- pollutant control legislation currently under consideration in Congress. This includes the following:

• Accurate cost information (generally available now);

• Details of the emission-generating processes;

• NO x 

### and PM control technologies already in place; and

• Accurate estimates of the current emissions. Better use could be made of existing EPA databa ses; in addition, the WRAP database should be updated to give a more accurate description of sources and existing control technology.

In this work, we found that the EPA databases (CEMs and E-GRID) were easy to use and provided what appeared to be a fairly comple te picture of current emissions and control technologies for NO x 

### and PM. Since much has change d in the West since the 1996 WRAP stationary source inventory, thes e databases are useful for gett ing more current information on utility boilers, which generate a si gnificant amount of the emissions in the western U.S. It would be worthwhile now to look attrends in emissions and NO x 

### control technologies in the West by analyzing the most recent CEMs and E-GRID databases.

Sufficient detail about the confi guration and process of the sources is generally not available in the EPA databases and these databases are only for utility boilers. Th e next WRAP inventory should be used to collect the information needed to make estimates of costs for control. Better identification of sources is important; there ar e instances in the 1996 WR AP database in which there is insufficient information on the type of s ource and/or the fuel in use. Obviously, better identification of existing air po llution control technology is crit ical. For combustion sources, particularly utility boilers, the capacity, in terms of MBtu/yr s hould also be included in the WRAP database.

Consideration should also be given to selecting a subset of sources for detailed characterization and calculate ranges of costs and expected em issions reductions. The subset should be a representative distribu tion of those sources within the mo st important source categories.http://www.reaction-eng.com 

### VI-60

INTERNATION AL REACTION

ENGINEERING 

### 7 REFERENCES

1. EPA Emissions Tracking System (Acid Rain Program), http://www.epa.gov/airmarkets/emissions/index.html

. 2. EPA Emissions & Generation Resource Integrated Database (E-GRID), http://www.epa.gov/airmarkets/egrid/

. 3. DOE Energy Information Agency, EIA-767 Steam Electric Plant Report, http://www.eia.doe.gov/fuelelectric.html

. 4. “Multi-pollutant Emission Control Technol ogy Options for Coal-Fired Power Plants,” EPA-600/R-02/075, October 2002. 5. Battye, R., Walsh, S., Lee-Greco, J. “NO x 

### Control Technologies for the Cement Industry (Final Report).” EPA Contract No. 68-D 98-026, EC/R Incorporated, Chapel Hill, NC, September 2000. 6. Dusome D. (1993). “Staged Combustion for NO X 

### Control at the Calaveras Tehachapi Plant”, presented to the Po rtland Cement Association. 7. Nielsen, P.B. et al. (1990). “An Overview of the Formation of SO X 

### and NO X 

### in Various Pyroprocessing Systems”, IEEE Cement Industry Technical Conference. 8. SA Johnson and S Haythornthwai te, Summary of Available NO x 

### Control Techniques for the Cement Industry, submitted to the Port land Cement Association, Skokie, IL 1998. 9. Amar, K.P., Staudt, J. “Status Report on NO x Controls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal Combustion Engi nes; Technologies and Cost Effictiveness.” Norhteast States for Coordinated Air Us e Management, Boston, MA, January, 2001. 

### 10. U.S. Environmental Protection Agency. “A lternative Control Techniques DocumentNO x 

### Emissions from Stationary Gas Turb ines.” EPA-453/R-93-007, Research Park Triangle, NC, January, 1993. 11. Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-D98- 026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000. 12. State of New Jersey Department of Environm ental Protection. “State of the Art (SOTA) Manual for Reciprocating In ternal Combustion Engines.” Trenton, NJ, July, 1997. 13. SA Johnson and S Haythornthwai te, Summary of Available NO x 

### Control Techniques for the Cement Industry, submitted to the Port land Cement Association, Skokie, IL 1998. 14. State of California Air Resources Board. “CAPCOA/ARB Proposed Determination of Reasonably Available Contro l Technology and Best Ava ilable Retrofit Control Technology for Stationary Internal Combus tion Engines (DRAFT).” Sacramento, CA, December, 1997. 15. State of New Jersey Department of Environm ental Protection. “State of the Art (SOTA) Manual for Reciprocating In ternal Combustion Engines.” Trenton, NJ, July, 1997. 16. European IPPC Bureau. “Reference Docume nt on Best Available Techniques in the Glass Manufacturing Industry.” Seville, Spain, October, 2000. 17. W. Neuffer, U. S. EPA. Summary of Information Provide d by Engine Manufacturers on Low Emission Combustion. 18. Telecon. R. Faulkner, Dies el Supply Company, with S. Edgerton, EC/R. April 6, 2000.http://www.reaction-eng.com 

### VI-61

INTERNATION AL REACTION

ENGINEERING 

### 19. Cooper-Bessemer. Facsimile from J. W. Hibbard to W. Neuffer, U. S. EPA. Information on Low Emission Combustion. Cooper-Bessemer, Cooper Energy Services, Mount Vernon, OH. March 3, 1999. 4pp. 20. Dresser-Rand. Facsimile from C. F. Willke to W. Neuffer, U. S. EPA. Information on Low Emission Combustion. Dresser-Rand Se rvices, Painted Post, NY. May 7, 1999. 2pp. 21. National Center for Environmental Research, U. S. EPA Office of Research and Development. “1994 Phase II Abstracts: Plas ma Ignition Retard for NO(x) Reductions.” http://es.epa.gov/ncerqa_abs tracts/sbir/94/topics43.html

. 22. Manufacturers of Emission C ontrols Association. Emission Control Technology for Stationary Internal Combustion Engines . Status Report, July 1997. Pg. 7. 23. NOxTech Inc. Letter and attachments from E. Cazzola to Mary Jo Krolewsky, U. S. EPA Acid Rain Division. April 12, 1999. 24. NOxTech Inc. “NOxTech ® 

### Technology.” website. www.noxtechinc.com/products.htm

. 25. Goal Line Environmental Technology News . “Cummins Engine Co. Tests SCONOx ® 

### for Diesel IC Engines.” Oct 1999. Vol 1, Issue 3.

### APPENDIX A : Breakdown of NO x 

### Emissions by StateA-1Table A-1. WRAP NOxEmissions for sources > 100 TPY by StateCategory 13-States AZ* CA* CO*# UnitsTotal NOxTPY (>100TPY) # UnitsTotal NOxTPY (>100TPY) # UnitsTotal NOxTPY (>100TPY) # UnitsTotal NOxTPY (>100TPY)Coal-Fired Boilers 151 607,748 15 75,018 3 1,544 31 82,927Reciprocating Engines 423 86,210 16 6,441 58 10,274 56 11,328NG 404 81,786 14 5,731 54 9,436 56 11,328Diesel 16 4,021 2 709 3 708Process Gas 3 403 1 130Cement Kilns 39 41,009 2 4,662 16 15,886 4 4,470Oil/NG Boilers 112 32,910 4 1,092 40 12,290 9 2,643Turbines 86 25,278 8 1,918 37 8,990 9 1,655NG 83 24,821 7 1,795 37 8,990 9 1,655Diesel 3 457 1 123Mineral Processing 34 16,250 4 2,861 4 3,263Petrochemical 48 13,719 1 101 13 3,978 4 730NG Compressor 16 10,959 14 10,686Pulp and Paper 39 10,010 3 602Wood Boilers 48 9,776 14 2,430Refinery Process Heaters 38 9,311 28 7,096Glass Manufacture 14 5,033 11 4,128 1 251Primary Metal Production 17 3,476 2 1,009 2 244Waste Combustion 6 3,309Refinery Emissions 8 3,256 8 3,256In-process Fuel Use 9 2,605 7 1,906Jet Engine Testing 4 2,297 4 2,297Oil and Gas Production 7 1,140Smelting Operations 3 961 2 852Sugar Beet Production 3 730 1 111Secondary Metal Production 4 507Turbines, Steam 1 165 1 165Total (> 100 TPY)1,110 886,659 68 104,639 248 78,217 116 104,249* GCTVR StateA-2Table A-1. WRAP NOxEmissions for sources > 100TPY by State [continued]Category ID* MT ND NM*# UnitsTotal NOxTPY (>100TPY)# UnitsTotal NOxTPY (>100TPY)# UnitsTotal NOxTPY (>100TPY)# UnitsTotal NOxTPY (>100TPY)Coal-Fired Boilers 6 2,218 6 25,452 17 108,007 10 70,193Reciprocating Engines 14 4,357 8 2,569 201 37,755NG 4 2,056 8 2,569 201 37,755Diesel 10 2,301Process GasCement Kilns 1 1,662 1 1,000Oil/NG Boilers 1 128 3 909 10 3,389Turbines 1 139 0 0 3 564 12 2,947NG 1 139 3 564 12 2,947DieselMineral Processing 1 117 3 428 1 145Petrochemical 3 1,449 5 842 1 915 1 124NG CompressorPulp and Paper 3 377 4 920Wood Boilers 4 708 4 1,057 1 360Refinery Process Heaters 1 206Glass ManufacturePrimary Metal ProductionWaste Combustion 4 2,971Refinery EmissionsIn-process Fuel Use 1 589Jet Engine TestingOil and Gas Production 2 348 1 140Smelting OperationsSugar Beet Production 2 619Secondary Metal ProductionTurbines, SteamTotal (> 100 TPY)18 5,008 39 35,436 40 116,901 239 116,258* GCTVR StateA-3Table A-1. WRAP NOxEmissions for sources > 100TPY by State [continued]Category NV* OR* SD UT*# UnitsTotal NOxTPY (>100TPY) # UnitsTotal NOxTPY (>100TPY) # UnitsTotal NOxTPY (>100TPY) # UnitsTotal NOxTPY (>100TPY)Coal-Fired Boilers 8 39,040 1 4,195 3 17,268 15 66,600Reciprocating Engines 15 2,074NG 14 1,772Diesel 1 303Process GasCement Kilns 2 3,789 2 687 3 2,718 2 565Oil/NG Boilers 6 3,727 6 2,155 1 267Turbines 1 191 3 5,372 2 435 3 772NG 2 5,229 2 435 3 772Diesel 1 191 1 143Mineral Processing 2 218 2 577 5 4,542Petrochemical 2 324NG Compressor 2 273Pulp and Paper 14 3,641Wood Boilers 17 3,366Refinery Process HeatersGlass ManufacturePrimary Metal Production 1 125 3 514 7 1,263Waste Combustion 2 339Refinery EmissionsIn-process Fuel Use 1 109Jet Engine TestingOil and Gas ProductionSmelting OperationsSugar Beet ProductionSecondary Metal ProductionTurbines, SteamTotal (> 100 TPY)21 47,199 46 19,929 10 20,998 54 77,020* GCTVR StateA-4Table A-1. WRAP NOxEmissions for sources > 100TPY by State [continued]Category WA WY*# UnitsTotal NOxTPY (>100TPY) # UnitsTotal NOxTPY (>100TPY)Coal-Fired Boilers 8 20,138 28 95,148Reciprocating Engines 7 1,191 48 10,219NG 5 918 48 10,219DieselProcess Gas 2 273Cement Kilns 4 4,126 2 1,444Oil/NG Boilers 28 5,758 4 553Turbines 3 324 4 1,971NG 3 324 4 1,971DieselMineral Processing 4 1,904 8 2,197Petrochemical 11 3,635 7 1,619NG CompressorPulp and Paper 15 4,471Wood Boilers 8 1,856Refinery Process Heaters 9 2,009Glass Manufacture 2 654Primary Metal Production 1 116 1 205Waste CombustionRefinery EmissionsIn-process Fuel UseJet Engine TestingOil and Gas Production 4 652Smelting Operations 1 109Sugar Beet ProductionSecondary Metal Production 4 507Turbines, SteamTotal (> 100 TPY)105 46,798 106 114,009*GCVTR State

### : APPENDIX B : Breakdown of PM Emissions by StateTable B-1. WRAP PM Emissionsfor sources > 100 TPY by StateCategory 13-States AZ* CA* CO*# UnitsTotal PMTPY# UnitsTotal PMTPY# UnitsTotal PMTPY# UnitsTotal PMTPYCoal-Fired Boilers 88 46,010 9 2,657 1 699 3 684Mineral Processing 85 24,499 14 4,932 5 710 18 4,700Petrochemical 42 10,836 5 834 4 757Wood Boilers 24 5,718 3 471Refinery Emissions 11 5,631 2 3,949 1 104 3 843Primary Metal Production 20 4,697 3 529 1 139 1 232Pulp and Paper 15 4,476 2 272Smelting Operations 8 3,555 1 137Miscellaneous 1 2,456 1 2,456Oil/NG Boilers 5 1,379Sugar Beet Processing 5 1,150 1 210 1 110 1 430Cooling Tower 4 932Cement Kilns 4 641 1 132Turbines 2 838 1 590 1 248Diesel 1 590 1 590NG 1 248 1 248Secondary Metal Production 1 537Jet Engine Testing 2 535 2 535Reciprocating Engines 3 525 1 104 1 169Diesel 2 273 1 104 1 169NG 1 252Refinery Process Heaters 1 176 1 176Total 321 114,589 32 13,107 24 6,638 32 8,063* GCTVR StateTable B-1. WRAP PM Emissions for sources > 100 TPY by State [continued]Category ID* MT ND NM*# UnitsTotal PMTPY# UnitsTotal PMTPY# UnitsTotal PMTPY# UnitsTotal PMTPYCoal-Fired Boilers 8 5,180 4 3,990 11 3,679 9 7,285Mineral Processing 5 1,864 9 2,565 1 110 2 270Petrochemical 4 688 2 274 1 590 1 307Wood Boilers 6 1,683 2 242Refinery EmissionsPrimary Metal Production 1 477Pulp and Paper 6 2,949Smelting Operations 1 158 4 1,242MiscellaneousOil/NG BoilersSugar Beet Processing 1 297Cooling TowerCement Kilns 1 216 1 117 1 176TurbinesDieselNGSecondary Metal ProductionJet Engine TestingReciprocating EnginesDieselNGRefinery Process HeatersTotal 30 12,579 20 7,825 14 4,676 17 9,280* GCTVR StateTable B-1. WRAP PM Emissions for sources > 100 TPY by State [continued]Category NV* OR* SD UT*# UnitsTotal PMTPY# UnitsTotal PMTPY# UnitsTotal PMTPY# UnitsTotal PMTPYCoal-Fired Boilers 8 5,688 1 108 2 236 8 2,436Mineral Processing 2 244 11 2,510PetrochemicalWood Boilers 11 3,056Refinery Emissions 1 233Primary Metal Production 1 211 1 276 4 857Pulp and Paper 5 898Smelting Operations 2 2,017MiscellaneousOil/NG Boilers 4 1,235 1 144Sugar Beet ProcessingCooling TowerCement KilnsTurbinesDieselNGSecondary Metal Production 1 537Jet Engine TestingReciprocating EnginesDieselNGRefinery Process HeatersTotal 15 7,379 20 5,019 3 469 25 7,820* GCTVR StateTable B-1. WRAP NOxEmissions for sources > 100TPY by State [continued]Category WA WY*# UnitsTotal PMTPY# UnitsTotal PMTPYCoal-Fired Boilers 4 2,968 20 10,400Mineral Processing 18 6,594Petrochemical 2 255 23 7,130Wood Boilers 2 266Refinery Emissions 3 386 1 115Primary Metal Production 8 1,976Pulp and Paper 2 357Smelting OperationsMiscellaneousOil/NG BoilersSugar Beet Processing 1 103Cooling Tower 4 932Cement KilnsTurbinesDieselNGSecondary Metal ProductionJet Engine TestingReciprocating Engines 1 252DieselNG 1 252Refinery Process HeatersTotal 22 6,311 67 25,423*GCVTR State

### APPENDIC C: NO x 

### Control Technology SummariesC-1 Process: Air or Fuel Staging

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Cement Kilns 41,009 0 to 50% 1000-2000 Commercial Process Description:

Inject portion of the fuel downstream of the main flame to create locally reducing conditions where NO x can be destroyed. Sometimes includes installing a “NO x fan” to increase burnout. Most commonly applied to preheater/precalciner kilns in which part of the coal is already being fired in the calciner. In this case, airflow is rerouted downstream of the calciner fuel injector.

Air and Fuel Staging as commonly applied to large industrial/utility boilers is discussed under the more commonly referred names technologies Overfire Air and Fuel Reburn

NO x Reduction:

NO x reduction is achieved by creating two separate combus tion zones. The burner zone is fired fuel-lean to create the high temperatures needed for clinker form ation. Limestone calcination, which takes place at temperatures in the range of 1600 to 1800 ° F, is accomplished in the second combustion zone in the tower. NO x reductions as high as 50% can be achieved by controlling the size of the fuel-rich region in the second combustion zone. Conversely, if combusti on is fuel-lean or well-mixed in the second zone, NO x would not be reduced. The ideal stoichiometric ratio in the calciner is 0.7 to 0.8. Some systems do not perform well because the second combustion zone is too fuel-rich (SR < 0.6), causing significant NO x production when the staging air is added.

Cost Information:

Capital cost for the technology includes additional ductwork and controls. This should run between $200,000 and 500,000 depending on the length of new ductwork required. Operating cost should not change unless lower temperatures or locally reduci ng conditions adversely affect cement quality.

Development Status:

Commercially available. Practical Considerations:

The technology is easier to implement on preheater/precal ciner kilns since special injectors are required to introduce fuel or air into the middle of a rotating kiln . In either case, there must be sufficient residence time at high temperature to complete burnout.

Compatibility with other air pollution control technologies:

Reducing conditions may increase sulfur emissions or require additional SO 2 emission controls.C-2 Process: Air or Fuel Staging
Secondary Environmental Impacts:

None expected. References:

Dusome D. (1993). “Staged Combustion for NO x Control at the Calaveras Tehachapi Plant”, presented to the Portland Cement Association.

Nielsen, P.B. et al. (1990). “An Overview of the Formation of SO X and NO X in Various Pyroprocessing Systems”, IEEE Cement Industry Technical Conference.

Johnson, S.A. and Haythornthwaite , S., “Summary of Available NO x Control Techniques for the Cement Industry”, submitted to the Portland Ceme nt Association, Skokie, IL, 1998.C-3 Process: Batch/Cullet Preheating

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Glass Manufacturing 5,033 5-25% 890-1,040 Commercial Process Description:

Batch and cullet (recycled glass) preheating can be app lied by direct preheating, indirect preheating and Edmeston EGB Filter. Direct preheating requires direct contact between the flue gas and the raw material in a cross-counter flow and incorporates a bypass th at allows furnace operation to continue when preheater use is either inappropriate of impossible. The indirect preheater is in principle a cross-counter flow, plate heat exchanger. The Edmeston electrified granulate bed (EGB) filter system is a hybrid between an electrostatic precipitator for dust removal and a direct cullet preheater. NOx Reduction:

Cullet preheating is primarily an energy saving t echnique (savings between 10-20%), but its practice reduces NO x emissions due to lower fuel requirements and lower furnace temperatures. Cost Information:

Capital costs generally range from $42K-110K. Econom ics are strongly dependent on the capacity of the furnace and the preheater. Development Status:

Commercially available Practical Considerations:

Cullet preheating systems can be installed at any existing glass melting furnace with greater than 50% cullet in the batch. For economic reasons, the temper ature of the waste gas available should be at least 400-450°C, and a cooling of the flue gases by at least 200-250°C is needed. To prevent material agglomeration, the maximum entry temperatur e of the flue gases should not exceed 600°C.

The design and implementation of the preheating uni t should be evaluated with the over-all system configuration. Many technical issues, such as monitoring of the preheating temperature, should be carefully reviewed prior to the implementation. Compatibility with other air pollution control technologies:

Cullet preheating is compatible with combus tion modification techniques and post-combustion technologies. Secondary Environmental Impacts:

• The use of a direct preheater causes increased emissions of particulate matter (up to 2000 mg/Nm 3 ) and secondary particulate abatement is necessary.

• Direct preheating reduces acidic compounds, SO 2 , HF, and HCl by up to 60%, 50%, and 90% respectively (difference before and after cullet bed). References

European IPPC Bureau. “Reference Document on B est Available Techniques in the Glass Manufacturing Industry.” Seville, Spain, October, 2000.C-4 Process: Catalytic Combustion

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Combustion or Gas Turbines 25,278 > 80% > 500 Commercial Process Description:

Catalytic combustion reduces NO x formed from the combustion process by reducing the combustion temperature to reduce thermal NO x . The fuel and air are premixed into a fuel-lean mixture (fuel/air ratio of approximately 0.02) and then pass into a catalyst bed. In the bed, the mixture oxidizes without forming a high-temperature flame font. Peak combustion temp eratures can be limited to below 2800 °F, which is below the temperature at which significant amounts of thermal NOx begin to form. Catalytic combustors can also be designed to operate in a rich/lean configura tion. In this case, the air and fuel are premixed to form a fuel-rich mixture, which passes through a first stage catalyst where combustion begins. Secondary air is then added to produce a lean mixture, and co mbustion is completed in a second stage catalyst bed. NO x Reduction:

According to one developer of the technology, catalyt ic combustion has been demonstrated to achieve 3 ppm NO x on a 1.5 MW gas turbine. A NO x level of 3.3 ppm was achieved on a General Electric Frame 9 test stand. Cost Information:

Costs referenced above are preliminary and based on DOE reference below. Development Status:

Commercially available. Practical Considerations:

Catalytic combustion techniques apply to all combus tor types and are effective on both diesel- and gasfired turbines. The technology has a limited operatin g range, and thus cannot be applied to gas turbines subject to rapid load changes. Compatibility with other air pollution control technologies:

Compatible with post-combustion technology. Secondary Environmental Impacts:

None expected. References:

NESCAUM, “ Status Report on NO x Controls for Gas Turbines, Cement Kilns, Industrial Boilers and Internal Combustion Engines: Technologies and Cost Effectiveness,” December 2000

U.S. Environmental Protection Agency. “A lternative Control Techniques Document-NO x Emissions from Stationary Gas Turbines.” EPA-453/R-93-007, Research Park Triangle, NC, January 1993.

DOE, “Cost Analyses of NO x Control Alternatives for Stationary Gar Turbines”, November 1999.C-5C-6 Process: DLN (Fuel-lean combustion)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Turbines 25,278 70% 1,000-2,000 Commercial Process Description:

Dry Low NO x (DLN) is a combustion technology for gas turb ines that enables gas-tu rbine combustors to produce low NO x emission levels without diluents (such as wate r or steam) or catalysts. DLN technology utilizes a lean, premixed flame as opposed to a turbulen t diffusion flame, a gas turbine equivalent of the LNB. NO x Reduction:

Engines from 3-10 MW retrofit with DLN achieved 42 ppm NO x emissions, corresponding to reductions in the range of 60-83%. New and retrofit turbines in the larger, power plant sizes (over 50 MW) have been retrofitted to below 9 ppm of NO x . Cost Information:

The cost of NO x reduction by DLN is very sensitive to the capac ity factor of the turbine. There is also substantial variation in capital cost measured in terms of dollars/horsepower ($/hp) due to different turbine types and variations in turbine design. Reported costs in case studies show capital costs ranging from $750K-1,950K (4,700 hp at $160/hp and 13,000 hp at $150/hp). These are total project costs that owners attributed to the project, which may include pr oject management or other charges associated with the project beyond the equipment and installation. Development Status:

Commercially available

As of August 2000, about 50 turbin es had been retrofitted and over 500 new turbines were operating with DLN technology. Practical Considerations:

Because DLN combustor technology operates under conditio ns that are much closer to the flammability limit than the conventional combustor technology, th ere is a significant risk of flame instability. Manufacturers have developed improved electronic turbin e controls to address this problem. Some early experience has also found combustor liners failing af ter only about 5,000 hours compared to over 20,000 hour lifetime for conventional technology. Similarl y, manufacturers have developed improved liners to address this problem.

Other considerations are:

• DLN is achievable with fuels that can be premixed and are low in fuel nitrogen content, such as natural gas. Turbines that must maintain low NOx levels while operating on fuel oil may not be compatible with DLN.

• Achieving low NO x across the full load range requires a sophisticated combustor design, often with variable operating modes in order to maintain flame stability.C-7 Process: DLN (Fuel-lean combustion)

• The DLN combustor is typically larger than a c onventional combustor and can have more limited operating ranges.

Compatibility with other air pollution control technologies:

Compatible with post-combustion technology (SCR, SNCR). Secondary Environmental Impacts:

None expected.

References:

NESCAUM, “ Status Report on NO x Controls for Gas Turbines, Cement Kilns, Industrial Boilers and Internal Combustion Engines: Technologies and Cost Effectiveness” December 2000

.C-8 Process: Flue Gas Recirculation (FGR)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Oil/Natural gas boilers 32, 910 40-80% 500-3,000 Commercial

Refinery Process Heaters 9,311 (combined with LNB) 5,900 Commercial Process Description:

Flue Gas Recirculation (FGR) simply refers to a NO x reduction approach that involves reintroducing some flue gas (5% to 15%) into the combustion ai r (or directly into the burner) to suppress flame temperatures and minimize NOx formation.

This technology usually involves a dedicated FGR fan to recirculate the flue gas back to the burner front and it is most applicable to gas fired applications. Th is is because its main benefit is in the minimization of thermal NO x (NO x formed from nitrogen in the com bustion air), as opposed to fuel-NO x (NO x formed from fuel-bound nitrogen). Since in oil and coal sources a significant fraction of NO x comes from “fuelNO x ”, FGR is less effective in such applications

NO x Reduction:

NO x reductions from FGR on gas-fired sources can be in the range of 40% to 80%. FGR is often used in combination with LNBs a nd discriminating between the relative NOx reduction contributions is difficult in some cases.

Cost Information:

The main costs associated with FGR involve the retrofit of the FGR fan(s) and required ductwork to route the flue gas to the burner front. Costs in the range of $10 - $20/kW are expected for power generation

sources

Development Status:

FGR is a well-proven technology in commercial opera tions for many years. Variations of the general concept include Induced FGR where the gas recirculated to the burner zone through an eductor, as well as recirculated to individual burners as opposed to the combustion air windbox for mixing with the combustion air prior to entering the burners. Practical Considerations:

As mentioned above, FGR is mostly appropriate for gas-fired applications. Its effectiveness on oil and coal reduce its “appeal” to such sources

Care is necessary to ensure that the amount of FGR does not compromise boiler safety by diluting oxygen concentration in the combustion air to unsafe levelsC-9 Process: Flue Gas Recirculation (FGR) Compatibility with other air pollution control technologies: FGR is used in combination with LNB’s and OFA.

FGR is also compatible with post combustion NO x technologies although the overall cost effectiveness needs to be addressed case-by-case. Secondary Environmental Impacts:

None expected.

References: EPRI, “Retrofit NO x Control Guidelines for Gas- and Oil-Fire d Boilers”, Final Report, December 1993.

Poole, L., “Houston Galveston Area NO x Abatement Industries Perspective,” present at the Council of Industrial Boiler Owners, NO x Control XV Conference, Houston, TX, August 2002.C-10 Process: Fuel Reburn

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Coal-fired boilers 607,748 30-60% 500-2,000 Commercial Wood/Biomass boilers 9,776 40-60% 300-3,000 Commercial Glass Melters 5,033 50-65% “moderate” Commercial Process Description:

Reburning, while generically included in th e “Combustion Modification” category of NO x control technologies, differs from the others (BCM, LNB and OFA) by “destroying” NO rather than by minimizing its formation. Fuel is introduced above the main burner zone in the furnace, creating a fuelrich (reducing) atmosphere in which NO x formed in the main burner zone is destroyed by reacting with hydrocarbon and nitrogen compounds. The hardware need ed for reburning includes reburn fuel burners or nozzles and overfire or burnout air ports (see discussi on on fuel-lean reburn for deviations from this). The level of complexity of a particular system depends mostly on the choice of the reburn fuel itself (gas, coal, oil, orimulsion), as well as on the status and capa bility of the existing boiler (e.g., the burner/boiler control system).

NO x Reduction:

Full load NO x reductions with reburning can be expected to range from 35% to 60% depending on factors such as:

• reburn fuel type and quantity; typically the reburn fuel needs to provide 15-20% of the total heat input if it is gas or 25-30% if coal to obtain 50-60% ∆ NO x

• initial NO x level

• “tolerance” of negative impacts (e.g ., efficiency loss, ash quality)

At low loads, NO x reduction may fall to the 20-40% range, depe nding on the burner zone stoichiometry and low load operating characteristics of the boiler (e .g., operating at high excess air to control reheat temperature). Reburning, like SNCR and SCR, may be thought of as a “dial-in” technology in that NO x reductions will be a function of th e amount of reburn fuel (or the amount of nitrogen compound reagent in the case of SNCR and SCR). This feature may make it particularly attractive for compliance scenarios based on seasonal use, averaging and/or trading.

Cost Information: In general, the capital costs range from $15/kW to $30/kW for gas reburn and $30/kW to $60/kW when using coal as the reburn fuel. Operating costs are mainly driven by fuel cost diffe rential (certainly gas vs coal). For other fuels (e.g. coal/orimulsion reburni ng), fuel preparation costs become more important (micronization, atomization) as there is little or no fuel cost differential.

Retrofit schedules are directly related to the scope of the retrofit requirements. In most cases, 3-6 weeks are adequate for a reburn retrofit.C-11 Process: Fuel Reburn Development Status: Commercial

While reburning does not account for a significant fraction of installed NO x reduction technologies compared to LNBs, SNCR and SCR worldwide, it is gaining acceptance, and a number of recent activities suggest it has become a viable strategic option for NOx control. This increase in interest is due to two key factors, among others: (1) increased experience a nd encouraging results, which increase the level of comfort with the technology; and (2) the “prolifera tion” of advanced reburn technologies, each with its own features, advantages and disadvantages. These “a dvanced” reburning options involve enhancements of the conventional approach, with features rangi ng from combinations with SNCR to the outright avoidance of overfire air, as in fuel-lean gas reburn (FLGR).

Practical Considerations:

Boilers with the following design and operating char acteristics are expected to be more suitable candidates for reburning:

• firing low-sulfur coals (e.g., less propensity for waterwall corrosion)

• low baseline unburned carbon (e.g., to minimize ash salability impacts).

• favorable cross-section/height profiles (e.g ., tall boilers which provide for adequate mixing/residence time to maximize effectiveness).

• gas availability, very efficient/effective coal pul verizers (e.g., approaching micronization) or access to orimulsion for the reburn fuel

Of major importance is the choice of reburn fuel. The increasing experience with coal and orimulsion dictates that these must be considered in light of cost, availability, deliverability and overall project objectives. However, the use of natural gas provid es benefits from lower maintenance costs (e.g., less demand on pulverizers) and lower emissions of other pollutants (particulate, SO x , CO 2 ).

Compatibility with other air pollution control technologies:

Reburn Technology can be implemented with both Low NO x combustion approaches (e.g. LNBs) and post combustion technologies (SNCR/SCR). However, the overall NO x reductions are not strictly additive and careful evaluation is required to ensure cost effective strategies.

Secondary Environmental Impacts:

Reburn technology has the potential to effect both pos itive and negative secondary environmental impacts depending on factors such as the reburn fuel, main combustion and reburn zone stoichiometries, boiler physical characteristics, etc.

The following are potential impacts that must be analyzed on an individual unit basis

• CO may increase due to stoichiometry in the reburn zone

• LOI may increase due to stoichiometries and OFA designC-12 Process: Fuel Reburn

• SO 2 /CO 2 benefits when reburn fuel is gas (proportional to gas input)

References:

NESCAUM, “Status Report on NO x Control Technologies and Cost Effectiveness for Utility Boilers”, June 1998.

EPRI, “Retrofit NO x Controls for Coal-Fired Utility Boile rs – 2000 Update”, EPRI Final Report, December 2000.

Folsom, B. “Field Experience with Reburn NOx Control”, ICAC Forum 2000, Arlington, VA. March 2000.C-13 Process: High Energy Ignition System (HEIS)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Reciprocating Engines 86,210 50% - 80% 115 - 200+ Commercial
Process Description:

HEIS technology, also known as plasma ignition, prov ides a continuous electrical discharge at the gap of a conventional spark plug for 10 to 90 degrees of crankshaft rotation as opposed to traditional spark ignition where the life of the spark is only a fracti on of a degree of crankshaft rotation. The extended energy ensures that ignition will occu r even in the leanest of conditions. A rich mixture is ignited in a small ignition cell located in the cylinder head. Th e ignition cell flame passes to the cylinder where it provides a uniform ignition source. NO x Reduction:

Laboratory tests and case studies have shown NO x emissions in the range of 2.5 to 3.0 g/bhp-hr while maintaining acceptable engine operation. Emissions of 2.5 b/bhp-hr were achieved on a 2,750-bhp engine, amounting to an 84% reduc tion from the uncontrolled level. Cost Information:

Cost information was not widely reported. Cost range indicated above was taken from the NESCAUM reference below.

Development Status: Commercially available

HEIS has been installed on numerous engines to meet NO x RACT requirements in the range of 2.5 to 3.0 g/bhp-hr in the Eastern United States. Seve ral users have reported over 80% reduction in NO x emissions. Practical Considerations:

HEIS technology can be used only in lean-burn, natura l gas-fired spark ignition engines. This technique can be retrofit to turbocharged 2- and 4-cycle engines. Compatibility with other air pollution control technologies:

Compatible with post-combustion NO x technologies (SCR, NSCR). However, the overall NO x reductions are not strictly additive and careful evaluation is required to ensure cost effective strategies. Secondary Environmental Impacts:

In most cases, NO x reductions have been accompanied by increased power output and increased fuel
economy. References:

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “S tationary Reciprocating Internal Combustion Engines Updated Information on NO x Emissions and Control Techniques (Final Report).” EPA contract No. 68- D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.

NESCAUM, “ Status Report on NO x Controls for Gas Turbines, Cement Kilns, Industrial Boilers andC-14 Process: High Energy Ignition System (HEIS) Internal Combustion Engines: Technologies and Cost Effectiveness,” December 2000.

State of New Jersey Department of Environmental Pr otection. “State of the Art (SOTA) Manual for Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997.

Alternative Control Techniques Document: NO x Emissions from Stationary Reciprocating Internal Combustion Engines. EPA Document No. EPA-453/R-93-032, July 1993.C-15 Process: High-Pressure Fuel Injection

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Reciprocating Engines 86,210 ~80% N/A (less than LEC) Commercial Process Description:

High-Pressure Fuel Injection represents a “sec ond generation” Low Emission Combustion (LEC), according to one vendor of NO x control equipment and retrofit services. The technology uses high pressure to enhance the mixing of air and fuel in the combustion cylinder under fuel lean conditions. This technique reduces the quantity of excess air in comp arison to LEC, diminishing the turbocharging and intercooling retrofit requirements.
NO x Reduction:

Tests from a large (~5,000 bhp) turbocharged Clar k engine showed 80% NOx reduction. May be comparable to LEC reductions.

Cost Information:

Less than LEC because the technology does not require pre-combustion chambers or as much excess air, thus reducing the degree of turboc harging and intercooling required. Development Status: Commercially available

Considered emerging in 2000.
Practical Considerations:

An LEC retrofit vendor stated that NO x emissions cannot be reduced to 2 g/bhp-hr through the use of a high-pressure fuel system alone. Less stringent regul atory requirements cans be met with a combination of ignition timing adjustment, high- pressure fuel injectors, and impr ove A/F ratio and ignition system controls. Compatibility with other air pollution control technologies:

Compatible with post-combustion NO x technologies (SCR, NSCR). However, the overall NO x reductions are not strictly additive and careful evaluation is required to ensure cost effective strategies. Secondary Environmental Impacts:

None expected.

References:

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “S tationary Reciprocating Internal Combustion Engines Updated Information on NO x Emissions and Control Techniques (Final Report).” EPA contract No. 68- D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.

National Center for Environmental Research, U. S. EPA Office of Research and Development. “1994 Phase II Abstracts: Plasma Ignitio n Retard for NO(x) Reductions.” http://es.epa.gov/ncerqa_abstracts/sbir/94/topics43.html.C-16C-17 Process: “Intelligent” Combustion Controls

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Coal-Fired Boilers 607,748 0-30% 100-300 Commercial
Oil/Gas Boilers 32,910 0-30% 100-500 Commercial Wood/Biomass Boilers 9,776 0-20% 200-500 Commercial Process Description:

Sensors and computer software programs are used to control air-fuel ratio to individual burners. Conventional combustion systems provide measured airfl ow to the windbox (that feeds all burners) and to each pulverizer (that feeds from two to eight burners) . However, coal flow to individual burners may deviate by as much as 50%, while airflow to each burner may deviate by over 20%. Measuring and controlling (using existing or new control valves) these quantities at each burner allows the boiler to operate with lower excess air or slightly staged. Sensors are also available to monitor post-combustion processes. Online measurements of unburned carbon and CO provide feedback for burner adjustments. Other sensors evaluate flame quality, furnace temperature, or boiler heat transfer. Software can be rulebased or neural net. Usually the new software resid es on the operator’s digital control system (DCS).

NO x Reduction:

Full -load NO x reductions with combustion monitoring and tuni ng can be expected to range from 0% to 30% depending on factors such as:

o Current state of “out of tune” combustion system.

o Initial NO x level.

o Operational flexibility of th e burner/furnace design.

The highest NO x reductions are usually found on boilers that are able to bias their fuel input to lower burners and bias the airflow to upper burners. At low loads where there may be more operating flexibility, NO x reduction may improve to the 20-40% range, depending on the burner zone stoichiometry and low load operating characteristics of the boiler (e .g., operating at high excess air to control reheat steam temperature).

Cost Information:

In general, the capital costs for combustion monitori ng and tuning are less than $1M per boiler. Operating costs are mainly driven by additional la bor to maintain the new equipment. Often the installation of this technology is driven by the potential to reduce boiler operational expenses. For example, if total airflow is minimized, boiler effi ciency can be increased. Reducing unburned carbon in the ash residue will not only increase boiler efficiency but also could improve sal ability of this byproduct to the cement industry.

An outage is generally not required when implemen ting this technology, but coal-flow sensors and adjustable orifices are best installed when a mill is out of service.C-18 Process: “Intelligent” Combustion Controls Development Status:

Commercially available. Many of the sensors, however , are relatively new and do not have a track record for reliability and dependab ility. Since each application of the t echnology is custom-engineered, there may be a steep learning curve for every user. For now, each installation also requires onsite presence (for a few weeks) from the supplier or other com bustion expert to achieve best results. Practical Considerations:

Boilers with the following design and operating char acteristics are expected to be more suitable candidates for combustion monitoring and tuning:

• Combustion equipment must be in good opera ting condition. The technology will not be able to overcome such factors as poor coal fineness or failure of burner parts.

• Favorable cross-section/height profiles (e.g ., tall boilers which provide for adequate mixing/residence time to maximize effectiveness).

• Excess coal pulverizer capacity so that fuel biasing can be maximized.

Of major importance is acceptance from boiler operators . If operators want to stick with old procedures and operating conditions, the effectiveness of the technology may not be realized.

Compatibility with other air pollution control technologies:

Combustion monitoring and tuning can be implemented with both Low NO x combustion approaches (e.g. LNBs) and post combustion technologies (S NCR/SCR). However, the overall NO x reductions are not strictly additive and careful evaluation is re quired to ensure cost effective strategies. Secondary Environmental Impacts:

Combustion monitoring and tuning has the potentia l to affect both positive and negative secondary environmental impacts depending on factors such as the fuel, burner stoichiometries, boiler physical characteristics, etc.

The following are potential impacts that must be analyzed on an individual unit basis

• CO may increase due to stoichiometry in the burner zone

• LOI may increase due to increased staging

• ESP performance may degrade with increased LOI

References: Power Plant Optimization Guide lines, EPRI Report, December 1998

Alternative Control Techniques Document: NO x Emissions from Industrial/Commercial/Institutional (ICI) Boilers. EPA Document No. EPA-453/R-94-022, July 1994.

Alternative Control Techniques Document: NO x Emissions from Utility Boilers. EPA Document No.C-19 Process: “Intelligent” Combustion Controls EPA-453/R-94-023, July 1994.

Fuller, T., “Field Experience with the Flame Doctor TM System”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003

Kohn, D. “Combustion Optimization Case Studies & Emerging Applications”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003C-20 Process: Iron Slag Addition (CemStar)

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Cement Kilns 41,009 12-30% 0-100 Commercial Process Description:

Change cement formulation by adding waste ir on to lower clinkering temperature and suppress NO x . The iron waste is usually supplied from local steel producti on facilities, which limits the technology to certain geographical areas. NO x Reduction:

NO x reduction is achieved by reducin g clinkering temperature as well as the required heat input to produce a ton of clinker. The technology reduces total NO x emissions by about 20 to 30%, and also may increase clinker production.

Cost Information:

Iron addition provides an overall econom ic benefit while reducing total NO x emissions. The technology is currently being used at several cement plants for its original purp ose of increasing production capacity. There are no capital costs for installing the technology. Operating and maintenance costs depend on the cost of the iron (shipping can be a large portion of this cost). Development Status:

Commercially available.

Practical Considerations:

There is a limit to how much iron that can be incorpor ated into the clinker. Cement product specifications may limit or prevent use of this technology for some products.

Compatibility with other air pollution control technologies:

Should not affect other control systems.

Secondary Environmental Impacts:

None expected.

References: NESCAUM, “Status Report on NO x Controls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal Combustion Engines; Technologies and Cost Effectiveness.” December 2000.C-21 Process: Kiln temperature control

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Cement Kilns 41,009 0 to 20% 200-500 Commercial Process Description:

Add temperature-monitoring device to kiln controls to minimize high-temperature excursions where more NO x is emitted. NO x Reduction:

NO x reduction is achieved by measuring a characteristic flame-zone temperature and then controlling heat input to maintain that temperature. Without dir ect temperature measuremen t, temperatures fluctuate within a wide range since clinker formation is an exothermic reaction. When clinker formation slows down or stops, temperatures fall. Operators respond with a large burst of fuel that sends temperature up by as much as 500 ° F. Then they back off the fuel input. Te mperature measurement helps operators avoid losing clinker formation and thus maintain relatively steady kiln temperatures.

Cost Information:

Capital cost for the technology includes installati on of a continuous temperature monitor along with control system upgrades to tie the temperature signal into the coal feed rate. Operating cost should not change unless lower temperatures adversely affect cement quality.

Development Status:

Commercially available.

Practical Considerations:

The dynamics of a cement kiln are very difficult to control, even with direct temperature measurement and control. Each kiln will react differently. It w ill require considerable operator experience to minimize the temperature on each kiln.

Compatibility with other air pollution control technologies:

Should not affect other control systems.

Secondary Environmental Impacts:

None expected.C-22 Process: Kiln temperature control References: U.S. Environmental Protection Agency. “A lternative Control Techniques Document: NO x Emissions from Cement Manufacturing.” EPA Document No. EPA-453/R-94-004, January 1994.

Johnson, S.A. and Haythornthwaite , S., “Summary of Available NO x Control Techniques for the Cement Industry”, submitted to the Portland Ceme nt Association, Skokie, IL, 1998.C-23 Process: Low-Emission Combustion (LEC)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Reciprocating Engines 86,210 80-90% 190-700 Commercial Process Description:

NO x formation from a spark-ignited engine is highest when the mixture is slightly fuel-lean. LEC enhances the effectiveness of the air/fuel ratio method by enabling much deeper leaning without the adverse effects associated with lean mixtures. Add itional combustion air acts as a heat sink, lowering the temperature in the cylinder and reducing NO x formation. Deeper leaning can be achieved by relocating the spark plug to a precombustion chamber (may u se High-Energy Ignition, see associated description) where the mixture is somewhat rich er than in the cylinder. Early sparking avoids problems associated with ignition and misfiring that can result form leani ng the mixture. Some smaller engines use an “open chamber” LEC design instead of a precombustion ch amber. These designs typically incorporate improved air-fuel mixing systems to achieve stable combustion under very lean conditions. NO x Reduction:

Large, stationary spark-ignition engines usually ach ieve 80% NOx reduction through a LEC Retrofit. A NOx emission level of 125 ppm (at 15% oxygen) is an achievable exhaust NOx value. Up to 90% reduction can be achieved in natural gas engines, a nd about 60-70% for landfill gas engines (probably due to lower initial NOx from the lo wer heating-value landfill gas).

Engines with open-chamber LEC technology typically are designed for excess air levels only slightly above 50%, while engines with preco mbustion chambers typically are designed for excess air levels of 75-100%. Consequently, prechambered engines have generally lower NOx emissions than do openchamber models. Cost Information:

The capital cost of retrofitting these engines depends on the e ngine BHP. For engines firing a single fuel, retrofits have been implemented costing $340/hp for 3400h p engines. A lower capital cost is expected for smaller, medium-speed engines, about $200/hp. Dual-f uel engines have much greater capital costs. For these engines (larger than 1,000 hp), the capital cost can be estimated by

Capital Cost = $405,000 + ($450 x hp).

Retrofitting a 2,500 hp engine is projected to cost $615/hp. Development Status:

Commercially available

The California Air Resources Board considers LEC Retrofit a Reasonably Available Control Technology (RACT) for large spark-ignition engines. LEC b ased on precombustion chamber technology has been in use for over 20 years. All major manufacturers of lean-burn spark ignition engines offer LEC-equipped models. Retrofit kits are also available.C-24 Process: Low-Emission Combustion (LEC) Practical Considerations:

Available for spark-ignition engines fired with g aseous fuels including dual-fuel engines operating in dual-fuel mode (as opposed to firing only diesel fuel). LEC can cause some fuel efficiency decrease. A reasonable fuel efficiency penalty is estimated to be on the order of 0.5%.

Turbocharging and intercooling are requ ired to avoid derate. In retrofit situations, this typically involves upgrading or replacing the turbocharger and in tercooler, or adding this equipment.

Other equipment associated with increased air flows ma y also need to be modified for LEC, such as the air intake and filtration system, the intercooler radiat or, and the exhaust system and muffler. To maintain the optimum A/F ratio, an automated A/ F ratio controller typically is used.

The challenge with very lean combustion is to achie ve proper ignition and stable combustion. Vendors of LEC technology (i.e., engine manufacturers and third-pa rty retrofitters) have met these requirements with some combination of improved combustion chamber design, enhanced air-fuel mixing, and improved ignition systems. Compatibility with other air pollution control technologies:

Compatible with post-combustion NOx technolog ies (SCR, NSCR). However, the overall NO x reductions are not strictly additive and careful evaluati on is required to ensure cost effective strategies. Secondary Environmental Impacts:

Emissions of products of incomplete combustion can increase.

References: Edgerton, S. W., Lee-Greco, J., and Walsh, S. “S tationary Reciprocating Internal Combustion Engines Updated Information on NO x Emissions and Control Techniques (Final Report).” EPA contract No. 68- D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.

NESCAUM. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal Combustion Engines; Technologies a nd Cost Effectiveness.” December, 2000.

State of California Air Resources Board. “CAP COA/ARB Proposed Determination of Reasonably Available Control Technology and Best Available Re trofit Control Technology for Stationary Internal Combustion Engines (DRAFT).” Sacramento, CA, December, 1997.

State of New Jersey Department of Environmental Pr otection. “State of the Art (SOTA) Manual for Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997.

U.S. Environmental Protection Agency. “A lternative Control Techniques Document – NO x Emissions from Stationary Reciprocating Internal Combustion Engines.” EPA-453/R-93-032, July, 1993.

Cooper-Bessemer. Facsimile from J. W. Hibbard to W. Neuffer, U. S. EPA. Information on Low Emission Combustion. Cooper-Bessemer, Cooper Energy Services, Mount Vernon, OH. March 3, 1999. 4pp.



### Dresser-Rand. Facsimile from C. F. Willke to W. Neuffer, U. S. EPA. Information on Low Emission Combustion. Dresser-Rand Servi ces, Painted Post, NY. May 7, 1999. 2pp.C-25 Process: Low-NO x Burners

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Coal-Fired Boilers 607,748 30 to 60% 200-1000 Commercial Cement Kilns 41,009 0 to 20% 500-1000 Commercial Oil/NG Boilers 32,910 30 to 60% 200-1000 Commercial Glass Manufacturing 5,033 ~ 40% 790-1,680 Commercial Refinery Process Heaters 9,311 30 to 60% 5,900 (with FGR) Commercial Process Description:

LNB’s operate on the principal of carefully controlling the rate of mixing of air and fuel within the flame so that peak flame temperatures are low and fuel- bound nitrogen is releas ed in a region where the concentration of oxygen is very low. This inhib its the formation of both fuel and thermal NOx by reducing the concentration of oxygen in the flame zone . Most LNB’s work by limiting the amount of air in the primary flame creating a central fuel-rich flam e core. Additional air is introduced to surround the primary flame where the temperature is lower, limiting thermal NO x formation. A few low-NO x burners split the coal flow into two or more streams to create multiple fuel-rich regions. One Japanese burner concentrates the coal-primary air mixture, and introduc es the dilute coal stream downstream of the burner while air is introduced only to the primary flame. Th e fuel introduced into the primary flame zone results in a high temperature fuel rich central flame. Th e balance of coal is added outside the primary flame where it burns at a lower temperature. NO x Reduction:

Full load NO x reductions with Low-NO x Burners can be expected to range from 30% to 60% depending on factors such as:

• Fuel type.

• Initial NO x level.

• Excess air

• Operational flexibility of the boiler or furnace.

For coal-fired boilers, NO x emissions rates as low as 0.15 lb/MBtu are achievable, particularly when burning low rank coals. However, the fuel nitrogen content of coal is such that significantly lower emission rates are probably not possible with coal. Lower emission rates can be achieved with natural gas. Installing Low-NO x burners is usually the first step taken to reduce NO x emissions. Cost Information:

In general, the capital costs for burners range from $10,000 to 50,000 per burner plus installation. The lower end of this range applies wh en existing burners are modified instead of replaced to achieve lower NO x . Operating costs are negligible unless increased unburned carbon results in lost revenues from ash sales. An outage is generally required when impl ementing this technology, but coal-flow sensors and adjustable orifices are best installed when a mill is out of service.C-26 Process: Low-NO x Burners

Development Status:

Commercially available.

Practical Considerations:

Since low-NO x Burners usually produce longer flames, th e size and shape of the furnace could cause problems for some installations. Flame impingement on sidewalls or rear wall can result in ash deposits, corrosion, or unacceptable unburned carbon in the flue gas. Most burners have op tional configurations to shape the flame at the expense of less NO x reduction.

Compatibility with other air pollution control technologies:

Low-NO x burners can be implemented with other NO x -control technologies such as OFA, SNCR, or SCR. In general, the NO x reduction achieved with LN B make post-combustion NO x control technologies more cost-effective.

Secondary Environmental Impacts:

Low-NO x burners can cause both positiv e and negative secondary envir onmental impacts depending on factors such as the fuel, burner stoichiometr ies, boiler physical characteristics, etc.

The following are potential impacts that must be analyzed on an individual unit basis

• CO may increase due to stoichiometry in the burner zone

• LOI may increase due to increased staging

• ESP performance may degrade with increased LOI or finer particulate.

References:

EPRI, “Retrofit NO x Controls for Coal-Fired Utility Boile rs – 2000 Update”, EPRI Final Report, December 2000

EPRI, “Retrofit NO x Controls for Coal-Fired Utility Boilers – 1996 Update Adde ndum”, May 1997C-27 Process: Low-NO x Calciners

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Cement Kilns 41,009 30 to 50% 1000-5000 Commercial Process Description:

Replace the riser duct in existing preheater/precalcine r kilns with new equipment designed for staged combustion. The new duct has separated air and fu el injection points, and extended residence time downstream of the final air addition point to assu re acceptable burnout and minimize CO or hydrocarbon emissions. NO x Reduction:

NO x reduction is achieved by creating two separate combus tion zones. The burner zone is fired fuel-lean to create the high temperatures needed for clinker form ation. Limestone calcination, which takes place at temperatures in the range of 1600 to 1800 ° F, is accomplished in the second combustion zone in the tower. NO x reductions as high as 50% can be achieved by controlling the size of the fuel-rich region in the second combustion zone. Conversely, if combusti on is fuel lean or well mixed in the second zone, NO x will not be reduced. The ideal stoichiometric ratio in the calciner is 0.7 to 0.8. Some systems do not perform well because the second combustion zone is too fuel-rich (SR < 0.6), causing significant NO x production when the staging air is added.

Cost Information:

Capital cost for the technology includes additional inj ectors, ductwork and controls. In some cases, the cyclones used to improve gas-solids contact are al so replaced. Capital cost range from $500,000 and 5,000,000 depending on how much of the existing towe r is replaced. Operating costs should not change unless cement quality degrades due to lower temperatur es or locally reducing conditions. An outage is required to install the new equipment.

Development Status:

Commercially available.

Practical Considerations:

Space to fit the newer larger equipment may not be available in all kilns.

Compatibility with other air pollution control technologies:

Reducing conditions may increase sulfur emissions or require additional SO 2 emission controls.

Secondary Environmental Impacts:

None expected.C-28 Process: Low-NO x Calciners References:

Rother, R. and Kupper, D., “Staged Fuel Supply – An Effective Way of Reducing NO x Emissions”, Zement-Kalk-Gips, No. 9. 1989.C-29 Process: Mid-Kiln or Tower Tire Injection

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Cement Kilns 41,009 15-30% 0-1000 Commercial Process Description:

Cement kilns are normally fired with a single open-pipe burner fueled by coal or natural gas. However, a portion of the main fuel may be replaced by a waste fu el injected in the mid-kiln region of long, wet or dry kilns, or in the calcining region of tower kilns. Special injectors have been designed to time the introduction of two to four tires into the mid-kiln regi on as the kiln rotates. Due to rotation, tires can only fall into the kiln once per revolution when the door is on top. Alternately, tires can be dropped into the tower where temperatures are high enough to support combustion.

Mid-kiln tire injection is attractive because it not only reduces NO x but also generates revenue in the form of tipping fees and reduced fuel requirements. Ca dence Environmental Energy, a subsidiary of Ash Grove Cement, offers an automated whole-tire injec tion system, including a fork that picks up the tires and drops them into the kiln through a gate asse mbly. A second option is to set up a tire shredding operation on site and inject tire flake into the kiln.

NO x Reduction:

NO x is lowered by burning some of the fuel at a lowe r temperature, and by creating pockets of fuel-rich gas as the tires decompose. Hydrocar bons from tire destruction can reduce NO x formed in the burner flame. Results to date have varied from 15 to 30% NO x reduction, depending on:

• Kiln type.

• Number of tires injected.

• Injection temperature.

In some installations, a booster fan has been mounted on the kiln downstream of the tire injection point to provide additional burnout air. This “NO x fan” gets rid of the high CO or smoke emissions caused by the tires, and may allow operation at higher tire injection rates. Cost Information:

The capital costs for installing a mid-kiln tire injection system are about $2 to 4M. Operating and maintenance costs should not be affected. Often the installation of this technology is driven by the tipping fee revenue generation. If this is possible, in jector costs can be recovered within a few years.

An outage is required when implementing this technolo gy, but downtime can be minimized at sites where space is sufficient for installing the injection system ahead of time (without getting in the way of kiln operation).

Development Status:

Commercially available.C-30 Process: Mid-Kiln or Tower Tire Injection Practical Considerations:

The main purpose of a cement kiln is to produce as mu ch high-quality clinker as possible at the lowest energy cost. Over-feeding tires creates locally reduc ing conditions that cause smoke, soot, and spoil the naturally occurring sulfur capture in the clinker resulting in higher SO 2 emissions. The practical limit on tire injection is replacement of about 10 to 30% of the fuel, depending on the kiln design. Also, since tires are injected every two minutes, the NO x emissions rise and fall erra tically, making control very difficult. Compatibility with other air pollution control technologies:

High airflows from the NO x fans can cause increased carryover of cement kiln dust (CKD) into the exhaust. Reducing conditions in the flame zone increase SO 2 emissions. Secondary Environmental Impacts:

Combustion monitoring and tuning has the potentia l to effect both positive and negative secondary environmental impacts depending on factors such as th e fuel, burner air-fuel ratio, kiln design, etc.

The following are potential impacts that must be analyzed on an individual unit basis

• CO, hydrocarbons and soot emissions may increase due to tire byproducts escaping the secondary combustion zone.

• SO 2 may increase due to increased staging.

• ESP performance may degrade with increased CKD. References:

U.S. Environmental Protection Agency, “A lternative Control Techniques Document: NO x Emissions from Cement Manufacturing.” EPA Document No. EPA-453/R-94-004, January 1994.

“Stick a Fork in It”. Product Brochure from Cadence Inc., 1997.C-31 Process: Non-Selective Catalytic Reduction (NSCR)

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status IC Engines, rich-burn only 111,488 40-98% < 500 Commercial Process Description:

In NSCR, the engine exhaust is routed to a catalyst bed across which NO x is reduced to nitrogen gas. At the same time, VOC and carbon monoxide are oxidized to water and carbon dioxide. Because the catalyst reduces emissions all three of these pollutants, NSCR is often referred to as a “three-way catalyst” system. These systems are similar to the catalytic converters used on automobiles.

For an NSCR system to operate optimally (i.e., to minimize NO x emissions), the inlet exhaust stream must have very low oxygen content, as well as proper concentrations of NO x , hydrocarbons, and carbon monoxide. This requires initial engine adjustments, followed by careful monitoring of oxygen content in the exhaust. For this reason, an automatic air-fuel (A /F) ratio controller typically is used to regulate the exhaust oxygen content entering the catalyst bed. The controller adjusts the A/F ratio based on input from an oxygen sensor upstream from the catalyst bed.

Because of the requirement for low oxygen content, NSCR systems are limited to rich-burn SI engines. NO x Reduction:

This source indicates that these catalyst systems reduce NO X emissions by over 98 percent, while reducing VOC by 80 percent and carbon monoxide by over 97 percent. NO x levels in the range of 0.1 to 1.0 g/bhp-hr have been achieved.

Cost Information:

Capital cost for NSCR includes the catalyst as well as the addition of oxygen sensors and controls. Catalyst replacement generally occurs af ter about 20,000 hours of operation.

Development Status:

Commercial. Information from vendors of NSCR system s indicates that NSCR three-way catalysts have been installed on over 1,000 IC engines in the United States and have been in use for over 10 years. . Practical Considerations:

The engine adjustments required to optimize NSCR syst ems typically reduce the efficiency of the engine, harming fuel economy. The biggest operational problem associated with NSCR h as been damage to the catalyst caused by excessive temperature. This is caused when the exhaust stream is too fuel rich. In this situation, the uncombusted natural gas is rapidly oxidiz ed in the catalyst bed, burning it out. At about 1,300 o F, the catalyst sustains damage.

Compatibility with other air pollution control technologies:

Enhanced removal of CO and VOC can be achieved.C-32 Process: Non-Selective Catalytic Reduction (NSCR)

Secondary Environmental Impacts:

None expected. References:

Manufacturers of Emission Controls Association. “E mission Control Technology for Stationary Internal Combustion Engines.” Status Report, July 1997.

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “S tationary Reciprocating Internal Combustion Engines Updated Information on NO x Emissions and Control Techniques (Final Report).” EPA contract No. 68- D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.C-33 Process: NOxTech

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Reciprocating Engines 86,210 90-95% ~ 1000 Commercial Process Description:

According to product literature, the NOxTech ® emission control system, developed by NOxTech Inc., NOxTech is an automated system in which exha ust gases are chemically treated with a nonhazardous liquid chemical. The technology involves replacing th e engine exhaust silencer with a reaction chamber where NO x and reagent react to form nitrogen, water vapor, and carbon dioxide. The non-catalytic chemical reagent is injected into the exhaus t at temperatures between 1,400 and 1,500 °F. NO x Reduction:

The vendor states that NOxTech has been proven to remove 90-95% of NOx, as seen in the 4,000-bhp diesel-powered generator on Catalina Island. Cost Information:

Based on vendor literature, self-sustained, gas- phase autocatalysis reduces emissions of NO x are reduced at costs as low as $1,000/ ton.

Development Status:

Commercially available

As of August 2000, the system has been installed and is operating on several diesel generators in California. Based on commercial performance in th ese engines, NOxTech has been demonstrated as BACT for some diesel engines. Practical Considerations:

The exhaust gas must be heated to achieve the temp eratures necessary for the NOxTech system reactions. A heat exchanger should be placed downstream from the reactor to reclaim and reuse this heat energy. Compatibility with other air pollution control technologies:

Compatible with low-NO x combustion approaches (LNB, combustion modification). Can be used to augment LEC. Secondary Environmental Impacts:

Technology also potentially removes 60-80% of part iculate matter, 90% of VOC, and 50-70% of carbon monoxide from the exhaust, as seen in the 4,000-bhp diesel-powered generator on Catalina Island.

The process produces trace ammonia emissions of less than 2 to 5 ppmv.C-34 Process: NOxTech References:

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “S tationary Reciprocating Internal Combustion Engines Updated Information on NO x Emissions and Control Techniques (Final Report).” EPA contract No. 68- D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.

NOxTech Inc. “NOxTech ® Technology.” website. www.noxtechinc.com/products.htm

.

NOxTech Inc. Letter and attachments from E. Cazzola to Mary Jo Krolewsky, U. S. EPA Acid Rain Division. April 12, 1999

.C-35 Process: Overfire Air (OFA)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Coal-fired boilers 607,748 20-40% 250-600 Commercial Oil/NG boilers 32,910 40-80% 1,000-2,000 Commercial Wood/Biomass boilers 9,776 20-60% 200-2,000 Process Description:

OFA, like LNB’s, represents practical approaches to minimizing the formation of NO x during combustion. Simply, this is accomplished by "contr olling" the quantities and the way in which fuel and air are introduced and mixed in the boiler (referred to as staging).

In the case of OFA, the approach consists of diver ting some of the combustion air (typically up to about 30%) to dedicated injection nozzles (called OFA ports) located some distance above the burner or main combustion zone. Variations include the design and lo cation of the OFA ports, the supply of air to the OFA (either directly from the windbox, or from a dedicated booster fan). NO x Reduction:

OFA, which can be used separately or as a system with LNBs, is capable of NO x reductions of 20% - 40% from uncontrolled levels, when used alone. The type of boiler (e.g., dry vs. wet-bottom, wall- vs. tangential-fired, NSPS vs. pre-NSPS, etc.) and the type of fuel will influence the actual performance achieved. Cost Information:

OFA technologies have little or no impact on operating cost s (other than the poten tial for an increase in unburned carbon - efficiency loss -, and the resulting impact on ash disposal options). Retrofit costs are site-specific. As such, the economics of these t echnologies are driven by capital/retrofit costs which typically range from $5-$10/kW, with the lower range reflecting easier application whereas the higher costs are typically associated with more difficult and involved retrofits.

From a schedule standpoint, OFA retrofit projects can require outages of 3 – 6 weeks, depending on factors such as scope of work, integration with other plant outage requirements, etc. Development Status: Commercial

OFA and LNB’s are the most prevalent in the power indus try at present. Plants that have had to comply with Title IV of the CAAA of 1992 have largel y used these technologies for compliance. Competing manufacturers have proprietary designs, geared toward s application in different boiler types, as well as reflecting their own design philosophies. Practical Considerations:

Boilers with the following design and operating char acteristics are expected to be more suitable candidates for OFA applications:

• firing lower-sulfur fuels (e.g., less propensity for waterwall corrosion)

• low baseline unburned carbon (e.g., to minimize ash salability impacts).C-36 Process: Overfire Air (OFA)

• favorable cross-section/height profiles (e.g ., tall boilers which provide for adequate mixing/residence time to maximize effectiveness).

• units with existing burners in good operating condition,

• Potential O&M impacts due to combustion NOx controls include:

• Change in optimum excess air level: 0.5-1.5 percentage points increase in excess O 2 is possible

• 3-5 percentage points increase in LOI is possible; in general, as higher NO x reduction is being sought, the higher the probability for increased LOI (NO x vs. LOI trade-off)

• Changes in reheat and superheat steam temp eratures (typically lower by 20-50 degrees F) are possible in some applications. Compatibility with other air pollution control technologies:

OFA technologies are often used in conjunction with LNB’s. As a main combustion based NO x control approach, OFA is fully compatible with other NOx controls including LNB’s, reburning (OFA is an integral component of reburning), as well as the post combustion technologies such as SNCR and SCR Secondary Environmental Impacts:

OFA, like all combustion modification approaches face a common challenge: that of "striking a balance" between NO x reduction and fuel efficiency. The concern is exemplified by the typically higher carbon levels in the fly ash, which reflect lower combustion e fficiency but also the contamination of the fly ash itself possibly making it unsuitable for reutilization (e.g., cement industry). References:

EPRI, “Retrofit NO x Control Guidelines for Gas- and Oil-Fire d Boilers”, Final Report, December 1993.

EPRI, “Retrofit NO x Controls for Coal-Fired Utility Boile rs – 1996 Update A ddendum”, May 1997.

EPRI, “Retrofit NO x Controls for Coal-Fired Utility Boile rs – 2000 Update”, EPRI Final Report, December 2000C-37 Process: Oxy-Fuel Firing

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Glass Manufacturing 5,033 80-85% 2,150-4,400 Commercial Process Description:

Oxy-fuel melting involves the replacement of th e combustion air with oxygen (>90% purity). The technique can be used with either natural gas or oil as the fuel, although the use of gas is more common. The elimination of the majority of the nitrogen fo rm the combustion atmosphere reduces the volume of the waste gases (composed mainly of CO 2 and water vapor) by 70-85 % de pending on oxygen purity. In general, oxy-fuel furnaces have th e same basic design as recuperative melters, with multiple lateral burners and a single waste gas exhaust port. In the most modern furnaces the geometry is optimized for oxy-fuel firing and minimization. Furnaces designed for oxygen combustion do not currently utilize heat recovery systems to pre-heat the oxygen supply to the burners, due to safety concerns; however, the technique potentially involves s ubstantial energy savings because it is not necessary to heat the atmospheric nitrogen to the temperature of the flames. The formation of thermal NO x is greatly reduced because the main source of nitrogen in the furnace is much lower. NO x Reduction:

Compared to air-fuel fired furnaces, NO x emissions are generally reduced by 70-90%. This reduction equates to:

• <1 kg/ton glass for fiber and container glass furnaces

• 1-2 kg/ton glass for special glass (without nitrate addition)

The latest versions of oxy-fuel burners combined with optimized furnace design and operation can in some cases reduce emissions to 0.3-0.8 kg NO x /ton of glass melted. No information is available for emissions from flat glass production, but emissions of 0.5 to 1.5 kg/ton of glass melted are considered likely. Cost Information:

In general, capital costs for oxy-fuel firing are $1,93 0K-$9,810K. An important factor in the capital cost is that oxy-fuel furnaces do not have a conventional combustion gas preheat system and so the capital cost is generally lower than for a regenerative or recupe rative furnace of comparable pull-rate. In most applications, the determining factor regarding cost ef fectiveness of oxy-fuel firing will be the difference between the energy savings and the costs of the oxygen compared with the costs of alternative NO abatement techniques. Development Status:

Commercially available

It is estimated that 5-10% of the world’s glass produc tion is made with oxy-fuel melting, but this figure varies between the sectors. There are several exam ples of oxy-fuel furnaces operating successfully in the following sectors: container glass, glass wool, special glass (particularly TV glass), continuous filament glass fiber, and frits. Trials have been carried out in the domestic glass sector resulting in good NO x reduction, but problems occurred with severe foaming. The problems encountered in domestic glass production are similar to those initially encountered in other applications e.g. container glass. SimilarC-38 Process: Oxy-Fuel Firing solutions are likely to be possible but the higher quality requirements make them more difficult to apply. There are several examples of the technique operating successfully for domestic glass production worldwide. Considerable development work is bein g undertaken and the number of plants and the level of operating experience are increasing. Practical Considerations:

The merits of oxy-fuel firing vary greatly from ca se to case depending on furnace size and availability of pure oxygen. The technique is most effectively in stalled during furnace rebuild. Hot installation may lead to energy savings and to an increased pull ra te; however, it is unlikely to result in lower NO x emissions, and there is a danger of accelerated refractory wear.

Furnace waste-gas temperature can be very high, 1200 -1300 °C and will usually require cooling. Due to high water content and concentration of corrosive speci es, cooling is usually by dilution with air. The higher temperatures associated with the tec hnique can result in higher refractory wear.

Oxygen required for combustion can be supplied either by delivery to the site or by on-site production. Except for very small applications, the amounts of oxygen required usually make it more economical to produce the oxygen on-site. Compatibility with other air pollution control technologies:

Addition of a cullet preheating system, which can also reduce NO x and other emissions by reducing the amount of fuel required, can add to the energy savings of oxy-fuel firing by recovering heat from the waste gases. See cullet preheating description. Secondary Environmental Impacts:

Oxy-fuel firing can also help to reduce overall emissions of volatile materials form the furnace (particulates, fluorides, chlorides etc.), due to redu ces gas flow over the melt and in some cases reduced turbulence.

• Particulate emissions in soda-lime glas s can be reduced to 0.2-0.3 kg/ton.

• Particulate emissions most effectively redu ced for boron containing glasses (up to 50%).

• Reduction in fuel usage leads to lower SO 2 emissions for oil-fired furnaces.

Concentrations of all pollutants may actually be hi gher due to reduced gas volume, although the absolute emission is reduced. Dilution with cooling air usuall y brings the concentrations closer to more normal levels. References:



### European IPPC Bureau. “Reference Document on Best Available Techniques in the Glass Manufacturing Industry.” Seville, Spain, October, 2000.C-39 Process: Oxygen-Enhanced Combustion Modifications

Category NO x , TPY (WRAP 1996) %NO x reduction Cost, $/ton Status Coal-fired Boilers 607,748 30 to 80% 1,000-2,000 Near Commercial Cement kilns 41,009 0-20% 100-1000 Commercial Process Description:

In coal-fired boilers, O 2 injection is used to improve effectiveness of OFA operation. Small amounts of oxygen are introduced into the burner zone thro ugh specially designed lances. The added O 2 creates a local hot spot that increases the rate of coal volatile release, encourages more NO x reduction, and enables more fuel-rich operation where less NO x is formed. The technology has been demonstrated on a 44-MW coal-fired boiler.

In cement kilns, oxygen lances are used to create a hot spot in the flame zone and achieve higher kiln throughput (increase clinker production). In doing so, NO x is not reduced but NO x emission rates (lb. NO x /ton of clinker) goes down in proportion to the increase in production. O 2 injection achieves even higher production when cement kiln dust (CKD) is co-injected. The CKD also quenches peak flame temperature to achieve some reduction in thermal NO x formation. NO x Reduction:

In the coal-fired boiler demonstration, conventional OFA reduced NO x to around 0.35 to 0.40 lb./MBtu. O 2 injection lowered the NO x further to around 0.22 to 0.25 lb./MBtu, while also decreasing LOI and opacity, and allowing better steam temperature control when firing bituminous coal. NO x reductions down to 0.16-0.19 lb./MBtu were achieved when the unit switched to a blend of 90% sub-bituminous and 10% bituminous coal.

In the cement industry, oxygen injection has achieved 0 to 20% NO x reduction in conjunction with a 0- 5% kiln capacity increase. Increased capacity (when it occurs) is the primary cause of the NO x reduction. Cost Information:

The primary cost of all these applications of oxygen- enhanced combustion is the cost of the oxygen. Oxygen required for combustion can be supplied either by delivery to the site or by on-site production. Except for very small applications, the amounts of oxygen required usually make it more economical to produce the oxygen on-site. Capital cost for oxyge n storage and delivery systems range from $100,000 when pipeline gas is used, to $1,500,000 when on-site storage is required. In general, capital costs are $1,930K-9,810K when on-site generation is chosen.

An important factor for the capital cost of oxy-fu el firing is that oxy-fuel furnaces do not have a conventional combustion gas preheat system and so the capital cost is generally lower than for a regenerative or recuperative furnace of comparable pull-ra te. In most applications, the determining factor regarding cost effectiveness of oxy-fuel firing will be the difference between the energy savings and the costs of the oxygen compared w ith the costs of alternative NO x abatement techniques.C-40 Process: Oxygen-Enhanced Combustion Modifications Development Status:

The coal-fired boiler technology needs to be demons trated over several months to show effectiveness, reliability, and safety. Such a demonstration is expected to begin during the summer of 2003. The technologies are commercially available for application to cement and glass manufacturing. Practical Considerations:

Using oxygen enrichment results in less flue gas flow since it eliminates the nitrogen in the air it replaces. The merits of oxy-fuel firing vary greatly from ca se to case depending on furnace size and availability of pure oxygen. The technique is most effectively in stalled during furnace rebuild. Hot installation may lead to energy savings and to an increased pull ra te; however, it is unlikely to result in lower NO x emissions, and there is a danger of accelerated refractory wear.

Furnace waste-gas temperature can be very high, 1200 -1300 °C and will usually require cooling. Due to high water content and concentration of corrosive speci es, cooling is usually by dilution with air. The higher temperatures associated with the tec hnique can result in higher refractory wear.

Many potential users do not want to own and operate an air-separation plant. Oxygen suppliers offer to build, own, and operate the air separation system in re turn for a long term contract for oxygen sales. Compatibility with other air pollution control technologies:

Oxygen-enhanced combustion on coal-fired boilers can only be effective when implemented with OFA. If O 2 is added to an unstaged flame, NO x emissions will increase. The technology can also be combined with SNCR or SCR for greater NO x reductions. O 2 can also be used with post-combustion NO x control technologies in cement kilns and glass melters. Secondary Environmental Impacts:

Oxygen-enhanced combustion may lessen the impacts of staged combustion. The following are potential impacts that must be analyzed on an individual unit basis:

• CO may increase due to stoichiometry in the burner zone

• LOI may increase due to increased staging

• ESP performance may degrade with increased LOI or finer particulate.

Oxy-fuel firing can also help to reduce overall emissions of volatile materials from the kiln or furnace (particulates, fluorides, chlorides etc.), due to redu ced gas flow and in some cases reduced turbulence.

• Particulate emissions in soda-lime glas s can be reduced to 0.2-0.3 kg/ton.

• Particulate emissions most effectively redu ced for boron containing glasses (up to 50%).

• Reduction in fuel usage leads to lowe r SO2 emissions for oil-fired furnaces.

Concentrations of all pollutants may actually be hi gher due to reduced gas volume, although the absolute emission is reduced. Dilution with cooling air usuall y brings the concentrations closer to more normal levels. References:

U.S. Environmental Protection Agency, “A lternative Control Techniques Document: NO x Emissions fromC-41 Process: Oxygen-Enhanced Combustion Modifications Utility Boilers”. EPA Document No. EPA-453/R-94-023, July 1994.

Bool, L., “NO x Reduction from a 44MW Wall-Fired Boiler Utilizing Oxygen-enhanced Combustion”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003C-42 Process: Pre-Stratified Charge

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Reciprocating Engines 86,210 80-95% <500 Commercial Process Description:

Air is injected into the intake manifold so that duri ng the intake stroke, the piston initially draws in air, followed by a fuel-rich air-fuel mixture. Thus, the mixture near the spark plug is fuel rich, promoting good combustion, while the mixture away form the sp ark plug is very lean, acting a s a heat sink and suppressing NO x formation. NO x Reduction:

From tests for ten engine models ranging from 100 to 800 bhp, NO x emissions ranged from about 0.1 g/bhp-hr to 9.5 g/bhp-hr, with a mean of 0.6 g/bhp-hr. Engines ranging from 300 to 800 bhp averaged 95% reduction, while tests on engines less than 50 bhp showed NO x reductions averaging 77%.

Vendors guarantee the achievable NO x emission level of 2.0 g/bhp-hr. Cost Information:

See EPA Report below.

Development Status:

Commercially available. In commercial use since 1980s.

Practical Considerations:

Applicable only to carbureted (i.e. non-fuel-injected) rich-burn engines. May cause some power derating; 20% has been observed. While the PSC system itself requires very little maintenance, the engines require more frequent overall maintenance. Compatibility with other air pollution control technologies:

Compatible with exhaust gas recirculation (EGR), with air injected by PSC system coming form the engine’s exhaust. May also be used in conjuncti on with post-combustion technologies. However, the overall NO x reductions are not strictly additive and careful evaluation is required to ensure cost effective strategies. Secondary Environmental Impacts:

Possible increase in CO and VOC emissions. References:

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “S tationary Reciprocating Internal Combustion Engines Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68- D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.C-43 Process: SCONOx Technology

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Reciprocating Engines 86,210 95% Not available Commercial Oil/NG boilers 32,910 70-99% Not available Commercial Turbines 25,278 >90% >7,000 Commercial Process Description:

The SCONOx system adds a chemical reactor for NO x sorption using a catalyst/sorbent to remove NO x , carbon monoxide, and VOC. NO x is oxidized in the presence of a platinum-based catalyst and the resulting NO 2 is adsorbed onto a potassium carbonate sorbent, forming potassium nitrites. The sorbent must be regenerated periodically by passing a cont rolled mixture of regeneration gases across its surface in the absence of oxygen. Regeneration gases react with the nitrites to form water and elemental nitrogen. The system is installed as a bed of sorbent/catalyst. A system of louvers and piping allows portions of the bed to oxidize and adsorb pollutants and other portions of the bed to undergo regeneration. NO x Reduction:

The first commercial installati on in gas turbines achieved NO x emissions below 2 ppm, a reduction of over 90%.

Vendor testing shows SCONOx reduced NO x emissions in natural gas-fired reciprocating engines up to 95%. Preliminary testing in diesel engines found th e technology reduced NOx by 98.9% to 0.4 g/bhp-hr. Cost Information:

Cost for Gas Turbine application is pre liminary and from DOE reference below.

Development Status:

Commercially available

First commercial installations in gas turbines commen ced in 1999. Commercial applications for natural gas-fired reciprocating engines went online in 2000. Diesel applications were sold in 2000, but further information is unavailable. Practical Considerations:

The technology was initially applied only to gas turbin es, but variations have be en developed for naturalgas and diesel-fired reciprocating engines.

Regeneration gas flow is about 1 pe rcent of exhaust gas flow. Typically, natural gas is converted to hydrogen in a reformer at 600-900 ° F to produce the regeneration gas. The regeneration step is complicated and the reformer requires additional labor and maintenance.

Exhaust temperatures should be controlled at 600-700 ° F for best NO x reduction. Performance also improves as exhaust gas oxygen levels approach zero. Temperature and O 2 control may be difficult at some sites. The catalyst is de-activated by soot or sulfur species, so catalyst must be cleaned every 20,000 hours.C-44 Process: SCONOx Technology

SCOSOx is required to remove SO 2 , which would otherwise poison the SCONOx catalyst. SCOSOx requires regeneration similar to SCONOx.

Compatibility with other air pollution control technologies:

Due to the emerging nature of the technology, little is discussed about compatibility with other technologies. Based on tests with LEC engines, issues regarding increases in CO/VOC may be of concern Secondary Environmental Impacts:

Carbon monoxide and VOC are also reduced up to 95%. References:

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “S tationary Reciprocating Internal Combustion Engines Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68- D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.

Amar, K.P., Staudt, J. “Status Report on NOx Contro ls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal Combustion Engines; Technologies and Cost Effectiveness.” Northeast States for Coordinated Air Use Management , Boston, MA, January, 2001.

Goal Line Environmental Technology News. “Cummins Engine Co. Tests SCONOx ® for Diesel IC Engines.” Oct 1999. Vol 1, Issue 3.C-45 Process: Selective Catalytic Reduction (SCR)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Coal-fired boilers 607,748 70-90% 1,500-2,000 Commercial Reciprocating Engines 86,210 75-90% <1,000 Commercial Oil/NG boilers 32,910 70-90% 2,000-10,000 Commercial Turbines 25,278 ~90% 500-10,000 Commercial Refinery Process Heaters 9,311 75-90% 3,700-11,000 Commercial Glass Melters 5,033 75-90% --- Commercial Process Description:

Post-combustion NO x controls include Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR). They are fundamentally similar, in that both use an ammonia-containing reagent to react with the NO x produced in the boiler, and convert it to harmless nitrogen and water, SNCR accomplishes this at higher temperatures (1700oF-2000oF ) in the upper furnace region of the boiler, while SCR operates at lower temperatures (about 600oF to 750°F) and hence needs a catalyst to produce the desired reaction between ammonia and NO x . High temperature catalysts, sometimes used in gas turbine applications can operate at temperatures up to ~1100 ° F

Conventional SCR incorporates a reactor located typica lly between the economizer and the air preheater. The reactor housing is sized to provide optimum flue gas velocity and catalyst volume.

In about one-quarter to one-third of the German SC R installations, the SCR reactor is located downstream of the flue gas desulfurization (FGD) system. This is called a “tail-end” configuration. Because the catalyst operates at temperatures of at least 600+ ° F, the flue gas temperature needs to be increased between the FGD and tail-end SCR. This reheating th e flue gas before it enters the SCR. This extra equipment makes the capital and energy costs higher th an in a conventional SCR. On the other hand, the tail-end SCR uses less catalyst, experiences a longer cata lyst life, and can be built without impacting plant operations, with tie-in typically occurring during a normal two-week outage.

An ammonia injection system is located upstream of the catalyst typically in a grid configuration to inject and disperse the ammonia uniformly into the flue gas. NO x Reduction:

NO x reductions of 90+% are capable with SCR. NO x reduction levels are typically limited by the need to control residual ammonia to low levels (2-5ppm), a nd by cost effectiveness considerations (higher costto-NOx reduction ratio for deeper reductions. SCR ap plications typically represent a balance between the percentage NOx reduction require ment, residual ammonia limit, SO 2 to SO 3 oxidation rate, and ability to continuously maintain a uniform, stable NH 3 /NO x distribution across the entr y plane into the catalyst. Cost Information:

Capital costs for retrofit SCR systems to power gene ration sources are mostly within the range of $60/kW to about $140/kW. The lower end of this range app lies to retrofits with nominal difficulty. The high end of the range would typically be associated with retr ofits having significantly impeded construction access, extensive relocations, and difficult ductwork transitions.C-46 Process: Selective Catalytic Reduction (SCR) Operating costs are mainly driven by cost of reagent, energy penalty (pressure loss, ammonia vaporization), catalyst replacement and dedicated O&M costs

Development Status:

Commercially available

SCR is widely used oversees (Germany and Japan re present over 50,000 MW of in stalled capacity. In the US, significant activity has recently occurred with SCR installations on coal fired units. Projections for over 100 new installations in the US in the next 5 years have been made. Practical Considerations:

From a technical perspective, SCR can be used many different applications and sources. However, the cost can vary considerably depending on retrof it difficulty and plant layout, fuel, or unit operating characteristics. The performance of an SCR system is dependent on the size and arrangement of the catalysts, the fuel burned, gas flow conditions at the catalyst entrance, and the type and amounts of reagent used. A number of factors should be considered when installing an SCR system. They include:

• Operating temperature window temperature which is a function of the catalyst formulation but typically ranges between 600°-750°F for sulfur bearing fuels,

• Ammonia injection system design to ensure good distribution in proportion to the mass flux of NO x for optimized performance (maximum NO x reduction and minimum NH 3 slip)

• Flue gas pressure drop which is dependent upon fl ue gas velocity, catalyst configuration, and quantity of catalyst required to achieve specified NO x reduction

• Flue gas flow/temperature distribution, as catalyst guarantees are typically predicated upon predetermined conditions

• Fouling potential of catalyst and/or APH surfaces. Reaction of excess ammonia with SO 3 generated in the furnace when firing sulfur bear ing fuels will form ammonium bisulfate/sulfate that deposits on the cold end sections of the ai r heater to cause corrosion and increased pressure drop

• Flue gas contaminants - alkaline compounds, ha logens, and heavy metals can cause catalyst poisoning.

• Decreased heat rate at low load if economizer byp ass is needed to maintain the required flue gas temperature in the SCR reactor. Compatibility with other air pollution control technologies:

SCR applications are fully compatible with combusti on NOx controls (LNBs, OFA, reburn, etc.) and can be used with other amine-based controls (e.g. SNCR) in hybrid configurations. In theory, most of these technologies can be used together. However, NO x reductions are not necessarily additive, and more importantly, the “economics” of the combined technologies may or may not be cost-effective. Such analyses are highly site- and strategy-specific.

However, several such combinations of technology are considered attractive and have or are gaining acceptance. For example, the combination of LNB/OFA with either SCR or SNCR is more prevalent than the application of the post-combustion technologies alone . The economics of this approach are justified by the reduced chemical and capital costs due to lower NO x levels entering the SCR system.C-47 Process: Selective Catalytic Reduction (SCR) When combining SCR with NO x control technologies whose performance depends on mixing characteristics in the upper furnace (i.e., OFA, reburn, or SNCR), potential stratification of inlet NO x levels to the SCR becomes a key design issue that can impact SCR performance.

Secondary Environmental Impacts:

Potential impacts arising from the application of SCR include:

• Increased corrosion downstream of the SCR from SO 3 formed on the catalysts

• Air heater fouling due to ammonia bisulfate formation in the cold end

• Ammonia contamination of fly ash affecting its salability or disposal

• Increased system pressure drop

• FGD waste management, if located downstream of SCR

These impacts are mostly relevant to applications w ith sulfur and other contaminants-bearing fuels (e.g. coal/oil). Applications with natural gas are more be nign both with respect to catalyst choice and life, as well as other plant impacts. References:

EPRI, “ Retrofit NO x Controls for Coal-Fired Utility Boile rs – 2000 Update”, EPRI Final Report, December 2000

NESCAUM, “Status Report on NO x Control Technologies and Cost E ffectiveness for Utility Boilers”, June 1998.

Cichanowicz, J., “100 GW of SCR: Installation St atus and Implications of Operating Performance on Compliance Strategies”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003

McIlvaine, R., “SCR Operating Experience of Germ an Power Plant Owners as Applied to Challenging US High Sulfur Service”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003C-48 Process: Selective Non-Catalytic Reduction (SNCR)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Coal-fired boilers 607,748 25-50% 800-1,500 Commercial Cement Kilns 41,009 30-70% 200-1,000 Commercial Oil/NG boilers 32,910 30-60% 1,300-3,000 Commercial Wood/Biomass boilers 9,776 40-80% 900-2,200 Commercial Refinery Process Heaters 9,311 50-70% 1,200-2,700 Commercial Glass Melters 5,033 ~40% --- Commercial Process Description:

Post-combustion NO x controls include Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR). They are fundamentally similar, in that both use an ammonia-containing reagent to react with the NO x produced in the boiler, and convert it to harmless nitrogen and water, SNCR accomplishes this at higher temperatures (1700oF-2100oF ) in the upper furnace region of the boiler, while SCR operates at lower temperatures (about 600oF to 750°F) and hence needs a catalyst to produce the desired reaction between ammonia and NO x .
While this difference between the two technologies may seem minor, it yields significant difference in performance and costs. This is because in the case of SNCR, the re action occurs in a somewhat uncontrolled fashion (e.g., the existing upper furnace becom es the “reactor”). In practice, this means that SNCR has lower capital costs (no need for a reactor/cat alyst); higher operating costs (lower efficiency means that more reagent is needed to accomplish a given reduction in NO x ); and limited NO x reduction capability (typically 30%-40%, with some case s achieving reductions in the 50% range).

With SNCR, the reagent is introduced directly in to the upper furnace, within the temperature window above. Typical applications may include multiple inje ction nozzles at various elevations (temperature points). in the furnace to optimize the distribution of reagent as well as to allow for operation at various load points. NO x Reduction:

SNCR technology is typically capable of NO x reductions in the range of 25% to 80% depending on many design and operating characteristics of the specific application.

Cost Information:

Capital cots range from $10 to $20/kW for power generation boilers. Operating costs are driven primarily by the consumpt ion of the chemical reagent – usually urea for SNCR - which in turn is dependent upon the efficiency of the as well as the initial NO x level and the desired percent reduction. These are typically in the range of $500-$700/ton of NO
x . An additional consideration important in the overall operating costs is the potential contamination of fly ash by ammonia making it potentially unsalable. Development Status: Commercial SNCR is a fully commercial technology widely employ ed in various industries and applications. Ureab ased applications are the predominant approach, as urea seems to have several advantages over ammonia in large-scale applications.C-49 Process: Selective Non-Catalytic Reduction (SNCR) Practical Considerations: SNCR applications must be considered on a site –specific basis as several design and operating characteristics will affect the suitability of the technology. Some key issues include

• Available temperature window

• Size (cross-section/height) of the furnace for appr opriate distribution and mixing of the reagent

• Sulfur content of the fuel (SO 3 and NH 3 form ammonium salts whic h can have negative impacts on the downstream equipment)

• Operational profile of the unit (rapid swings in flows/temperatures often result in poor performance in terms of NO x reduction and ammonia slip)

Compatibility with other air pollution control technologies: SNCR applications are compatible with combustion NO x controls (LNBs, OFA, reburn, etc.) and can be used with other amine-based controls (e.g. SCR) in hybrid configurations. In theory, most of these technologies can be used together. However, NO x reductions are not necessarily additive, and more importantly, the “economics” of the combined technologies may or may not be cost-effective. Such analyses are highly site- and strategy-specific.

The application of SNCR with reburn has yielded sever al developments by different companies. Various approaches are available commercially. Essentially th ey all revolve around the ability to combine the injection the reburn fuel and the amin e reagent in the upper furnace region. NO x reductions are not additive but better than the individual technology. While these combined approaches have not gained extensive commercial deployment reductions of 60% -70% have been reported. Economic effectiveness needs to be properly addressed on an individual basis as both the cost of reagent and reburn fuel contribute to the overall cost analyses

Other variations of SNCR-based technology include the use of hydrocarbon injection to promote NH 3 reduction reactions, as well as reagent injection into a fuel rich zone of the OFA system. These variations while offered commercially are still under demonstration Secondary Environmental Impacts: SNCR has some of the same issues associated with S CR. The two most likely to warrant consideration are

• NH 3 slip (emissions and impacts on ash)

• Formation of nitrous oxide (N 2 O – a green house gas). This is mostly associated with urea, as opposed to ammonia, and may become a larger concern from the perspective of global climate issues

References: NESCAUM, “Status Report on NO x Control Technologies and Cost E ffectiveness for Utility Boilers”, June 1998.

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update, Final Report”, December 2000.

Himes, R., “A Fresh Look at SNCR”, EPRI/DOE /EPA Mega Symposium, Washington, May 2003

EPRI, “Sate of the Art Assessment of SNCR Technology”, September 1993.

EPRI, “SNCR Feasibility and Economic Evaluation Gu idelines for Fossil-Fired Utility Boilers”, May 1994C-50C-51 Process: Tempering (Water, air, steam injection)

Category NO x , TPY (WRAP 1996>100 TPY) %NO x reduction Cost, $/ton Status Turbines 25,278 ~50% 2,000-7,000 Commercial Refinery Process Heaters 9,311 --- --- Commercial Process Description:

Tempering is a combustion control using water, air, or steam to lower the combustion temperatures, which reduces thermal NO x formation. Water or steam, treated to quality levels comparable to boiler feedwater, is injected into the combustor and acts as a heat sink to lower flame temperatures. NO x Reduction:

Controlled NO x emission levels range form 25 to 42 ppmv for natural gas fuel and from 42 to 75 ppmv for distillate oil fuel.

Cost Information:

Capital costs for wet injection include a mixed bed demineralizer and reverse-osmosis water treatment system and an injection system. All costs are based on availability of the injection medium on site. Capital costs range from $388K for a 4,430 hp turbine ($89/hp) to $4,830K for a 216,000 hp turbine ($22/hp). For steam injection, capital costs ar e slightly higher than for water injection. Development Status:

Commercially available
Practical Considerations:

This technique is available for all new turbine models and can be retrofitted to most existing installations. The decision of which injection medium to use for NO x reduction depends on many factors including the availability of steam injection nozzles and controls from the turbine manufacturer, the availability and cost of steam at the site, and turbine performance a nd maintenance impacts. This decision is usually driven by site-specific environmental and economic factors. Compatibility with other air pollution control technologies:

None. Secondary Environmental Impacts:

None expected. References: Alternative Control Techniques Document: NO x Emissions from Stationary Gas Turbines. EPA Document No. EPA-453/R-93-007, January 1993.

U.S. Environmental Protection Agency. “A lternative Control Techniques Document – NO x Emissions form Stationary Reciprocating Internal Combustion Engines.” EPA-453/R-93-032, July, 1993.C-52 Process: Tempering (Water, air, steam injection) Poole, L., “Houston Galveston Area NO x Abatement Industries Perspective,” present at the Council of Industrial Boiler Owners, NO x Control XV Conference, Houston, TX, August 2002.

### APPENDIX D: PM Control Technology SummariesD-1 Process: Cyclones

Category PM, TPY (WRAP 1996 >100 TPY) %PM reduction Cost Status Mineral Processing 24,499 50 – 90% See below Commercial Petrochemical 10,836 50 – 90% See below Commercial Wood/Biomass boilers 5,718 50 – 90% See below Commercial Primary metal production 4,697 50 – 90% See below Commercial Pulp & Paper 4,476 50 – 90% See below Commercial Process Description:

Cyclones use centrifugal force to separate particulate fr om gas streams, and belong to the broader family of mechanical collectors, which use a variety of me chanical forces to collect particulate. A multiple cyclone is an array of a large number of small (several inch diameter) cyclones in parallel.

PM Reduction:

Multiple cyclones have overall mass removal effici encies of 70-90%. However, cyclone collection efficiencies fall off rapidly with particle size, so that control of fine particulate (PM-2.5) is limited. While collection efficiency is a function of the cyclone design and particle properties, cyclone removal efficiencies will be 90% or greater for 10 micron particles, dropping to perhaps 70% for 2.5 micron particles, and 50% for 1 micron particles. Addition of a second multiple cyclone in series with the first will allow for increased removal efficiency.

The efficiency of a cyclone increases with the gas fl ow rate through the cyclone. Cyclones are therefore most effective at high boilers loads, where flue g as flow rates are highest, with collection efficiency decreasing at lower loads. Cost Information:

The following values represent typical costs for several of these tec hnologies (these numbers reflect unit sizes ranging from utility-size units up to about 2,000,000 ACFM to smaller process down to about 10,000 ACFM).

• Capital - $1 - $5/ACFM

• O&M - NA Development Status:

Commercial.

Cyclones have been used extensively in various partic ulate collection applications over the years. In the past, industrial plants used mainly cyclones. Cycl ones are robust technologies that can deal with the cyclic operation and load changes. However, their e fficiency is moderate when compared with ESP or fabric filtration Practical Considerations:

Cyclones are best suited for applications of relativel y large particle sizes as their effectiveness on smaller particles is limited

Cyclones are less expensive than other PM contro ls and have no costs beyond the initial capital cost.D-2 Process: Cyclones



### Multiple cyclones have no moving parts, but do require regular cleaning to avoid plugging, and preventive maintenance to avoid leaks, which can disrupt flow patterns and thus lower collection efficiency. Compatibility with other air pollution control technologies:

Cyclones are compatible with other PM controls a nd may be desirable in selected applications to minimize PM loadings into downstream cont rols such as an ESP, FF or PM scrubber Secondary Environmental Impacts:

None expected.

References:

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.comD-3 Process: Electrostatic Precipitator (ESP)

Category PM, TPY (WRAP 1996 >100 TPY) %PM reduction Cost Status Coal-fired boilers 46,010 90%-99+% See below Commercial Wood/Biomass boilers 5,718 90%-99+% See below Commercial Oil/NG boilers 1,379 90%-99+% See below Commercial
Cement kilns 641 90%-99+% See below Commercial Process Description:

ESP’s operate on the principle of electrophoresis, by im parting a charge to the particulates and collecting them on opposed charges plates. Dry vs. wet refers to whether the gas is water cooled and saturated prior to entering the charged plate area, or is collected dry on the plates.

Electrostatic precipitators (ESPs), have been in u se for particulate control since the early 1920’s, use electrical fields to remove particulate from boiler flue gas.

In an electrostatic precipitator, an electric field is maintained between high-voltage discharge electrodes, typically wires or rigid frames, and grounded collecting electrodes, typically plates. A corona discharge from the discharge electrodes ionizes the gas passing through the precipita tor, and gas ions subsequently ionize particulates. The electric fields impart elect rostatic forces to the negatively charged particles, “driving” them to the collecting electrodes. Particulat es are collected from the electrode plates either by mechanical rapping (Dry ESP) or by using a wate r spray to remove this particulate. (Wet ESP).

In a typical electrostatic precipitator, collecting plat es are arranged parallel to the gas flow, normally 9-18 inches apart, with discharge electrodes between them. Most precipitators have 3-5 independent electrical sections, i.e., sets of discharge and collecting el ectrodes with independent power supplies called Transformer/Rectifier (TR) sets, in series. Each independent section removes a fraction of the particulate in the gas stream. This arrangement allows the use of lower power (higher voltages, but lower current) in the first sections of the precipitator, where there is more particulate to be removed. Higher power is needed in the later sections, to collect the smaller particles.

A typical wet ESP configuration uses cylindrical collec ting electrodes, with discharge electrodes located in the centers of the cylinders. Wet ESPs are useful in obtaining low opacities through the removal of acid gases and mists in addition to fine particulate. In addition, these devices have no rapping re-entrainment losses, and no back corona.
PM Reduction:

Many factors determine electrostatic precipitator re moval efficiency. ESP size is an important one. Size determines residence time (longer particle r esidence times help collection efficiency) Precipitator size is related to and usually referred to as the specific collection area (SCA), the ratio of the surface area of the collection electrodes to the gas flow. Higher collection areas lead to better removal efficiencies. Collection areas normally are in the range of 200-800 ft2/1000 acfm. In order to achieve collection efficiencies of 99.5%, specific collection areas of 350-400 ft2/1000 acfm are typically used.

Electrostatic precipitator collection efficiencies can exceed 99.9%, and efficiencies in excess of 99.5% are common. Precipitators with high overall collection efficiencies will have high collection efficiencies for particles of all sizes. Good control of PM-10 a nd PM-2.5 can be achieved with well-designed and operated electrostatic precipitators.D-4 Process: Electrostatic Precipitator (ESP)

Precipitator collection efficiencies decreases for very small particles (less than 1 micron). The reason for lower efficiency for submicron particles is that bot h particle charge and the resistance of the gas to particle motion increase with particle size. As particles get smaller, the particle charge is lower, while the resistance to particle motion is higher resulting in poor collection. In practice this effect means that an ESP precipitator with a 99.9% overall mass collection e fficiency may only collect over 90% of submicron particles, and over 97-98% of the 0 to 5 micron particles.

Some older precipitators on utility boilers are small, with SCAs below 200 ft2/1000 acfm and correspondingly short treatment times. Cost Information:

The following values represent typical costs for several of these tec hnologies (these numbers reflect unit sizes ranging from utility-size units up to about 2,000,000 ACFM to smaller process down to about 10,000 ACFM))

• Capital: $15 - $40/ACFM

• Fixed O&M: Dry ESP’s - $0.25 - $0.65/yr-ACFM Wet ESP’s - $0.15- $0.50/yr-ACFM

• Variable O&M: Dry ESP’s - $0.45 - $0.60/yr-ACFM Wet ESP’s - $0.25 - $0.50/yr-ACFM Development Status:

Commercial

ESP’s have been in use for over 75 years and are a widely recognized technology option for PM control

Practical Considerations:

Maximizing electric field strength will maximize precipitator collection efficiency.

Other actors limiting precipitator performance include fl ow non-uniformity and particle re-entrainment. Uniform flow distribution helps ensure that there are no high gas velocity, short treatment time paths through the precipitator.

Re-entrainment of collected particles may occu r during rapping. Proper rapper design and timing will minimize rapper re-entrainment. Maintenance of a ppropriate hopper ash levels and of flow uniformity will minimize re-entrainment of ash from the hoppers.

A major consideration of ESP collection efficiency is the electrical resistivity of the particles to be collected. Particles with resistivities in the range of 10 7 -10 10 ohm-cm are more easily collected with ESPs: these particles are easy to charge, and loose their charge slowly once deposited on a collecting electrode. Particles with low resistivities (less than 10 7 ohm-cm), on the other hand, loose their charge to a collecting electrode rapidly and tend not to adhere to th e electrode, causing high re-entrainment losses. (Carbon black is an example of a low resistivity material).

Particles with high resistivity (greater than 10 10 ohm-cm) can be difficult to remove with a precipitator: such particles are not easily charged, and thus are not easily collected. High-resistivity particles also form ash layers with very high voltage gradients on the collecting electrodes. Electrical breakdowns in these ash layers lead to injection of positively charged i ons into the space between the discharge and collectingD-5 Process: Electrostatic Precipitator (ESP) electrodes ("back corona"), thus reducing the charge on particles in this space and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high resistivity, and thus is difficult to collect. Flue gas treatment options exist to address both high and low resistivity problems and include the injection of ammonia, SO 3 and other proprietary additives. Compatibility with other air pollution control technologies:

ESP’s are compatible with other PM controls and may be desirable in selected applications to minimize PM loadings into downstream controls such as a FF or PM scrubber Secondary Environmental Impacts:

None expected.

References:

EPRI, “Economic Evaluation of Particulate Cont rol Technologies”, Final Report, September 1992.

Staehle, R., “The Past, Present and Future of Wet ESPs in Power plant Applications”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003.

IEA Coal Research, “Particulate control Handbook”, Final report, July 1997.

IEA Coal Research, “Prevention of Particul ate Emissions”, Final report, December 2000.

ICAC, “ESPs vs. Fabric Filters: A Symposium and Debate”, March 1994.

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.comD-6 Process: Fabric Filter

Category PM, TPY (WRAP 1996 >100 TPY) %PM reduction Cost, Status Coal-fired boilers 46,010 99+% See below Commercial Mineral Processing 24,499 99+% See below Commercial Wood/Biomass boilers 5,718 99+% See below Commercial Fugitive 5,631 99+% See below Commercial Oil/NG boilers 1,379 99+% See below Commercial
Cement kilns 641 99+% See below Commercial Process Description:

Fabric filter (FF) collectors (also referred to as bag houses) are the industrial equivalent of very large vacuum cleaners: by passing flue gas through a tightly woven fabric, particulate in the flue gas will be collected on the fabric by sieving and other mechan isms. The dust cake which forms on the filter from the collected particulate can contribute significan tly to the overall collection efficiency.

FF types are usually defined by the type of bag clean ing utilized. Major types include: (1) the “reverseair” baghouse, where the flue gas flows upward th rough the insides of vertical bags, which open downward. The fly ash thus collects on the insides of the bags, and the gas flow keeps the bags inflated. To clean the bags, a compartment of the FF is taken o ff-line, and the gas flow is reversed. This causes the bags to collapse, and collected dust to fall from the bags into hoppers. (Shaking or other method may be necessary to dislodge the dust from the bags.); and (2) th e pulse-jet fabric filter, where the dirty gas flows from the outside of the bags inward, and the bags are mounted on cages to keep them from collapsing. Dust that collects on the outsides of the bags is re moved by a reverse pulse of high-pressure air. This cleaning does not require isolation of the bags from th e flue gas flow, and thus may be done on-line.

PM Reduction: FF’s are capable of 99.9% removal efficiencies. In a ddition removal efficiency is relatively level across the particle size range, making FF’s good alternatives for very small particle sizes

. Key performance factors include the fabric of th e bag, the cleaning frequency and methods, and the particulate characteristics. Fabrics can be chosen for different applications, and some fabrics are specialty-coated for enhanced rem oval of submicron particulate.

Cleaning intensity and frequency are also important variables in determining removal efficiency. Because the dust cake can provide a significant fraction of the fine particulate removal capability of a fabric, cleaning which is too frequent or too intense will lo wer the removal efficiency. On the other hand, if removal is too infrequent or too ineffective, then pressure drop will increase rapidly and impact overall operation.D-7 Process: Fabric Filter Cost Information:

FF’s have been used extensively for many years in different industries. The power generation sector while predominantly dominated by ESP’s has star ted to utilize FF’s in the last 20 years.

• Capital: Reverse Air Fabric Filter - $17 - $40/ACFM Pulse Jet Fabric Filter - $12 - $40/ACFM

• Fixed O&M: Reverse Air Fabric Filter - $0.35 - $0.75/yr-ACFM Pulse Jet Fabric Filter - $0.50 - $0.90/yr-ACFM

• Variable O&M: Reverse Air Fabric Filter - $0.70 - $0.80/yr-ACFM Pulse Jet Fabric Filter - $.90 - $1.1/yr-ACFM

Development Status:

Commercial.

FF’s have been used extensively for many years in different industries. The power generation sector while predominantly dominated by ESP’s has star ted to utilize FF’s in the last 20 years.

Practical Considerations:

FF size is determined by the choice of air-to-cloth ratio (A/C), or the ratio of air flow to cloth area, typically expressed in feet per minute (cubic feet per minute of flow divided by square feet of fabric area). The selection of air-to-cloth ratio depends on th e particulate loading and characteristics, and the cleaning method used. A high particulate loadings will re quire the use of a larger FF (lower A/C) in order to avoid forming too heavy a dust cake, resulting in an excessive pressure drop

Pulse-jet FF’s are smaller (higher A/C) than rever se-air FFs due to the higher cleaning intensity and resulting bags being cleaner Compatibility with other air pollution control technologies:

FF’s are compatible with other PM controls. FF’s ar e also choices for applications downstream of dry SO2 controls (e.g. spray dryers) as well as in comb ination with sorbent injection techniques for SO2 and/or Hg control

Adding a FF downstream from an existing electrostatic precipitator is a strategy gaining some acceptance in the power industry. Because the ESP removes the bulk of the particulate, the baghouse can be relatively small, and thus less expensive. One commercia l approach to this is the installation of a small pulse-jet fabric filter downstream of an ESP, known as a Compact Hybrid Particulate Collector (COHPAC). Physically, it may be separate from the preci pitator, or even fully integrated into the last field of the existing ESP, further reduci ng the over cost and space requirements. Secondary Environmental Impacts:

As mentioned above FF’s can represent a complement ary option to sorbent injection technologies where they enhance the contact (reaction) times between the sorbent and the flue gas contaminant of interest. This results in enhanced collection efficiency for the pollutant (e.g. mercury), as well as reduced quantities of sorbent neededD-8 Process: Fabric Filter References:

EPRI, “Economic Evaluation of Particulate Cont rol Technologies”, Final Report, September 1992.

Staehle, R., “Particulate Control Options for Dr y FGD Systems”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003.

IEA Coal Research, “Particulate control Handbook”, Final report, July 1997.

IEA Coal Research, “Prevention of Particul ate Emissions”, Final report, December 2000.

ICAC, “ESPs vs. Fabric Filters: A Symposium and Debate”, March 1994.

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.comD-9 Process: PM Scrubber

Category PM, TPY (WRAP 1996 >100 TPY) %PM reduction Cost, Status Mineral Processing 24,499 50%-99+% See below Commercial Petrochemical 10,836 50%-99+% See below Commercial Wood/Biomass boilers 5,718 50%-99+% See below Commercial Primary Metal production 4,476 50%-99+% See below Commercial Pulp & Paper 4,476 50%-99+% See below Commercial Process Description:



### Scrubbers work on the principle of rapid mixing and impingement of the particulate with the liquid droplets and subsequent removal with th e liquid waste. For particulate controls the “venturi scrubber” is an effective technology w hose performance is directly related to the pressure loss across the ventur i section of the scrubber.

Venturi scrubbers are one type of the more commonly used “scrubbers” for particulate collection. As the name implies, the scrubbing liquid and flue gases a ccelerate through a converg ing section into a narrow throat. In the throat, very high gas velocity shears the scrubbing liquid into many very fine droplets, which collect particles through numerous “collisions”.

PM Reduction:

Scrubbers have varying PM reduction capabilities b ased on deign operating co nditions and particle characteristics. Performance can range 50% for the sma ll size fraction (< 2microns) to over 99% for the larger sizes.

Higher collecting efficiencies and a wider range of par ticulate sizes, require higher operating pressures. . High-energy scrubbers refer to designs operating at pr essure drop of 50-70 inches of water. Of course, higher pressure translates to higher energy consumption. Cost Information:

The following values represent typical costs for several of these tec hnologies (these numbers reflect unit sizes ranging from utility-size units up to about 2,000,000 ACFM to smaller process down to about 10,000 ACFM)

• Capital: Venturi Scrubber - $5 - $20/ACFM

• Fixed O&M: Venturi Scrubber - $0.25 - $0.65/yr-ACFM

• Variable O&M: Venturi Scrubber - $1.2 - $1.8/yr-ACFM Development Status:

Commercial

Wet scrubbers are widely used in various industries. One advantage of scrubbers is their ability to treat wet gases which are not conducive to other technologies such as dry ESPs and FFs. Practical Considerations:



### For applications where variation in flow requi re throat velocity compensation to maintain specified scrubbing efficiencies, automatic and ma nually variable throat designs are available.D-10 Process: PM Scrubber 

### The automatic throat is used where flow conditions vary widely and frequent adjustments are required. When occasional variations occur, a manua lly controlled throat is generally sufficient.

Compatibility with other air pollution control technologies:

Scrubbers are compatible with othe r PM controls. However, dry ESP’s and FF’s would not be deployed downstream of a scrubber without prior reheating of the flue gas which would make such application economically questionable in general Secondary Environmental Impacts:

Liquid waste disposal requires consideration on a case-by-case basis.

Since scrubbers have the capability to reduce acid gases, applications where this is important must be considered. References:

IEA Coal Research, “Particulate control Handbook”, Final report, July 1997.

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.comAppendix A-8 – SO2 Milestones/Backstop Arizona Regional Haze SIP 

## APPENDIX A-8. SO2 MILESTONES/BACKSTOP

This appendix contains work products a nd references relied u pon by Arizona in the development of Chapter 8 of the Regional Haze SIP.Appendix A-8 – SO2 Milestones/Backstop Arizona Regional Haze SIP 

## Appendix A-8a. WRAP Market Tr ading Forum Non-Utility Sector Allocation Final Report from the Allocations Working Group (November 2002)

# PECHAN

5528-B Hempstead Way Springfield, VA 22151

703-813-6700 telephone 703-813 -6729 f

acsimi le

3622 Lyckan Parkway Suite 2002 Durham, NC 27707
919-493-3144 telephone 919-493 -3182 f

acsimi le

P.O. Box 1575 Shingle Springs, CA 95682
530-672-0441 telephone 530-672 -0504 f

acsimi le 

## M ARKET 

## T RADING 

## F ORUM 

## N ON 

## -U TILITY 

## S ECTOR 

## A LLOC ATI ON



## F INAL 

## R EPORT

FROM THE 

## A LLOCAT IONS 

## W ORKING 

## G ROUP

Prepared

for:

Western Governors’ Association 1515 Cleveland Place Denver, CO 80202
Prepared by:

E.H. Pechan & Associates, Inc. 5528-B Hempstead Way Springfield, VA 22151

November 2002

WGA Contract No. 30204-48 Pechan Rpt. No. 02.11.001/9422.000iii 

## CONTE NTS

Page

TABLES

......................................................... ........... v

ACRONYMS AND A BBREVI ATI ONS

.......................................... vii

EXECUTI VE SUMMARY

..................................................... ix

CHAPTER I INT RODUCTI ON

......................................................... . . I-1 A. ANALYS IS METHODS

............................................... I-1

CH AP TE R II PETROLEUM REF INI NG

................................................... II-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............. II-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

....................... II-1 1. Sulfu r Re cove ry U nits

........................................... II-1 2. Fu el G as C om bus tion U nits

...................................... II-2 3. Cata lytic Crackers

.............................................. II-3 4. Flares

........................................................ II-3 C. FLOOR ALLOCATION RESULTS

.................................... II-3 D. COMPARI SON WI TH HIS TORI CAL EMI SSI ONS

...................... II- 10 E. EXAMPLE CAL CULATI ON

......................................... II- 10 1. Sulfu r Re cove ry U nit

........................................... II- 10 2. Fuel Gas Com bustion

.......................................... II- 10 3. Cata lytic Crackers

............................................. II- 12 4. Flares

....................................................... II- 12

CH AP TE R III LIME MANUFA CTURI NG

.................................................. III-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............. III-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

....................... III-1

CH AP TE R IV INDUS TRI AL BOI LERS AND COGENERATORS

............................... IV -1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............. IV -1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

....................... IV -1 1. Co al F ired U nits

................................................ IV -2 2. Oil F ired U nits

................................................. IV -2 C. FLOOR ALLOCATION RESULTS

.................................... IV -3 D. COMPARI SON WI TH HIS TORI CAL EMI SSI ONS

....................... IV -3 E. EXAMPLE US E OF CAPACI TY UTI LIZ ATI ON DATA FOR F LOOR ALLOCATI ON ESTI MATES

......................................... IV -3

CHAPTER V PULP AND P APER I NDUSTRY

............................................... V-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

.............. V-1 1. Recovery Furnaces

............................................... V-1 2. Lime Kil ns

..................................................... V-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

........................ V-2 1. Recovery Furnaces

............................................... V-2 2. Lime Kil ns

..................................................... V-2 C. FLOOR ALLOCATION RESULTS

..................................... V-2 D. COMPARI SON WI TH HIS TORI CAL EMI SSI ONS

........................ V-4iv 

## CONTE NTS (conti nued)

Page

CHAPTER VI CEMENT MANUFACTURI NG

............................................... VI -1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............. VI -1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

....................... VI -1 C. FLOOR ALLOCATION RESULTS

.................................... VI -1 D. COMPARI SON WI TH HIS TORI CAL EMI SSI ONS

....................... VI -4

CH AP TE R V II NATURAL GAS PROCESSI NG PLANTS

..................................... VI I-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............ VI I-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

...................... VI I-1 C. FLOOR ALLOCATION RESULTS

................................... VI I-2 1. Ge nera l Plan ts

................................................ VI I-2 2. Spe cific Exa m ple

.............................................. VI I-3 D. COMPARI SON WI TH HIS TORI CAL EMI SSI ONS

...................... VI I-3

CH AP TE R V III ELEMENTAL P HOSPHORUS PRODUCTI ON

............................... VI II-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

........... VI II-1 B. FLOOR ALL OCATI ON ESTI MATION P ROCEDURES

................. VI II-1

CH AP TE R IX GLASS MANUFACTURI NG

................................................. IX-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............. IX-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

....................... IX-2

CHAPTER X COPPER S MELTERS

....................................................... X-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

.............. X-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

........................ X-1 C. COMPARI SON WI TH HIS TORI CAL EMI SSI ONS

........................ X-2

CHAPTER XI ALUMINUM PROD UCTI ON

................................................ XI-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............. XI-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

....................... XI-2

CH AP TE R X II SULFURIC ACI D PLANTS

................................................. XII -1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

............ XII -1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

...................... XII -2

CH AP TE R X III METALLURGI C COKE PRODUCT ION

..................................... XII I-1 A. SECTOR DESCR IPTION AND SIGNIFICANT SO 2 SOURCES

........... XII I-1 1. By Prod uct Coke Ovens

........................................ XII I-1 2. Rotary Calcine rs

.............................................. XII I-1 B. FLOOR ALL OCATI ON ESTI MATION METHODS

..................... XII I-2 C. COMPARI SON WI TH HIS TORI CAL EMI SSI ONS

..................... XII I-3

CH AP TE R X IV FLOOR ALL OCATI ON SUMMARY

.......................................... XIV -1v 

## TA BLES

Page

I-1 Methodology for t he Calculati on of the Floor Allocat ions for Non-Utili ty Sources I-3 II-1 Sulf

ur Plant s - Required Minimum SO 2 Em ission Re duction E fficiency

...... II-2 II-2 Petroleum Refining Floor Allocat ion Calculat ion

......................... II-4 II-3 Petro leum Refi neri es – Hist ori cal Emissio ns – 1990 t o 2000

.............. II- 11 III-1 Emiss ion Fa ct ors fo r Li me Manufac tur ing

.............................. III-3 III-2 Lime Manufactur ing - Histo ric al Emissi ons - 1990 to 2000

................. III-4 IV -1 Assumed Level of Control for SO 2 Floor Alloc ation

....................... IV -2 IV -2 Facil it y SO 2 Floor A llocation E stimation for ICI Bo ilers

................... IV -5 IV -3 Comparison o f SO 2 Floor A llocation w ith Historical E mission s for ICI Bo ilers

. IV -7 IV -4 Exam ple Use of Capacit y Utili zation Data for Floor Alloc ation Esti mates

.... IV -9 V-1 Facil it y SO 2 Floor Alloc ation Esti mation for Pulp and Paper Facil iti es

Based on Unit Capacity Values

........................................ V-3 V-2 Facil it y SO 2 Floor Alloc ation Esti mation for Pulp and Paper Facil iti es

Based on Fuel Throug hput

............................................ V-3 V-3 Pulp and Paper - His tor ical Emissio ns - 19 90 to 2000

...................... V-5 VI -1 Floo r Al loc ati ons

................................................... VI -2 VI -2 Cement Manufactur ing - Histo ric al Emissi ons - 1990 to 2000

.............. VI -3 VI -3 Exam ple Calculat ion

................................................ VI -4 VI I-1 Sulf

ur Plant s - Required Minimum SO 2 Em ission Re duction E fficiency

..... VI I-2 VI I-2 Pos sible F loor - N atura l Ga s Pro cessin g U nits

.......................... VI I-4 VI I-3 Oil and Gas Pr oduct ion - Histo ric al Emissi ons - 1990 to 2000

............. VI I-6 VI II-1 Elemental Phosphorus Product ion - Histo ric al Emissi ons - 1990 to 2000

... VI II-2 IX-1 Glass Manufac turi ng - His tor ical Emissio ns - 19 90 to 2000

................ IX-3 X-1 Copper Smelt er SO 2 Em issi on Project ions (t py)

........................... X-2 X-2 Recent His tor ical Copper Smelt er SO 2 Emiss ions

......................... X-3 XI-1 Aluminum Pl ant Dat a Used t o Est imat e Flo or Al loc ati ons

................. XI-4 XI-2 Aluminum Smelting - Histo ric al Emissi ons - 1990 to 2000

................. XI-5 XII -1 Sulfu ric Acid Pla nts

................................................ XII -3 XII I-1 Histo ric al SO 2 Em issi on s a t P 4 P rod uc tion , Ro ck S pri ng s, W Y

............ XII I-2 XII I-2 Coking Plant - His tor ical Emissio ns - 19 90 to 2000

..................... XII I-3 XIV -1 Stat e/Se cto r Summary of SO 2 Floor A llocations (tons pe r year)

............ XIV -2 XIV -2 Facil it y-Level SO 2 Floor Alloc ati ons - Comparison wi th Year 2 000

SO 2 Em issions (tons pe r year)

........................................ XIV -3vivii 

## A CRONYMS A ND A BBREVI A TI ONS

BACT Best Available Contr ol Technology BART Best Available Retr ofit Technology BLS Black liquor soli ds CAA Clea n A ir Act CWPB cente r-wo rked preb ake cells DCE Direct contact evaporator dscf dry st andard cubic f oot ESPs electrostatic precipitators FCCU fluid ca talytic cra cking un it GCVTC Grand Can yon Visibil ity Transpor t Comm issi on H 2 S hydrogen sulfi de HSS horizon tal stud Sod erberg ICI indust rial , c ommercial , and i nsti tut ional kg kil ogram LAER Lowest Achievable Emission Reduction lbs/M M Btu pou nds per m illion B ritish th erm al un its Mg megagram MTF Market Tradi ng For um NO

x oxides of nitrogen NSPS New Sou rce Perf ormance Standards
ppm parts per million
pp mv pa r t s p er mi l l i on vo l ume PTE poten tial to em it RE CL AIM Regional Clean Air Incenti ves Market SCC Source Classi fic ation Code SIC Standard Indust rial Classif icat ion SIP Stat e Implementat ion Plan SO 2 sulfur dioxide SRU Sulfu r Re cove ry U nit SWPB side-w orke d pre bak e cells tpy tons p er year VSS vertical stud So derberg WGA Western Governors’ Assoc iati on WRAP W estern Re gion al A ir Pa rtners hipviiiix 

## EXECUTI VE SUMMA RY

Th is stud y w as pe rform ed for a W orkin g G roup of the W estern Re gion al A ir Part ners hips ’ ( WRAP) Market Tradi ng For um. I t pr ovi des a cur rent , b est est imat e of the floor allocation for n on-utility sources in the region that w ould b e establish ed if western Stat es and t ribe s adopt a regi onal, backst op tr ading pr ogram for sulf ur di oxide (SO 2 ) to meet the r equir ements of Sect ion 309 of

the r egional haze rul e. The majo r SO 2 emit ti ng

non- uti li ty s ourc e cat egor ies eval uate d in t his st udy i ncl ude t he f oll owing: pet rol eum refi neries, lime manufacturing, industr ial boi lers and c o-generat ors, pulp and paper manufac tur ing, cement manufac tur ing, natur al g as pr oce ssi ng and o il and gas pro duct ion, elem enta l pho sph orus prod uction , glass m anu facturin g, alu m inu m sm elters, su lfuric acid plants, and coke production. Of these industry sectors, phosphoru s, aluminum smelters, sulfuric acid plan ts, and coke production plants w ere no t considered in the origin al source categor ies f

or the Market Trading Forum. The fl oor contr ol tec hnology (or emiss ion rate or SO 2 control eff

ecti veness) was deter mined by evaluating the emissi ons perfor mance of other sources in that source category in the western States. The floor is defi ned to be best available control technology (BAC T), best available retr ofit t echnology (BA RT), or lowest achievable emissi on rate ( LAE R) for exist ing sources . For some sources , EPA has not deter mined what thes e leve ls of emissi ons are . SO 2 floor alloc ations were computed f or each of about 200 majo r non- util it y sourc es in t he wester n Stat es, where major is d efi ned as tho se so urce s em itting gre ate r tha n 1 00 ton s pe r ye ar (tp y).

While this analys is uses pl ant and process -level infor mation to est imate fl oor all ocat ions, if

the bac ksto p tr ading pr ogram is tr igger ed, SO 2 all owance s unde r t he tr adi ng progr am will be al loc ated by the par ti cip ati ng tr anspor t r egion St ates and Tribe s at t hat time. This s tudy is onl y an approximation of how the all ocati ons might be made based upon the limited i nformation that we have today. It is expec ted that the States and Tribes would be able to obtai n more detailed i nformation about cur rent emissi ons and control s for these non -utility sou rces th an h as b een ava ilable for the curren t project.

The floor al locat ion analysis has been performed separat ely for each of t he 12 ma jor non-util ity s ource cat egories i n the west. The text below summ arizes t he key findings for each source c ategory.

To simpli fy t he analys is, it was dete rmined t hat Cali for nia SO 2 sources ar e already highl y co ntr oll ed. The Cali for nia f loo r al loc ati on of

27, 335 t py i s bas ed on t he opt -i n/o ut 2018 SO 2 all ocat ion t hat ha s bee n est imat ed pr evi ousl y by t he WRAP Market Tr adi ng Fo r um.

Pe tro leu m Re fini ng : There are t en pet rol eum ref iner ies outs ide Cali for nia i n the WR AP transport r egion. Data were rec eived fr om all of t hese refi neries f or the all ocati on proc ess. These f

loor all ocat ions wer e computed for each of the f our major SO 2 emit ti ng process es at ref

ineries : sul fur pl ants, flui dized cat alyti c crac king units ( FCC Us), f uel combusti on units , and f lare s. The SO 2 floor alloc ation f or these t en refi neries i s 11,418 tpy, or about 5,400 tpy less than historic emissions during 199 6 to 2000. This is one of the best characterized source categories.

Ce m en t M an ufa ctu rin g: The contr ol t echnol ogy analy ses f or c ement kil ns showed t hat ther e was no demonstr ated SO 2 cont rol tec hnique at wester n Stat e sourc es t hat co uld be appli ed to r educe SO 2 acro ss t he sourc e popul ati on. Ther e are wid ely var ying SO 2 emi ss io ns ra te s f

ro m th es e ki ln s, and th e p ro ce ss it se lf re move s s ul fu r f

ro m th e of

f gas

. As

a re su lt, th is se cto r’s flo or a llo cat ion of 7 ,76 1 tp y w as ba sed on rec en t hi sto ric e m issi on s. Th e ana lysis for lim e m anu facturin g reach ed th e sam e conclu sion a s that for cem ent. The lime manufacturing f loor al locat ion is 2, 103 tpy.x

Bo ilers a nd Co -gen era tor s: The fl oor f or boi ler s and co -gener ator s at i ndustr ial fac il it ies was est imated by apply ing t he equival ent of 85 perc ent SO 2 contro l to coa l and oilfir ed sources not already at, or near, this c ontrol l evel. Average capacit y fact ors were used to estim ate b oiler u tilization for estim ating the floo r with a 5 p ercen t grow th m argin . This

ass umpti on is cons is tent wit h that used in t he ut il it y boi ler fl oor all ocat ions . S ome nonutil ity boi lers ar e operati ng at low util izati on rates. The industri al boil er and cogenerator floor alloc ation is 7,910 tpy.

Pulp and Paper Industr y: Recover y fur naces and li me kilns a re t he SO 2 sour ces at t he Kraft pulp mills i n the west. Most of these mill s are in Oregon. Floor all ocati ons for
recovery furnaces and l ime kilns are based on st andard U.S. Environmental Prot ecti on Agency ( EPA) emissi on fac tor s and 100 per cent capac it y uti li zati on (or rec ent annual throu ghp ut, if capa city estim ates w ere n ot av ailab le). Th e pu lp an d pa per floo r alloca tion is 7,184 tpy.

Natur al Gas Pr oce ss ing Pla nts and Oil

and Gas Produc ti on: SO 2 emissions f rom natur al g as pr oce ssi ng pl ants res ult fr om combust ion o f s our g ases . I t was dec ide d th at t he

cur re nt Ne w Sour ce Per fo rmanc e St anda rd (NS PS) woul d se rv e as the fl oor

. The NSPS
req uire s a v aria ble sulfu r rem ova l efficie ncy ba sed on the hy dro gen sulfi de (H 2 S) cont ent of the a cid ga s an d the am oun t of sulfu r in the gas. If a fa cility ha d curre nt con trol leve ls highe r than th e assu me d floor, the actua l averag e em issions ove r the past thre e yea rs were used to e st imat e the fl oor . S inc e emis si ons f rom f lar ing o per ati ons bo th i n the pla nt and the well f

ield ar e not amenable to control , f loor emissi ons are assumed to be the average of the e m ission s in th ree re cent y ears. D ata a vaila bility w as a significa nt issu e in determ ining the floor allocations for som e gas pla nts. The floor allocation for this sou rce categor y is 28, 884 tpy.

Ele menta l Pho spho rus Produc ti on: One of the t wo U.S. ele mental phos phor us producti on facil iti es is i n Idaho. Because of t he uniqueness of thi s faci lit y, no fl oor contr ol tec hnology was i denti fi ed. The fl oor al loc ati on is s et at year 2000 S O 2 em issions, wh ich were 15,861 tpy. It i s expect ed that t he State of Idaho will per form a more detailed evaluation of

this f acil ity dur ing preparat ion of i ts reg ional haze Stat e Implementation Pla n (S IP).

Glass Manufactur ing: The major so urce o f SO 2 emiss ions in t he gl ass indu st ry i s t he glass melti ng operation. There are only two act ive glass manu fact uring fac ili ties in the 8 non-Cali for nia WRAP States. With a la ck of inf ormati on about SO 2 contro l techn ique s in
prac ti ce, the f

loor all ocat ion f

or gl ass manufac turi ng plant s was set acco rdi ng to hi sto ric al SO 2 emissions. The glass manufacturing f loor al locat ion is 368 t py.
Cop per Sm elters: Be cau se of th e un ique nes s of the existin g cop per sm elters, retro fit techno logy an alysis m ust be pe rformed on a sm elter-by-sme lter basis. A dou ble conta ct acid p lant is co nside red th e ap prop riate re trofit contro l equ ipm ent. A ll coppe r sm elters in the wes ter n Sta tes are c urr entl y equi pped wit h doubl e co ntac t ac id p lant s. The cur rent year SO 2 alloca tion for the six copp er sm elters in the 9 -State re gion is 86,0 00 to ns. T his all ocat ion i s red uced t o 78,00 0 tons by 2013 and i s the s ame in 2018.

Alumi num Produc ti on: There are only 2 pri mary aluminum plants i n the study regi on and both ar e loc ated i n Oregon. The pri mary SO 2 sour ce i n alumi num prod uct ion i s t he sulfur in the coke, and the coal t ar pit ch binder used t o produce the anodes. The floor cont rol tec hnolo gy f

or al uminum smelt ers was det ermi ned by eval uati ng th e emis si ons perf ormance at the t wo Oregon fac il it ies. One faci li ty use s a wet s crubbe r t o achi eve a 70
perc ent SO 2 emissi on reduc ti on. Ther efor e, a wet scr ubber wit h a 70 perc ent SO 2 reducti on was select ed as the fl oor tec hnology for al uminum smelters. The aluminum smelter f loor alloc ation is 2,076 tpy.

Sulfuric Acid P lants: The only sign ificant source of air em issions from a conta ct sulfu ric acid p lant is th e tail ga s leav ing th e fina l abso rbing tow er. Th is gas conta ins sm all amounts of

SO 2 and eve n sm aller a m oun ts of sulfu r trioxide , sulfuric v apo r, and sulfu ricxi

acid m ist. Bas ed o n th e info rm ation ava ilable for the 4 su lfuric acid plan ts in th e w est, it was d ec id ed t hat the fl oor al lo cat io n sho uld be e st imat ed b y ap pl yi ng t he NSPS requirements t o each sulf uric ac id plant . Achievi ng this st andard requires a conversi on eff ici ency of

99.7 p erc ent i n an uncontr oll ed plant , or the equi valent SO 2 coll ecti on mechanism in a c ontr oll ed fac il it y. However , r ecent hist ori cal SO 2 emissions for these fac il it ies were l ower t han the NSPS emis si on ra te t imes c apac it y est imat ed val ues, so t he sulf uric aci d plant fl oor was es ti mated usi ng thes e hist ori cal SO 2 emiss ion v alue s. The result ing fl oor all ocati on for t hese sulfur ic aci d plants i s 5,386 tp y.

Metal lur

gi c Coke Produc ti on: SO 2 em ission s from coke ove n op eratio ns pr ima rily resu lt from combustion of the byproduct coal gas i n the oven. There were three c oke producti on fac il it ies o perat ing i n the west duri ng the 1990s . Coke pr oduct ion has r ecent ly c eased at two of the se facilities . The only facility tha t contin ues to ope rate is a rotary calcine r in Wyom ing. Because of the uniqueness of t his operat ion, t he floor alloc ation is based on

rec ent hi sto ric SO 2 emissions, and is 631 tpy.

Th ere are tw o b en ch m ark s th at c an be us ed to p ut t he floo r al loc ati on s in pe rsp ect ive

. One is year 2000 hist ori c emiss ions and the ot her i s the no n-ut il it y SO 2 emissions forecast for 2018. The f

loor all ocat ion es ti mate in t his r eport is abo ut 2, 500 tons higher than year 200 0 his torical e m ission s. Ho we ver, this com pariso n of th e resp ective e m ission totals is skewed by t he fac t t hat year 2000 copp er smel ter emissi on were about one-hal f of the 78 thousand ton allocation for t his sector. Wh en copper sm elters are removed from the totals, the floo r al loc ati on is a bo ut 4 5 th ou sa nd ton s lo w er t ha n y ea r 20 00 em issi on s. A compari son of

the f loor all ocat ion wit h the SO 2 emissions i n the 2018 opt-i n/out emissi on alloc ations s hows that the fl oor all ocati on is approxi mately the same.xiiI-1 

## CHA PTER I IN TRODUCT IO N

This rep ort desc ri bes a n anal ysi s t hat was pre pare d f or a Wor king Group o f t he Weste rn Regi onal Air Part ners hip’ s ( WRAP) Market Tradi ng For um (MTF). It pro vid es t he

curre nt be st estim ate o f the floo r alloca tion for non -utility sou rces in the re gion that w ould be establi shed if western Stat es and tri bes adopt a regi onal, backs top tr ading program for sulf ur di oxide (SO 2 ) to m eet th e req uirem ents o f Section 309 of the regio nal h aze rule. N ote that thi s does not es tabl ish f inal all ocat ions f

or so urces in t he regi on. Eac h Stat e and tr ibe will d eterm ine th e ap prop riate floo r leve l for sou rces w ithin th eir jurisd iction, an d w ill inclu de th is inform ation in the ir State or triba l imp lem enta tion p lan. T he p rogra m is voluntary f

or western St ates and tr ibes. Informati on is provi ded to assi st el igibl e States and tr ibes evaluat e the i mpacts of t he progr am, but de cis ions t o part ici pate i n the pr ogram wil l be made by ea ch s epar ate jur is dic ti on.

The dist ribut ion of

regi onal SO 2 allowances to ex ist ing sources in the nine Comm issi on Tr ans por t S ta te s i s c ompo se d o f two po rt io ns: f lo or and re duc ib le al lo ca ti on. The re ar e t wo

com pon ents o f the floo r alloca tion - a n allo cation for the Ca lifornia Re gion al C lean Air Inc enti ves Mar ket (RECLAIM) p rog ram, and so urc e-s pec if ic fl oor all ocat ions fo r nonREC LAIM sources. The floor allocati on is a min imum allocation for all existing sources, whic h wil l be cal cul ate d to ensur e tha t wel l- cont rol led sour ces wil l r ece ive a ful l al loc ati on.

Calif orni a RECLA IM Program: 3,462 S O 2 allow anc es w ill be in clude d in th e C aliforn ia budget for REC LAIM sources. These credit s will be a s ubset of t he existi ng source pool f or the S tate o f Ca lifornia and , hen ce, will n ot con sum e an y ex tra cred its from the to tal cred it
poo l.

Sour ce- spec if

ic Floo r Al loc ati on: A fl oor all ocat ion wi ll be ca lc ulat ed f or al l ex is ti ng sources i n the region based on some speci fied l evel of c ontrol ( e.g. , Best Avail able Control Tec hn olog y [BA CT ], Best A vaila ble R etrofit T echn olog y [BA RT ], Low est A chiev able Em ission Reduction [LAE R]) for non-util ity sources.

The sources aff

ected by t he backstop t rading progr ams are all those s tati onary sources in par ti cip ati ng Stat es and t ribe s that emit SO 2 in an amount gr eater than or equal t o 100 tons per year (t py) . The 100 t on cut of f wi ll be as ses sed a t t he pl ant l evel to c orr espo nd with the methodology used in t he 1990 em issi ons inventory. Amon g the source t ypes

cov ere d by t his def

ini ti on ar e uti li ty a nd in dust ri al bo il ers , r efi neri es, smelt ers , p ulp a nd paper mills , cement and li me kilns, and all of the ot her source c ategori es li sted i n secti on 16 9(g)(7 ) of th e C lea n A ir A ct (C AA ).

In this report , t he geographic area of analysis i s defi ned to be the nine Comm issi on Transport Region St ates, which are Arizona, Cali forni a, Colorado, Idaho, Nevada, New Mexico, Oregon, Utah, and Wyoming. Faci li ti es inc luded i n the anal ysis are t hose t hat emitt ed 100 tp y or more o f SO 2 som etime during the period 1990 to 2000 . Plants tha t are electri c utili ties are excluded from this analysis.



### A. ANA LYSIS METHODS

The f loo r al loc ati on anal ysi s f or t he non- uti li ty s ect or was per for med usi ng th e following steps:

1. It was assumed that the SO 2 sour ces in t he St ate of Cali for nia a re al read y at the floor. Th is is exp ected beca use of the stringe ncy o f the a ir em ission regu lation s in that Stat e.I-2

2. Becaus e co pper smelt er al loc ati ons f or 20 18 have alr eady b een de ter mined, no additiona l analyse s were perform ed for coppe r sme lters. Smelter alloca tions are
pr ese nte d i n Chap te r X.

3. The foc us of

the anal ysis was on non-Cal if orni a, non- smelte r f acil it ies t hat had at leas t 100 t py of

SO 2 em issi on s du rin g a t lea st o ne ye ar i n th e p eri od 19 90 to 2 00 0. States i ncluded in t his analysi s were Arizona, Color ado, Idaho, Nevada, New Mexico, Oregon, Utah, and Wyom ing.

4. The major SO 2 emitti ng non-util ity s ource cat egories eval uated in thi s study incl uded the f

oll owing: petr oleum ref iner ies, li me manu fac turi ng, i ndustr ial boiler s and co-gener ators, pulp and paper manufacturi ng, cement manufacturing, natur al g as pr oce ssi ng and o il and gas pro duct ion, ele mental phos phor us pro duct ion, gla ss manuf act uri ng, alumi num smelt ing, sul fur ic aci d pr oduc ti on, and metal lur gic al c oke pr oduc ti on.

5. The fl oor c ontr ol t echnol ogy or e missi on rat e or SO 2 cont rol eff ect ivenes s was deter mined by eval uati ng the emis sions perf ormance of

other sourc es in t hat

source c ategory i n the western Stat es. The fl oor is d efined t o be BAC T, BART , or LA ER for exis ting sou rces. Th e floor fo r each of the ma jor sou rce cate gorie s is summarized i n Table I- 1.

6. The pri mary sourc e of e missi ons inf ormati on for the west ern St ates is t he 1996 WR AP point source i nventory. The 1996 em issi on estimates were pr epared under contra ct to the W estern Go vern ors’ A ssocia tion (W GA ) by P acific E nviro nm enta l; Servi ces and Easter n Researc h Group, Inc. under c ontr act to t he WGA (PES, 2001) . Howev er, thi s dat a set was not suf fi ci ent f or p rov idi ng al l of

the inform ation nee ded to com pute the floo r alloca tion for each sou rce. Th e Sta te air pollu tion co ntrol a gen cies in e ach of the 8 Sta tes w ere co ntacte d to ob tain supplementary data. For most source c ategori es, t his addit ional inf ormation included es timates of unit capaci ties . This c ould be eit her the desi gn capacit y for boilers, or the production capacity for i ndustrial processes.

7. Once data was received f rom the State agenci es, i t was used to est imate the fl oor alloca tion b y sou rce an d facility b ased on th e con trol tech nolo gies liste d in T able I- 1 and the uni t or plant -sp eci fi c inf ormati on about ex ist ing c apaci ti es and SO 2 control techniques.

The chapters t hat fol low explain the f loor al locat ion analyses f or each of t he key industrial sect or source categories in the western United States.I-3 

### Table I-1 Methodol ogy

for the Calculation of the F loor A llocations f or Non-U tility

Sources

Sou rce C ateg ory Technol ogie s or Sta ndar d for

Flo or
Co pp er Sm elters Due to t he uni queness of t he exist ing smelt ers, retr ofi t t echnolog y
ana lysis m ust b e pe rform ed o n a s m elter-b y-sm elter ba sis. Current ly , t he Hidal go smelter is t he onl y BART-el igi ble sou rce on the l ist in t his cat egory . A doubl e-cont act aci d plan t wi ll be

co ns ide re d th e a pp ro pr iate ret ro fit c on tro l eq uip m en t (a ll sm elte rs in the re gion are c urre ntly equ ippe d with d oub le-co ntac t acid p lants)

. On August 21, 2000, New Mexico completed an eng ineer ing analy sis t hat ve ri fi ed earl ier deter minati ons by the MTF that the fugi ti ve SO 2 captur e syst em at Hidal go sati sfi es BART at 96% overal l capt ure.
Refineri es There ar e fou r sou rces o f SO 2 emissions at the r efi nery lev el. Floor based upon N ew Sou rce Perform ance S tandards (N SPS ) where appli cable.

Descript ion Assum ed Average Cont rol Level

Sul fu r Re cov er y Uni t (SRU ) Meet NSPS Subpart J or the equ ivalent o f 3-s tage Clau s un its with a tai l gas unit

(NSPS and the t ail gas unit do es n ot ap ply to Cla us u nits

sm aller t han 20 long tons /day or l ess).

Fu el gas com bus tion un its Fix at the NSPS emission li mit rat e of 0.027 poun ds per mil li on Bri ti sh ther mal unit s (l bs/MMBtu) assuming fu el g as inp ut a nd no t fu el o il. Catalyti c crack ers NSPS (J) sel ecte d 9. 8 l bs of SO 2 per 1,000 l bs of coke burn ed.

Flare s Ba sed upo n av erag e of th e last 5 year s' emissi on, AP42 f actor s for calcul ated. No addit ional contr ols.

Natur al Gas Pr ocess ing Descript ion Assum ed Average Le vel of Contr ol

Process Emissions R ed uc tion to s atis fy N SP S. V ar iab le reduct ion de pending on hy drogen sulfide (H 2 S) c onte nt an d plan t size.

Flari ng Ba sed upo n av erag e of th e last 5 year s' emissi on.
Oil & Gas Pr oduct ion Descript ion Assum ed Average Le vel of Contr ol

Flari ng Ba sed upo n av erag e of th e last 5 year s' emissi on.
Lime Plants No addit ional reduct ion. Approxi mately 50% control inher ent i n the proce ss. Addi ti onal SO 2 co ntr ols are no t in p lac e a t lim e p lan ts in the west ern Sta tes.

### Table I-1 (continued)

Sou rce C ateg ory Technol ogie s or Sta ndar d for

Flo or

I-4 Industri al Boil ers (Cogens) T ec hn olo gy d ete rm ina tion de pe nd en t up on cu rre nt le ve l of c on tro l.
Descript ion Assum ed Average Le vel of Contr ol

Un con trolled U nits 85%

Unit s contr oll ed at l ess than 70% Treat as u ncontrolled (see above ).

Unit s contr oll ed between 70-80% Increase redu ctions by 5% (i.e., i f a unit is at 7 2% , wou ld be a ssu m ed to control to 77%).

Unit s contr oll ed great er than 80% No addit ional reduct ions.

Pulp and Paper Sulf ur sources are recov ery furnaces and boi ler s. Boi ler discussi ons covered wi th i ndustr ial boil ers. Recovery Furnaces: No addit ional reduct ion. Low emissions coupled wit h lack of

more than one example of scrubbi ng.
Cem ent Plan ts No addit ional reduct ion. Approxi mately 70-90 per cent cont rol in heren t i n th e pro cess. Addi ti onal SO 2 co ntr ols are no t typic ally appli ed to t hese le vel s of proce sses.
Alum inum Sm elters A wet scrub ber wi th a 70 per cent SO 2 emission r educti on sele cted

as the floo r ba se d o n a ch iev ed co ntr ol le ve ls a t N W Alu m inu m in Oregon.

Sulfuric Acid Plants No add itional red uction . Exis ting un its are alrea dy co ntrolled to NSP S levels (4 lbs per ton of 100% acid produce d).

Coke Pr oduct ion O nly o ne fac ility is s till op er atin g. B ec au se of t he un iqu en es s o f th is rot ary cal cin er, the fl oor a ll ocat io n i s est abl ish ed at hi stor ic SO 2 emission l evel s.II-1 

## CH APT ER II PETROL EUM REFI NI NG

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

Th e pe troleu m refinin g ind ustry in volv es n um erou s proce sses th at con vert cru de o il into more than 2,500 prod ucts, includi ng gasoline, liquef ied petr oleum gas, kerosene, jet fuel , di esel fuel , ot her f uel oi ls, lubri cat ing oi ls, and fee d st ock f or t he petr ochemic al industr y. Petr oleum refinery ac tivi ties include t he storage of crude oil at the ref

inery, petro leum han dling and refinin g op eratio ns, an d stora ge o f the re fined prod ucts prio r to shipment. As of

January 1990, there were 189 operati ng refi neries i n the United Stat es with a total crude capac ity of 15.4 milli on barrels per calendar day.

Re m ova l of sulfu r from refine ry strea m s is a pa rt of refinin g. It wo uld b e de sirab le to

rem ove all su lfur com pou nds befor e an y crud e pro cessin g be gins, b ut be cau se this is impractical, s ulfur is removed through out the refining process. There are several reasons, besid es air p ollutio n con trol, for rem ovin g su lfur from interm edia te fraction s an d pro ducts of crude oil. Sulfur removal reduces corrosion, odor, breakdown frequency, catalyst poisoning, and gum formation and improves oc tane rati ng, col or, and l ube oil li fe.



### B. FLOOR ALLOCA

TION ESTIMATION METHODS

There are four possi ble uni t t ypes ( SO 2 em ission poin ts) with in a re finery , as no ted in the metho dology for the calculation of t he floor allocati ons for non-utility sources. These four SO 2 sour ces are: (1) the S RU; ( 2) f uel g as c ombust ion un it s; (3) cat aly ti c c rac kers ; a nd (4) fl ares. The approac h for est imati ng SO 2 fl oor all ocat ions is unique fo r eac h of thes e f our SO 2 source t ypes within t he refi nery. Floor calcul ation methods are pr esented below for each of these four source types.



### 1. Sulfur Recovery Units

Su lfur r eco ver y re fers to con ver sion of H 2 S to ele m en tal su lfu r. H 2 S is a by produc t of
process ing natural gas and refi ning high sulf ur crude oi ls. The m ost common conversion

m etho d use d is the Cla us pr ocess . App roxim ately 90 to 95 p ercen t of recov ered sulfu r is
pro duce d by t he Clau s pr oce ss. The Clau s pr oce ss t ypi cal ly r eco ver s 95 t o 97 pe rc ent o f t he H 2 S f ee d s t r ea m.
The average producti on rate of a sulfur recover y plant i n the United Stat es varies from 51 to 203 megagram s (Mg) ( 56 to 224 tons) per day. Some of the small to mid- sized refineries i n the we stern States have sulfur plant capacities t hat are lower than these average value s.

The SO 2 fl oor all ocat ion f or S RUs depe nds o n the si ze of the s ulf

ur pl ant. For s ulf

ur plan ts of 20 long tons p er da y or la rger, the NS PS requ ire a 3 -stage Cla us u nit w ith a ta il gas unit. Existi ng NSPS limit sulfur emissions f rom Claus sulfur r ecovery pl ants of gr eater than 20.32 Mg (22.40 tons) per day capaci ty to 0. 025 percent by vol ume (250 parts per million vol ume [ppmv]). The NSPS and tail gas unit do not apply t o Claus units smaller than 20 l ong tons per day or l ess. For t hese small er sul fur plant s, the SO 2 fl oor all ocat ions

are es ti mated as 95 pe rce nt SO 2 contro l.

Table 8. 13-1 i n AP-42 prov ides the f oll owing SO 2 emiss ion f act ors fo r modi fi ed Cl aus Recovery P lants:II-2 Em ission Fa ctors for M odified C laus Su lfur Recov ery Plan ts

SO 2 Emission s Nu m ber of Catalytic Stages Average % Sulfur Rec overy Kilo grams (kg) /Mg of Sulfur Produced lbs/ ton of Sulfur Produced 1, Uncontrol led 93 .5 139 278 3, Uncontrol led 95 .5 94 188 4, Uncontrol led 96 .5 73 145 2, Control led 98 .6 29 57 3, Control led 96 .8 65 129

The SO 2 em issi on fac tor for 9 9.8 pe rce nt s ulf ur rec ov ery is 8 lbs /ton an d fo r 96 .8
perce nt su lfur reco very is 132 lbs/ton of sulfu r prod uced . This e m ission factor va lue is multipli ed by the sulf ur plant c apacit y in tons per day, 365 days per year , and 1 ton per 2,000 l bs to arri ve at an annual SO 2 emiss ions fl oor est imat e. Equati on ( 1) b elo w shows t he above des cri pti on as a f ormula:

For refine ries with su lfur plants sm aller than 20 lon g tons pe r day, an d lowe r H 2 S cont ents i n thei r aci d gas, an SO 2 control level of 9 6.8 percen t ma y not be achieva ble. In that si tuat ion, an al ter nati ve way t o cal cul ate the f loo r i s t o use the s ulf ur f eed r ate and t he H 2 S cont ent of

the ac id gas of t he aff ect ed fac il it y to c ompute the a pprop riat e minimum SO 2 red uct ion e ff

ic ienc y usi ng th e re lat ions hips shown i n Table II -1. This tabl e is fr om the NSPS fo r ons hore natur al g as pr oduc ti on.


### Table II-1 Sulfur Plan ts - Requ ired Minimu m SO 2 

### Emission Red uction Ef ficiency

H 2 S Conte nt of Acid Ga s (Y ), % Sulfur Feed Rate (x), Long To ns per Day
2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 300 .0 X> 300 .0

Y > 50 74.0 . . . . . . . 85. 35X 0.0144 Y 0.0128

. . . . . . .

or 99. 8, whi chever i s smaller

20 < Y<50 74.0 . . . . 85.35X 0.0144 Y 0.0128

. . . .

or 97. 5, whi chever i s smaller 97.5

10 < Y<20 74.0 85.35X 0.0144 Y 0.0128

or 90. 8, whi chever i s smaller 90.8 90.8
Y<10 74.0 74.0 74.0 74.0



### 2. Fuel Gas Combustion Units

Fuel g as c ombust ion un it s i n ref iner ies were d efi ned t o inc lude all pro ces s heat ers and boil ers, and thei r co mbined oil and gas c ombustio n capac it y. SO 2 floor allocations a re est im ate d a s th e co m bin ed oil a nd ga s co m bu stio n c ap aci ty m ult ipli ed by 0.0 27 lbs /M M Bt u. This emis sion r ate i s an appr oximati on of t he SO 2 emission fac tor f or a fuel gas combustion unit mee ting the NSP S of 0.10 grains H 2 S per dr y st andard c ubic f oot ( dscf

) as requi red by 40 CFR 60 Subpart J.

This H 2 S value i s conve rte d to an SO 2 emission rat e in lbs/ MM Btu using the equation bel ow:II-3

In the fl oor all ocati on estimates f or fuel gas combustion units , t he fuel gas c ombustion
capac it y is based on r eport ed value s fo r t he ref iner ies i n Colorad o, New Mexico , and Ut ah as well as f

or Wyoming Refi ning and Fro ntie r Refi ning i n Wyoming. Where thi s val ue has not been r eport ed, it is e sti mated to be 5 perc ent of the c rude oi l pr oces sing c apaci ty at that ref iner y. The ind ust ry no rm is rep ort ed t o be i n the rang e of 5 to 10 per cent . The 5 per cent value wa s used b ecause it is the averag e valu e for the w estern Sta te refineries for wh ich data on fuel gas combustion capaci ty were provi ded.



### 3. Cataly

tic Crackers

The SO 2 fl oor all ocat ion f or c atal yti c c rac kers at p etr ole um ref iner ies is comput ed us ing the NSPS for fl uid catal ytic cracki ng units ( FCC Us). The NSPS for FCCUs w ithout add- on cont rol s is 9.8 kg SO

x per 1,000 kg coke burn- off . For FCCUs without add-on contr ol devic es, EPA decided that the r egulat ed pol luta nt shoul d be SO

x , bec ause SO 3 could const it ute a s igni fi cant p ort ion of the t otal SO 2 emissi ons f rom FCCUs using SO

x reducti on cataly sts. Th e stan dard for FC CU s with out a dd-on contro ls requ ires the use of M etho d 8 to deter mine the t otal SO

x emissions from affected facil ities.

One of t he iss ues in ap plyi ng the NSPS emiss ion r ate t o est imate t he SO 2 floor allocation is the availab ility of information abou t the am oun t of coke bu rn-off for each FCCU. T he So urc e Cl ass if ic at io n Code (S CC) u nit s us ed i n emi ss io n in vent or ie s, and AP42 SO 2 em ission factors, are exp resse d as lb s/1,000 barre ls of fresh feed. T here fore, it is

necess ary t o devel op a conve rsi on fac tor to go f rom an emissi on li mit expr essed as an SO

x emi ss io n r at e p er 1, 000 kg c oke bur n- of f to an e mis si on l imi t e xp re ss ed in AP- 42 o r S CC units i f the c oke burn rate is not availabl e for a r efiner y.

In order t o apply the NSPS SO2 em issi on rate to es timate the f loor al locat ion for FCCUs, i nfo rmati on about the c oke bur n rat e was nee ded f or e ach r efi nery . Fo r 10 o f t he Western State r efiner ies l ist ed in Table II- 1, est imates of t he coke burn rate i n pounds per hour were avai la bl e f ro m a dat a se t t hat the Ameri can Pet ro le um Ins ti tut e pr ovi ded to EPA
as par t of

the MACT standard set ti ng proc ess. These cok e burn rat es are based on 1997 operation s. For the refine ries with F CC Us a nd n o coke b urn rate availab le, the coke b urn rates were es timated using t he relati onship between the FCCU feed capac ity i n barrels per calen dar d ay a nd th e cok e bu rn ra te (pou nds per h our) for the 1 0 w estern refine ries w ith report ed values. The relati onship used was 16 pounds coke per barrel of oil . Refi neries wh ere this defau lt value w as app lied include d the tw o Co lorado refine ries and F lying J, Inc. in Uta h. Wyomi ng Re fi ni ng p ro vi ded a de si gn c oke bur n r at e f or it s FC CU.



### 4. Flares

Flar es ar e co mmonly use d f or t he di spos al o f was te g ases duri ng pr oce ss up set s and

em erge ncies . The y are bas ically sa fety de vices th at are also u sed to destro y org anic const it uents i n waste emis sion s tre ams. The AP-42 SO 2 emission fac tor f or a vapor recovery system and flar ing is 26. 9 lbs per 1, 000 barrels r efiner y feed. This emission f actor is ap pli ed to e sti mate the SO 2 emissions f loor f or fl ares at eac h refi nery.


### C. FLOOR ALLOCA

TION RESULTS

Table II -2 i ncl udes the f loo r al loc ati on ca lc ulat ion f or t he re fi neri es i n the 8 nonCalifor nia Western Regional Air Part nership ( WR AP) States. The Oil & Gas Journal Worldwide Refi ning Surv ey f or 2000 prov ided th e va lues for sulfu r plan t capa city, cataly tic cracki ng unit capaci ty, and crude capaci ty li sted i n Table II-2 where they were not otherwise pr ovided by Stat e air agenci es or ref inery companies. Fuel gas combustion
capa cities in M M Btu /hou r (hr) are estim ated usin g info rm ation prov ided b y Sta te air pol lut ion c ontr ol a genc ies . S inc lai r Cor por ati on pr ovi ded d ata f or i ts two Wyoming refin erie s (G ree ne , 200 2).II-4 

### Table II-2 Petroleum Refining Floor Allocation Calculation

Pl an t Na me City State Source Ty pe Plan t/Unit C apa city Capacit y Not es Floo r Al locat ion Em ission Ra te Emissio n Ra te U nits Floo r al locat ion tons/ year Cono co Inc. Co m m erc e C ity CO Su lfur R eco very U nit 70 Su lfur pla nt c ap ac ity tons sul fur

per day 8 lbs of SO 2 per t on sulf ur pr oduced 10 2.2

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 11 2.9

Oil MMBtu/hr
Tot al 955 MMBtu/hr
FCCU 12,666 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 55 4.8

Flar es 57,500 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 28 2.3

All Sources Combined 1,0 52 .2

Color ado Refi ning Denver CO Su lfur R eco very U nit 4 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 96 .4

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 60 .2

Oil MMBtu/hr

Tot al 509 MMBtu/hr
FCCU 5,333 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per coke burn off 23 3.6

Flar es 35,000 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 17 1.8

All Sources Combined 56 2.0

Giant Refi ning Co. Blo om field NM Su lfur R eco very U nit 2 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 48 .2

Fuel Gas Combusti on Gas 328 MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 38 .8

Oil MMBtu/hr

### Table II-2 (continued)

Pl an t Na me City State Source Ty pe Plan t/Unit C apa city Capacit y Not es Floo r Al locat ion Em ission Ra te Emissio n Ra te U nits Floo r al locat ion tons/ year

II-5 Tot al 328 MMBtu/hr
FCCU 5,400 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 23 6.5

Flar es 18,500 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 90 .8

All Sources Combined 41 4.3

Giant Refi ning Co. Gall up NM Su lfur R eco very U nit 2 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 48 .2

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per

m illion Btu 37 .3

Oil MMBtu/hr
Tot al 315 MMBtu/hr
FCCU 8,200 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 35 9.2

Flar es 32,200 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 15 8.1

All Sources Combined 60 2.7

Navajo Ref ini ng Co. Arte sia NM Su lfur R eco very U nit 140 Su lfur pla nt c ap ac ity tons sul fur

per day 8 lbs of SO 2 per t on sulf ur pr oduced 20 4.4

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 10 9.3

Oil MMBtu/hr
Tot al 924 MMBtu/hr
FCCU 13,000 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 56 9.4

Flar es 70,000 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 34 3.6

### Table II-2 (continued)

Pl an t Na me City State Source Ty pe Plan t/Unit C apa city Capacit y Not es Floo r Al locat ion Em ission Ra te Emissio n Ra te U nits Floo r al locat ion tons/ year

II-6 All Sources Combined 1,2 26 .7

BP/now Tes oro Pet rol eum Sa lt La ke City UT Su lfur R eco very U nit 17 .4 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 41 9.2

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 10 0.0

Oil MMBtu/hr

Tot al 846 MMBtu/hr
FCCU 14,000 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 61 3.2

Flar es 52,000 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 25 5.3

All Sources Combined 1,3 87 .7

Chevron Pr oduct s Co. Sa lt La ke City UT Su lfur R eco very U nit 22 .4 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 53 9.6

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 14 5.9

Oil MMBtu/hr
Tot al 1,234 MMBtu/hr
FCCU 6,500 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 28 4.7

Flar es 55,000 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 27 0.0

All Sources Combined 1,2 40 .3

Silver Eagle Refining Inc. W ood s Cro ss UT Su lfur R eco very U nit 0 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 0.0

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per

m illion Btu 15 .6

### Table II-2 (continued)

Pl an t Na me City State Source Ty pe Plan t/Unit C apa city Capacit y Not es Floo r Al locat ion Em ission Ra te Emissio n Ra te U nits Floo r al locat ion tons/ year

II-7 Oil MMBtu/hr

Tot al 132 MMBtu/hr
FCCU 0 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 0.0

Flar es 12,500 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 61 .4

All Sources Combined 77 .0

Flyi ng J Inc. Sa lt La ke City UT Su lfur R eco very U nit 7 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 16 8.6

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 57 .8

Oil MMBtu/hr
Tot al 489 MMBtu/hr
FCCU 7,533 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn 32 9.9

Flar es 24,000 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 11 7.8

All Sources Combined 67 4.2

Phil li ps Pet rol eum Co. W ood s Cro ss UT Su lfur R eco very U nit 14 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 33 7.3

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per

m illion Btu 83 .4

Oil MMBtu/hr

Tot al 705 MMBtu/hr
FCCU 5,000 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 21 9.0

Flar es 25,000 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 12 2.7

### Table II-2 (continued)

Pl an t Na me City State Source Ty pe Plan t/Unit C apa city Capacit y Not es Floo r Al locat ion Em ission Ra te Emissio n Ra te U nits Floo r al locat ion tons/ year

II-8 All Sources Combined 76 2.4

Frontier Refini ng Inc. Cheyenne W Y Su lfur R eco very U nit 110 Su lfur pla nt c ap ac ity tons sul fur

per day 8 lbs of SO 2 per t on sulf ur pr oduced 16 0.6

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 15 5.5

Oil MMBtu/hr
Tot al 1,315 MMBtu/hr
FCCU 7,330 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 32 1.1

Flar es 46,000 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 22 5.8

All Sources Combined 86 3.0

Sincl air Oil Corp. Casper W Y Su lfur R eco very U nit 21 .7 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 52 2.8

Fuel Gas Combusti on Gas MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 77 .1

Oil MMBtu/hr
Tot al 652 MMBtu/hr
FCCU 7,590 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 33 2.4

Flar es 22,000 Based on 2001 operat ions (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 10 8.0

All Sources Combined 1,0 40 .3

Sincl air Oil Corp. Sin clair W Y Su lfur R eco very U nit 52 .6 Su lfur pla nt c ap ac ity tons sul fur

per day 8 lbs of SO 2 per t on sulf ur pr oduced 76 .8

Fuel Gas Combusti on

### Table II-2 (continued)

Pl an t Na me City State Source Ty pe Plan t/Unit C apa city Capacit y Not es Floo r Al locat ion Em ission Ra te Emissio n Ra te U nits Floo r al locat ion tons/ year

II-9 Gas MMBtu/hr 0.027 lbs of SO 2 per

m illion Btu 11 9.9

Oil MMBtu/hr
Tot al 1,014 MMBtu/hr
FCCU 13,120 Co ke B urn R ate (lbs/h r) 20 lbs of SO 2 per t on coke burn off 57 4.7

Flar es 60,000 Based on 2001 operat ions (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 29 4.6

All Sources Combined 1,0 66 .0

W yomi ng Refi ning Co. Ne wca stle W Y Su lfur R eco very U nit 3 Su lfur pla nt c ap ac ity tons sul fur

per day 132 lbs of SO 2 per t on sulf ur pr oduced 72 .3

Fuel Gas Combusti on Gas 0 MMBtu/hr 0.027 lbs of SO 2 per
m illion Btu 51 .6

Oil 0 MMBtu/hr

Tot al 43 6.6 MMBtu/hr
FCCU 6,0 28 .5 Data pr ovid ed by W yomi ng Refi ning (lbs/hr) de sign c oke burn rate 20 lbs of SO 2 per t on coke bur ned 26 4.0

Flar es 12,500 From t he December 2000 Oil and Gas Jour nal (bbl s/c d) 26 .9 lbs/ 1,000 bbl ref iner y f eed 61 .4

All Sources Combined 44 9.3
Total Floor A ll ocation ( CO, NM, UT, WY) 11,418II- 10



### D. COMPARISON WITH HISTORICA L EMISSIONS

Table II -3 s umm ariz es his tor ical SO 2 emiss ions fr om pet rol eum ref iner ies loc ate d in t he 9 WRAP Stat es. Cali for nia r efi neri es ar e inc lude d in t his tabl e. This tabl e pr ovi des a poi nt of c omparis on with t he fl oor al loc ati ons shown in Tabl e II- 2.



### E. EXAM PLE CA LCULA TION

This sec ti on pr ovi des a n exampl e cal cul ati on of the r efi nery fl oor all ocat ion us ing t he data provi ded for t his proj ect by Wyoming Refining. This r efiner y is l ocated i n New castl e, Wyo mi ng

. Th i s s ame i nf or mat i on c an be f

ou nd i n Ta bl e I I

- 2 i n c on de ns ed f or m.



### 1. Sulfur Reco

very Unit

The SO 2 fl oor all ocat ion f or t he SRU is base d on t he ca paci ty o f t he uni t. Becaus e the
capa ci ty o f t he Wyoming Ref ini ng sul fur pla nt i s l ess than 2 0 lo ng to ns pe r da y, a sul fur

rec over y ef

fi ci ency of

96. 8 per cent is appl ied in t he f loo r c alc ulat ion. (I f t he sul fur pla nt was lar ger t han 20 long t ons per day, a 99.8 p erc ent sul fur rec overy v alue would be
ap plie d.)

The SO 2 emissi on fac tor for 96.8 p erc ent sul fur rec overy i s 132 l bs SO 2 per ton o f s ulf ur pr odu ce d as sh own b el ow:

Then, t he SO 2 floor alloc ation is the sulf ur plant c apacit y (3 short tons per day) multipli ed by the SO 2 emission factor and 365 da ys per year, as foll ows:



### 2. Fuel Gas Combustion

The SO 2 fl oor all ocat ion f or f uel g as c ombust ion i s bas ed on t he co mbined b oil er an d
proc ess heat er c ombustio n capac it y with eac h ref iner y. Wyoming Ref ining est imates that its total boiler plus proc ess heater f ired dut y capacit y at the ref inery is 436.6 MM Btu per hour. The SO 2 floor alloc ation is esti mated to be the combined oil and gas combustion
capac it y multi pli ed by 0. 027 lbs /MMBtu.II- 11 

### Table II-3 Petroleum R

efineries – H istorical Emi ssions – 1990 to 2000

Sta te Sta te

ID Co unty ID Fac ility

ID IAS Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000

AZ 4 005 0001 42 2911 6 Oil/ Gas Int ermounta in Ref ini ng 803 0 0 0

CA 6 037 800012 14 2911 6 Oil/ Gas AR CO (NS R U SE ON LY ) ARCO PRODUCTS CO 1,919 2,359 1,706 2,315

CA 6 037 800030 14 2911 6 Oil/ Gas CHEVRON U. S. A. I NC ( EI S USE) - EL SEGUNDO CHEVRON PRODUCT S CO. 833 1,795 938 1,208

CA 6 013 10 11 2911 6 Oil/ Gas CHEVRON USA I NC - RI CHMOND CHEVRON PRODUCTS COMPANY 1,291 1,018 1,413 1,244

CA 6 095 15 11 2911 6 Oil/ Gas EX XO N C OR PO RA TIO N - B EN ICIA 4,922 6,042 5,779 5,779

CA 6 029 37 13 2911 6 Oil/ Gas KE RN OIL & R EF ININ G C O. 319 425 443 364

CA 6 037 800089 14 2911 6 Oil/ Gas MOBIL OI L CORP ( EI S USE) - TORRANCE MOBIL OI L CORP ( EI S USE) 256 807 725 1,018

CA 6 013 32 11 2911 6 Oil/ Gas PACI FI C REFI NING COMPANY NOW PLANT ID 11587 278 290 0 0

CA 6 029 25 13 2911 6 Oil/ Gas SAN JOAQUI N REFI NERY SAN JOAQUI N REFI NING COMPANY 337 313 138 0

CA 6 013 11 11 2911 6 Oil/ Gas SHELL O IL COMPAN Y - MARTINEZ MARTI NEZ REF INI NG COMPANY 2,790 2,518 2,374 1,159

CA 6 037 800223 14 2911 6 Oil/ Gas TEXA CO REF I NI NG & MAR KETI NG I N - WIL MI NGTON 546 727 590 953

CA 6 029 33 13 2911 6 Oil/ Gas TEXAC O REFINING AN D MAR KETING - BAKE RSFIELD EQUILON ENTER PRISES LLC 471 190 94 72

CA 6 013 12758 11 2911 6 Oil/ Gas TOSCO CORP AVON REFI NERY 7,661 4,459 5,422 5,422

CA 6 037 800026 14 2911 6 Oil/ Gas UL TR AM AR INC (NS R U SE ON LY ) 341 959 669 620

CA 6 037 800144 14 2911 6 Oil/ Gas UNION OIL CO OF CAL (NS R USE O TOSCO REF INI NG COMPANY 724 1,005 806 806

CA 6 079 4 13 2911 6 Oil/ Gas UNOCAL CARBON TOSCO SANT A MARI A REFI NERY 0 0 0 0

CA 6 079 4 13 2911 6 Oil/ Gas UNOCAL CHEM DI V-UN OCAL CORP - ARROYO GR TOSCO 3,034 3,950 0 0

CA 6 013 16 11 2911 6 Oil/ Gas UNOCAL CORPORA TI ON - RODEO TOSCO RODEO REF INE RY 584 728 675 615

CA 6 037 14 2911 6 Oil/ Gas UNOCAL REF INI NG & MARKETI NG CO TO SC O R EF ININ G (L .A.) 0 343 508 587

CA 6 079 13 13 2911 6 Oil/ Gas UNOCAL- SANTA MARI A REFI NERY TOSCO SANT A MARI A REFI NERY 647 225 3,501 3,727

CA 6 037 800047 14 2911 6 Oil/ Gas FLET CHER OI L & REF CO ( EI S USE 107 0 0 0

CA 6 037 800184 14 2911 6 Oil/ Gas GO LD EN W ES T R EF CO (EIS US E) 232 0 0 0

CA 6 037 800103 14 2911 6 Oil/ Gas PO W ER INE OIL CO (EIS US E) 196 0 1 1

CA 6 037 800115 14 2911 6 Oil/ Gas SHELL OI L CO ( EI S USE) - CARSON SHELL O IL PRODUC TS 778 0 0 0

CO 8 001 0004 53 2911 6 Oil/ Gas COLO REFI NING 632 664 526 545

CO 8 001 0003 53 2911 6 Oil/ Gas CONOCO DENVER 2,336 2,610 2,496 1,972

CO 8 077 0001 55 2911 6 Oil/ Gas LANDMARK PET ROLEUM 157 0 0 0

NM 35 045 0023 60 2911 6 Oil/ Gas GIAN T I NDUSTRI ES/ BLOOMFI ELD REF 676 772 920 920

NM 35 031 0008 61 2911 6 Oil/ Gas GIAN T REFI NING/ CINI ZA REF INE RY 1,346 1,115 1,779 1,779

NM 35 015 0010 65 2911 6 Oil/ Gas NAVAJO REF INI NG/A RTESI A REFI NERY 1,549 1,552 969 980

UT 49 035 0004 32 2911 6 Oil/ Gas Am oco Pe troleum Pro duc ts TESORO PET ROLEUM 6,701 983 1,116 1,368

UT 49 011 0003 31 2911 6 Oil/ Gas Chevron Prod ucts Company 2,424 1,116 845 1,242

UT 49 011 0008 31 2911 6 Oil/ Gas Flyi ng J I ncorpor ated 312 574 225 300

UT 49 011 0013 31 2911 6 Oil/ Gas Phil li ps 66 Company 5,672 864 862 601

W Y 56 021 0001 9 2911 6 Oil/ Gas FRONTI ER OI L & REF INI NG - CHEYENNE 1,521 1,769 1,422 1,396

W Y 56 025 0001 9 2911 6 Oil/ Gas LI TTL E AMERI CA REFI NING COMPANY SI NCLAI R - CASPER 1,899 1,629 1,305 1,458

W Y 56 007 0011 9 2911 6 Oil/ Gas SIN CL AIR @ SIN CL AIR 5,917 3,990 3,524 3,407

W Y 56 045 0001 9 2911 6 Oil/ Gas WYOMING REF INI NG CO WY OMING R EFINING - NEWC ASTLE 630 930 804 876

W Y 56 025 0002 9 2911 6 Oil/ Gas AMOCO REFI NERY 1,153 0 0 0

Tota ls 61,994 46,721 42,575 42,734II- 12



### 3. Cataly

tic Crackers

The SO 2 fl oor all ocat ion f or c atal yti c c rac kers is base d on t he co ke bur n rat e at the FCCU an d the NSPS SO 2 emission rat e. The FCCU for Wyoming Refining has a design feed rat e of 5, 300 barr els p er day, or 6, 029 lbs per hour . The NSPS SO 2 emissi on rat e is 20 lbs SO 2 per ton cok e b urn -off.



### 4. Flares

The SO 2 floor allo cation for the flares a t W yom ing R efinin g is estim ated accord ing to the to tal crud e pro cessin g cap acity o f the facility . The estim ated crude proce ssing capa city for Wyoming Refining is 12, 500 barrels per calendar day. This capaci ty value i s multipl ied by the AP- 42 SO 2 emission fac tor f or a vapor rec overy syst em and flaring of 26.9 lbs per 1,000 barrel s ref

inery f eed.

REFERENCES

40 CFR Part 60, 2001a: Code of Federal Regulati ons, “ Subpart J - St andards of Perf ormance f

or Pet rol eum Refiner ies, ” ( 60.100- 60.109) , 2001.

40 CFR Part 60, 2001b: Code of Federal Regulati ons, “ Subpart LLL - Standards of Perf ormance f

or Onshor e Natural Gas Proce ssi ng: SO 2 Emissio ns, ” 2001.

EP A, 19 89: U .S. En viron m enta l Prote ction A gen cy, “Sulfu r Ox ides E m ission s from Flu id Catalyti c Cracking Unit Regenerat ors – Background Infor mation for Promulgated Sta ndar ds – Fi nal EI S, ” EPA- 450/ 3-8 2-0 13b, Off ic e of Air Quali ty Pl anning and Standar ds, Researc h Triangl e Park, NC, Apri l 1989.

EPA , 1993: U. S. Environmental Protec tion Agency, “Compilation of Air Pollut ant Emission Fact ors (AP- 42) , S ect ion 8 .1 3 Sul fur Recov ery ,” Off ic e of Air Quali ty Pl anning and Standar ds, Researc h Triangl e Park, NC, 1993.

EPA , 1995: U. S. Environmental Protec tion Agency, “Compilation of Air Pollut ant Emission Fact ors (AP- 42) , S ect ion 5 .1 Petr ole um Refi ning, ” Of fi ce o f Ai r Qual it y Pla nning and Standar ds, Researc h Triangl e Park, NC, 1995.

Greene, 2002: Lett er fr om Sam uel B. Greene, P. E., Si nclair Oil Corporat ion, Sal t Lake City, UT , to Jim W ilson, E .H. P echa n & Asso ciates, In c., Spring field, VA , Re: Sin clair O il Co rpora tion W estern Re gion al A ir Pa rtners hip - M arke t Tra ding For um , Non -Utility SO 2 Floor Alloc ati on Study, Transmit tal of Reques ted I nfor mation, Septe mber 30, 200 2.

O il & G as Jo ur na l, 20 00 : Oil & Gas Journal , “ 2000 W orldwide Refi ning Survey,” December 18, 2000, Volume 98.51, 2000.III-1 

## CH APT ER III LI ME MANU FA CTURI NG

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

Lime is the high temperatur e product of the calc ination of

limestone. Although limestone deposi ts are f ound in every State, only a small port ion is pur e enough for indu strial lim e m anu facturin g. Th e Sta nda rd Ind ustria l Cla ssification (SIC ) code fo r lime manufact uring i s 3274. The six- digi t SCC for li me manu fac turi ng is 3- 05-016.

The hear t of

a li me plant is the k il n. The pre val ent t ype o f ki ln i s t he ro tar y ki ln,

accou nting for ab out 9 0 pe rcent o f all U.S . lime prod uction . This k iln is a lo ng, cylin drical, sli ghtly i nclined, refr actory -li ned furnace, through which the li mestone and hot combustion
gases p ass concu rrently. Coa l, oil, and n atural ga s ma y all be fired in ro tary kilns. Prod uct cooler s and kiln f

eed preheaters of vari ous types ar e common ly used to r ecover heat f rom the hot li me product and hot exhaust gases, respect ively.

Th e n ex t m ost com m on typ e o f kil n in the U nit ed Sta tes is th e v ert ica l, or sh aft, k iln

. Th is k iln can be de scri be d a s a n u pri gh t he av y st ee l cy lin de r lin ed w ith refr act ory m ate ria l. The li mesto ne is char ged at the t op and is cal ci ned as it desc ends sl owly t o di sc harg e at the bottom of t he kiln. A primary advantage of vert ical kilns over rotar y kilns i s higher average fuel ef

fic iency. The primary disadvantages of verti cal kil ns are their relat ively l ow pro duct ion r ate s and t he f act that coal canno t be used wit hout degr adi ng th e qual it y of the lime produced. There have been few recent vert ical kiln inst allat ions in t he United States because of high produ ct quality requirements.

O the r, m us t les s co m m on , kil n ty pe s in clu de rot ary he art h a nd flu idiz ed be d k iln s. Both k il n typ es c an achi eve hi gh pr oduc ti on ra tes , b ut ne it her c an oper ate wit h coa l. The “calcim atic” kiln , or rotary hea rth kiln , is a circula r kiln w ith a slo wly revo lving dou ghn utsha ped hea rth. In flu idized bed kilns , finely d ivided lime stone is brou ght in to con tact w ith hot c ombust ion a ir in a t urbul ent z one, usual ly a bove a per for ate d gr ate . Bec ause o f t he amount of l ime car ryover int o the ex haust gas es, dust col lec ti on equipment must be instal led on fl uidized bed ki lns for process economy.

SO 2 emiss ions are i nfl uence d by s ever al f act ors , i ncl udin g the fue l s ulf ur c onte nt, the sulfur content and numeralogical form (pyr ite or gypsum) of the s tone feed, the qualit y of li me being pro duced, and the t ype of kil n. The dominant sourc e of SO 2 emiss ions is the kiln’s fu el, an d the vast m ajority o f the fu el sulfu r is no t em itted be cau se of re action s with calc ium oxides in t he kil n. SO 2 emissions may be further reduced if the poll ution equipment us es a wet p roc ess or if it bri ngs cal cium oxi des and SO 2 into in tima te con tact.

Table II I- 1 provi des SO 2 emi ss io n f ac to rs f or li me manu fa ct ur in g. Thi s t abl e s hows that ther e is a wide rang e of SO 2 emissions per formance depending on the kil n type, pollu tion co ntrol e quip m ent, fee dstock , and fuel.

Because o f diff

erences in the sulfur content of the raw m aterial and fuel and in process operation s, a ma ss balan ce on su lfur ma y yield a m ore represe ntative em ission factor for a specifi c facil ity than AP-42 e mission factors.



### B. FLOOR ALLOCA

TION ESTIMATION METHODS

With the wide rang e of SO 2 emissi on fac tor s fo r li me manu fac turi ng, t he SO 2 control that is in here nt in th e lim e m anu facturin g pro cess, an d ad dition al con trols are not ty pically appli ed to l ime plant s, the SO 2 fl oor al loc ati on for li me plants will be based o n hist ori calIII-2

em issi on s. T he his tor ica l em issi on s fo r th e 1 99 0 to 20 00 pe rio d a re l iste d in Ta ble III-2

. The cale ndar year 2000 SO 2 emission total for li me m anufacturing is 2,316 tons.

REFERENCES

AW M A, 2 00 0: A ir & W as te M an ag em en t A sso cia tion , “A ir P oll uti on En gin ee rin g M an ua l,” 2 nd edit ion, edit ed by Wayne T. Davi s, 2000.

EPA , 1998: U. S. Environmental Protec tion Agency, “Compilation of Air Pollut ant Emission Fact ors , AP- 42, Sec ti on 11: 17: Lime Manufa ct uri ng, ” Of fi ce o f Ai r Qual it y Pla nning and Standar ds, Researc h Triangl e Park, NC, 1998.III-3 

### Table III-1 Emission Factors for Lime Manufacturing a

Source SO 2 b Emiss ion Fact or Ra ti ng

Coal-f ir ed rot ary kil n (SCC 3-05-016- 18) 5.4 D

Coal-f ir ed rot ary kil n wit h fabri c fi lt er (SCC 3-05- 016-18) 1.7 D

Coal-f ir ed rot ary kil n wit h wet scr ubber (SCC 3-05- 016-18) 0.30 D

Gas-fir ed rot ary kil n (SCC 3-05-016- 19) ND

Coal- a nd gas-fi red rot ary kil n wit h vent uri scrubber (SCC 3-05-016- 20) ND

Coal- a nd coke-fi red rot ary kil n wit h vent uri scrubber (SCC 3-05-016- 21) ND

C oa l-fir ed rot ar y pre he ate r k iln w ith d ry P M co ntr ols (SCC 3-05-016- 22) 2.3 E

C oa l-fir ed rot ar y pre he ate r k iln w ith m ultic lon e, w ate r s pr ay, and fabr ic f il ter (SCC 3-05-016- 22) 6.4 E

Gas-fir ed calci matic ki ln ( SCC 3-05-016-05) ND

Gas-fir ed paral lel fl ow regenera ti ve kil n wit h fabri c fi lt er (SCC 3-05-016- 23) 0.0012 D

Product cooler

(SCC 3-05-016- 11) ND

NOTES: a Factor s repr esent uncont rol led emissi ons unle ss other wise not ed. Fact ors ar e lbs/ ton of li me produced unl ess noted. ND = no data. Cl assif icat ion Code.

b Mass balance on sul fur may yield a more repr esentat ive emissi on fact or f or a speci fi c faci li ty.III-4 

### Table III-2 Lime Manuf

acturing -

Historical Emissions - 1 990 to 2000

Sta te Sta te

ID Co unty ID Fac ility

ID IAS Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000 Floor

All ocati on*

AZ 4 025 0011 41 3274 10 Me tals /Min ing /Min era ls CHEMI CAL L I ME ( CHEMSTAR) CHEMI CAL L I ME CO - NELS ON PLANT 141 122 562 702 632

AZ 4 003 0003 47 3274 10 Me tals /Min ing /Min era ls CHEMI CAL L I ME ( DOUGLAS) CHEMI CAL L I ME CO - DOUGLAS PLANT 212 634 724 742 733

CA 6 053 12 12 3274 10 Me tals /Min ing /Min era ls NATIONA L REFRA CTOR IES&MINERALS CHEMI CAL L I ME CO - NATI VI DAD PLANT 243 <100 69 82 76

NV 32 003 0003 22 3274 10 Me tals /Min ing /Min era ls CHEMSTAR APEX CHEMI CAL L I ME CO - APEX PLANT 783 175 210 193

NV 32 007 0261 3274 10 Me tals /Min ing /Min era ls CONTI NENTAL L I ME I NC., PI LOT PEAK PLANT GRAYMONT WESTERN US I NC, PI LOT PEAK PLANT <100 136 235 249 242

UT 49 027 35 3274 10 Me tals /Min ing /Min era ls CONTI NENTAL L I ME I NC., CRI CKET MOUNTAI N PLANT GR AY MO NT W ES TE RN US , INC

., CRI CKET MOUNTAI N PLANT 115 297 275 331 303

Tota ls 1,594 1,289 2,040 2,316 2,179

NOTE: *Ba sed on 199 8 an d 20 00 h is to ri cal SO 2 emission esti mates.IV -1 

## CH APT ER IV IN DUSTRI A L BOI LERS A ND COGENERA TORS

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

Industri al, c omm erci al and insti tuti onal (ICI) boiler s produce s team or heat water for use in industr ial pr ocesses, elect ric al/mechanical power generation, or space heat ing. Some have a dua l functionality su ch as the cogen eration o f steam a nd electricity. Aux iliary boilers provid e back up po wer a nd po wer for startu p/shutdow n of large u nits. Large b oilers ( $ 150 MM Btu/hr) are generall y fiel d-erec ted units while small boil ers are pr eassembled, packaged units. The design of an indivi dual ICI boil er is of ten dependant on the appli cati on of stea m and the sp ace lim itation s in a particu lar pla nt.

ICI boilers generate steam at low er temperatures and pressures than utility boilers

, theref ore, t heir heat i nputs are smaller . Indust rial boiler s generall y have heat input rat es

ran gin g fro m 30 to 2 50 M M Btu /hr, b ut m ay be as h igh as 1 ,500 M M Btu /hr (E PA , 199 4). Comm erc ial and inst it utio nal boi ler s ty pic all y have heat input rat es rang ing f rom 0.4 t o 12 MMBtu/ hr

, but may b e as hi gh a s 1 00 MMBt u/ hr ( EPA, 199 4)

. The ove ra ll po pul at io n of ICI boi ler s have small heat inpu ts , wi th 80 per cent of the p opul ati on ope rat ing a t l ess than 5 MM Btu/hr per boiler (STAPP A, 1994). Over 80 pe rcent of the ICI boilers burn oil and gas. The remaining boilers burn pr imarily c oal, wit h a small numb er burning biomass, waste or othe r non- fos si l f

uel. ICI c ombust ion un it s of ten b urn a mi xtur e of conv enti onal fue ls and bio mass or wast e. Pulve ri zed c oal -f ir ed uni ts acc ount fo r ap pro ximat ely 1 per cent of the tot al ICI boil er pop ulat ion. However, t hey have lar ge heat i nputs, great er t han 100 MM Btu/hr , t heref

ore, they r epres ent 14 per cent of t he tot al ICI boil er c apaci ty. Oil and g as fi red I CI boil ers ar e small er i n siz e than c oal- fi red boi ler s, typi call y les s than 250 MM Btu/hr.

The use of

ICI b oil ers vari es wi th t he ind ust ri al ap pli cat ion. In ad dit ion, the application o f steam from an ind ustrial boiler can chan ge w ith the sea sons, an d can v ary thro ugh the c ourse o f a day as well , de pending o n the pr oces ses and ac ti vit ies und erway at a given mom ent and their demand for steam. Therefor e, ICI boi lers may have a much lower

an nu al o pe rat ing loa d o r ca pa city fac tor tha n a typ ica l ut ility bo ile r.



### B. FLOOR ALLOCA

TION ESTIMATION METHODS

The analysi s was li mited t o fac il it ies whi ch emit great er t han 100 tpy o f SO 2 in tota l, and/or indi vidual units which emit great er t han 25 tpy of SO 2 . In ad dition , only co al an d oil fir ed units were analyzed. Auxiliary boi lers were i ncluded in t he floor alloc ation est imation if t he unit had a potenti al to emit ( PTE) greater t han 25 tpy. This i ncludes boil ers lar ger than 5 MM Btu/hr f

iri ng fossi l fuel with a sulf ur content of

1 percent or more.

The a ir po ll ut io n ag enc ie s f or eac h WRAP St at e p ro vi ded in fo rma ti on f or eac h I CI boiler being analyzed. This infor mation included t he boiler des ign capaci ty, annual fuel consumpti on for rec ent c alendar years , f uel t ype ( coal or oi l) , f uel sul fur cont ent, SO 2 control devic e inf

ormati on, and t he cont rol devic e SO 2 cont rol eff ici ency, or per mitt ed SO 2 em ission s lim it for each un it.

The SO 2 floor alloc ations ar e calcul ated for each faci lit y based on the curr ent level of contro l. An a vera ge le vel o f contro l is then assu m ed for e ach facility, acco rding to Ta ble IV- 1 be lo w:IV -2 

### Table IV-1 Assu med Lev el of Con trol for SO 2 

### Floor Allocation

Curr ent Faci li ty Level of Cont rol Ass umed Ave rag e Leve l of Contr ol for Est imat ing the Floo r
Uncontrol led, 0% 85% Reduction

Unit s contr oll ed at 0% to <70% 85% Reduction

Unit s contr oll ed at 70% to 80 % Incre ase reduct ion by 5%

Unit s contr oll ed at 80% or gr eater No addit ional reduct ion

Floor all ocati ons for i ndustri al boil ers/ cogenerator s were also based on t he average
capa city utiliza tion d urin g the mo st recen t calen dar y ears. S om e Sta tes w ere a ble to provide as many as fi ve years worth of boiler util izati on data. The recent years of boiler util izati on (fuel consumption) dat a were used to esti mate an average capacit y fact or for each unit . Thi s ave rage cap aci ty f act or was used , a long wit h a 5 per cent margi n fo r gr owth, in t he SO 2 floor allocation calcu lation for each boiler/cogen erator.



### 1. Coal Fired Units

Coal f ire d unit s were as sumed to f ire subbit uminous coal with a heat ing val ue of 9, 000 Btu/l b (18 MMBtu/t on) of coal burned, unless a spec if ic c oal t ype or heati ng value was reported (A WM A, 200 0). The IC I boilers in the WR AP States w ere assu me d to burn subbituminous coal si nce it has a l ow sulfur cont ent. I n additi on, a lower grade of subbituminous coal, class C coal, was assumed to be used f or ICI appli cati ons. The fuel

su lfu r co nte nt u sed to c alc ula te th e flo or a llo cat ion w as fac ility -sp eci fic, w he re a va ila ble

. For f aci li ti es t hat d id no t r epor t s ulf ur c onte nt, an aver age s ulf ur c onte nt ( 1 per cent ) f or t he type of co al b ein g fire d w as u sed (AW M A, 2 00 0).

The SO 2 emissi on fac tor for subbit uminous coal fi red boi ler s in po unds of SO 2 emitted per ton of coal burned is given in AP -42 as:

wher e S i s t he p er ce nt age su lf ur co nt ent of

th e c oal bur ned by e ac h c ombus ti on u ni t ( EPA, 19 98 a).



### 2. Oil Fired Units

Oil fired units were assume d to have a h eating value of 0.15 M MB tu/gal unless a specif ic oi l type or heating value was report ed (AWM A, 2000). The fuel sulf ur content us ed to c alc ulat e the fl oor all ocat ion was fac il it y- spec if ic . Fo r f

aci li ti es no t r epor ti ng sul fur

con ten t, an av era ge s ulfu r con ten t for th e typ e of o il be ing fired wa s us ed (A W M A, 2 00 0).

The SO 2 emission fac tor f or No. 2 and No. 6 oil fir ed boiler s in pounds of SO2 emitted per 1,000 gallons of oil burned is given in AP -42 as:

wher e S i s t he pe rc ent age sul fu r c ont ent of the oi l b urn ed b y ea ch c ombus ti on uni t ( EPA 19 98 b).IV -3

Un its that b urn natu ral ga s an d oil a re ass um ed to b urn natu ral ga s as a prim ary fu el, if the emis sion d ata i ndic ated SO 2 emiss ion < 5 tp y. If natur al g as i s t he pr imary fue l, no alloc ations ar e computed.



### C. FLOOR ALLOCA

TION RESULTS

Table IV- 2 summari zes the f loo r al loc ati on ca lc ulat ion f or t he ICI boi ler s i n the 8 nonCalifornia Western R egional Air Partnership (W RAP ) States.



### D. COMPARISON WITH HISTORICA L EMISSIONS

Table IV- 3 summarizes hi sto ric al SO 2 em ission s from indu strial bo ilers loca ted in Arizona, Color ado, Idaho, Oregon, Utah, and Wyoming. This table pr ovides a poi nt of

com parison w ith the floor allocation s show n in T able IV -2 and h istorical emission s at each facili ty. Note that the histori cal emissions are the total plant emissions, not just those result ing fr om operation of t he boiler. In general, boiler s which current ly have a scrubber are abl e to meet thei r SO 2 floo r al loc ati on s b as ed on his tor ica l em issi on s.



### E. EXAM PLE USE OF C APA CITY UT ILIZA

TION DA

TA FOR FLOOR

AL LOCA

TION ESTIMA TES

The f loo r al loc ati on es ti mati on metho d f or bo il ers and c ogene rat ors tak es i nto a cc ount util izati on of these f uel combustion units in the most rec ent hist oric al years. This sect ion provi des an exampl e of how t he capac it y fac tor cal culat ion was per for med for o ne boil er at Abiti bi Consol idat ed in Ari zona.

In order t o esti mate the average annual capacit y fact ors of each unit, Pechan requested the actual fuel t hroughput data for the last 5 years for each boiler . The data was suppli ed by the ai r pol luti on agenci es f or eac h WRA P Stat e. The f uel t hroughput data s uppli ed by the Ari zona DEQ for Abit ibi Consoli dated is l ist ed in Tabl e IV-4.

Fuel t hroug hput fo r al l f uel t ypes , c oal , o il and nat ural gas wer e use d to est imat e the annual heat inpu t f

or e ach uni t us ing t he f oll owing e quat ion:

where: Q annual = a nn ua l he at in pu t for e ach bo iler (M M Btu /yr),
T = thr oughput fo r gi ven f uel t ype, and HC = heat content f or a given f

uel type.

M ost Sta tes did not sp ecify th e he at con tent for e ach fuel, the refore, th e follow ing d efau lt values were used:

Coal Heat content = 18. 0 MM Btu/ton Oil Heat cont ent = 0. 15 MM Btu/g al Natural Gas He at conten t = 1,020 M MB tu/MM scf

Th e bo iler des ign ca pacity at A bitibi P ow er bo iler #2 is 1,13 2 M M Btu per h our. In this

exe rcise, the ann ual fu el con sum ption is com pare d w ith this boile r desig n ca pacity to est imate t he perc entage o f t otal capac it y that is us ed in eac h year. The Arizona DEQ was ab le to pro vid e fu el th rou gh pu t, or fue l co ns um ptio n, e stim ate s fo r fou r ca len da r ye ars : 1998 through 2001. This part icular unit burns coal and oil, but not natural gas. Fuel

cons umpti on es ti mates were p rov ide d by t he St ate in t ons f or c oal and gal lons fo r oi l. The
average heat c ontent s of these two fue ls ar e li ste d in Tabl e IV-4 a nd are use d to c ompute an All Fuel s Combi ned Thr oughput value in col umn J. Column K contains the boil er desig n capac it y value c onvert ed to a n annual equiv alent . The c apaci ty f act or f or eac h cale ndar year is c omputed (in col umn L) as the r atio of column J to column K. For Abitibi Power boile r #2, th ese ca pacity factors ra nge from 60 to 70 p ercen t, with a n av erag e cap acityIV -4

fact or of 64 per cent. The 64 percent average capac ity f actor value is used i n the floor alloc ation est imate. ( Note that duri ng a leap year (2000) , t he potential hours of oper ation

are gre ate r.)

This aver age capac it y fac tor is us ed to c alcul ate t he SO 2 floor allo cation . This v alue is multi pli ed by 1 .0 5 to pro vid e some mar gin f or f utur e inc reas es i n oper ati ons. Only t he primary fuel (coal in this example) is as sumed to burned by the boiler in the f loor al locat ion est imati on. The SO 2 all ocat ions ar e cal culat ed usi ng the as sumed cont rol eff ici ency ( 85
perc ent) as spe cif

ied i n Table IV- 1. The SO 2 fl oor all ocat ion i s c alc ulat ed us ing t he fol lowi ng equat ion:

where: SO 2 = SO 2 floor allo catio n (to ns/y r), Q design = a nn ua l he at in pu t (M M Btu /yr), HC pri me = h ea t co nte nt o f pri m ary fue l (M M Bt u/to n, M M Bt u/g al), EF = SO 2 em issio ns fa ctor (lb /ton , lb/ga l), CF = aver age c apac it y f act or ( %), and CE = re qu ired con trol e fficien cy (% ).

For Abitibi Power boiler #2, the appropri ate values f or the above equation ar e:
Q design = 9,916, 320 HC pri me = 18 EF = 35 CF = 0.64 CE = 85

As is s hown in col umn P of Table IV- 4, t he SO 2 fl oor al loc ati on est imate f or Abit ibi Power boiler #2 is 978 tpy.

REFERENCES

AW MA , 2000: Air and Wa ste Managem ent Associ ation, Davis, Wayne T. ed., “Air Poll ution Engineeri ng Manual,” Second Edi ti on, John Wil ey and Sons, Inc. , New York, 2000.

EPA , 1994: U. S. Environmental Protec tion Agency, “Alter native Control Techniques Doc ument – NO

x Emis si ons f ro m Ind ust ri al / Commer ci al / In st it ut io nal Boi le rs , ” E PA453/ R-94- 022, Emiss ion S tand ards Divi si on, Off ic e of Air Quali ty Pl anning and Standar ds, Researc h Triangl e Park, NC, March 1994.

EPA, 199 8a: U.S. Envir onmental Prot ect ion Ag ency , “ Compil ati on of Air Poll utant Emissio n Factor s (AP- 42), Sect ion 1. 1 Bituminous And Subbituminous Coal Combustion, ” Off

ice of Ai r Quali ty Pl anning and St andards , Rese arch Tr iangl e Park, NC, 1998.

EPA, 199 8b: U.S. Envir onmental Prot ect ion Ag ency , “ Compil ati on of Air Poll utant Em ission Fa ctors (A P-42 ), Section 1.3 F uel O il Co m bus tion,” O ffice of Air Q uality Planning and S tandar ds, Researc h Triangl e Park, NC, 1998.

STAPPA, 19 94: Sta te a nd Ter ri tor ial Air Poll uti on Pro gram Admini st rat ors (STAPPA) and Asso ci ati on of

Local Air Poll uti on Cont rol Off ic ial s ( ALAPCO), “ Contr oll ing Ni tr ous Oxides, ” Jul y 1994.IV -5 

### Table IV-2 Facility SO 2 

### Floor A llocation E stimation for ICI B oilers

Fac ility Un it Ca pac ity in MM Btu/hr Fuel Sulfur Content Curr ent SO 2 Co ntro ls Percent

Reduction SO 2 Lim it Average Ca pac ity Factor ( % ) Assumed

Percent Reduction Floor

All ocati on (tpy)

Arizona

Abiti bi Consol idat ed No. 2 Power Boi ler 1,132 Coal 1.0 None 0 64 85 978

Colorado

TR IGE N - C olora do E nerg y Co rp Boil er #3 225 Coal 0.39 0 43 85

TR IGE N - C olora do E nerg y Co rp Boil er #4 360 Coal 0.38 0 62 85

TR IGE N - C olora do E nerg y Co rp Boil er #5 650 Coal 0.43 0 59 85 387

Idaho
Amalgamated Sugar, Nampa S-B 1 105 Coal 1.0 None 0 34 85
Amalgamated Sugar, Nampa S-B 2 105 Coal 1.0 None 0 35 85
Amalgamated Sugar, Nampa S-B 3 250 Coal 1.0 None 0 43 85 242
Amalgamated Sugar Company, Paul S-B 1 200 Coal 1.0 None 0 35 85
Amalgamated Sugar Company, Paul S-B 2 200 Coal 1.0 None 0 23 85 155

Am alg am ate d S ug ar C om pa ny, T win Fa lls P-B 1 280 Coal 1.0 None 0 30 85

Am alg am ate d S ug ar C om pa ny, T win Fa lls P-B 2 285 Coal 1.0 None 0 24 85 203 Oregon

Boise Cascade c Power Boil er 6- 9 N/A Oil 2.0 No 0 4125 tp y

-- 85 411
Amalgamated Sugar B& W Bo ilers 204 Coal 1.5 W et Scr ubber 45 200 tpy 12 85
Amalgamated Sugar Foster Ril ey Boi ler 136 Coal 1.5 0 265 tpy 20 85
Amalgamated Sugar Foster W heeler

Boil er 300 Coal 1.5 0 775 tpy 21 85 74
Georgia Pacifi c W est Power Boil er #1 Unknown Oil 2.0 None 0 429.6 t py

-- 85 143
Pope & Talbot Power Boil er #1 Unknown Oil 2.0 None 0 391 tpy

-- 85 107

W est Li nn Paper Co. Boi le rs 1 & 2 Oil 2.0 None 0 492.74 tpy 46 85 211 Georgia -Paci fi c W auna Power Boil er Unknown Oil 2.0 None 0 641.1 t py

-- 85
Georgia -Paci fi c W auna Package Boil er Unknown Oil 2.0 None 0 0.5 t py 0 85 277

W eyerh aeu ser S pring field Power Boil er Unknown Oil 2 None 0 590 tpy

-- 85

W eyerh aeu ser S pring field Package Boil er Unknown Oil 0.55 None 0 73 tpy

-- 85

W eyerh aeu ser S pring field Package Boil er 16 Oil 2 None 0 39 tpy 0 85 362

Utah Sunnysi de Cogenerat ion Assoc iat es FBC Boiler #1 700 Coal 1.0 Scrubber 86 462 lb s/hr 84 86 1,270

Ke nne cott U tah C opp er C orp N . Co nce ntato r Un it 1 431 Coal 0.68 None a 0 1258 tp y 41 85

Ke nne cott U tah C opp er C orp N . Co nce ntato r Un it 2 431 Coal 0.68 None a 0 1258 tp y 33 85

Ke nne cott U tah C opp er C orp N . Co nce ntato r Un it 3 431 Coal 0.68 None a 0 1258 tp y 28 85

Ke nne cott U tah C opp er C orp N . Co nce ntato r Un it 4 838 Coal 0.68 None a 0 2445 tp y 39 85 700
Brigh am You ng U nive rsity Units #2, #3 , and # 5 128 Coal 0.70 None a 0 217 tpy 0 85
Brigh am You ng U nive rsity Auxil iar y #7 5 Oil 1.5 0 6 85 0

Brush Wellman Inco rpor ated S-11 - Main Boi ler 81.2 Oil 1.5 None 46 0.85 lb/MB tu 32 85

Brush Wellman Inco rpor ated S-10 Backup Boil er 12.66 Oil 1.5 None 46 0.85 lb/MB tu 19 85 23

### Table IV-2 (continued)

Fac ility Un it Ca pac ity in MM Btu/hr Fuel Sulfur Content Curr ent SO 2 Co ntro ls Percent

Reduction SO 2 Lim it Average Ca pac ity Factor ( % ) Assumed

Percent Reduction Floor

All ocati on (tpy)

IV -6 Geneva Steel Po wer B oiler 1 411 Coal/ Gas 1.0 None 0 4

Geneva Steel Po wer B oiler 2 411 Coal/ Gas 1.0 None 0 4

Geneva Steel Po wer B oiler 3 411 Coal/ Gas 1.0 None 0 4

Geneva Steel Po wer B oiler 4 205 Coal/ Gas 1.0 None 0 0

Geneva Steel Power Boil er 5 205 Coal/ Gas 1.0 None 0 520.2 t py 0 96 17
Wyoming
Solvay Miner als, Inc. Boil er #18 350 Coal 0.7 Scrubber 85 0.2 62 85
Solvay Miner als, Inc. Boil er #19 350 Coal 0.7 Scrubber 85 0.2 61 85 294

General Chemical Bo iler C 534 Coal 0.5 No 0 1.2 74 85

General Chemical Bo iler D 880 Coal 0.5 No 0 1.2 71 85 750
Holly Sugar- Torri ngton Pl ant 221 .2 Coal 0.7 No 0 None 17 85 23
FMC Corp - Green River Plant Boil er #6 887 Coal 0.5 Sc rubb er b 0 1.2 70 85
FMC Corp - Green River Plant Boil er #7 887 Coal 0.5 Sc rubb er b 0 1.2 70 85 956

Univer sit y of

W yoming Cent ral Heati ng Plant Boil er #2 73.1 Coal 0.5 No 0 1.2 18 85

Univer sit y of

W yoming Cent ral Heati ng Plant Boil er #3 73.1 Coal 0.5 No 0 1.2 25 85 22

Univer sit y of

W yoming Cent ral Heati ng Plant Boil er #4 73.1 Coal 20
FMC Granger Boil er #1 358 Coal 1.0 Scrubber 99 0.2 lb/M Mb tu 48 99
FMC Granger Boil er #2 358 Coal 1.0 Scrubber 99 0.2 lb/M Mb tu 48 99 305

Total Floor All ocati on 7,910

NOTES: a Natural gas i s fi red duri ng winter months per SIP requir ements.
b Sc rubb er is for the entire p lant no t just the b oiler.IV -7 

### Table IV-3 Comparison of SO 2 

### Floor A llocation with Historical E missions fo r ICI Boil ers

His to ri cal SO 2 Emissions

Fac ility Un it Capacity ( MM Btu/hr) SO 2 Floo r Allo catio n (tpy) 199 0 (tpy) 199 6 (tpy) 199 8 (tpy) 200 0 (tpy)

Arizona

Abiti bi Consol idat ed Power Boil er #2 1,132 978 2,455 2,448 1,893

Colorado

TRIGEN - Colorad o Energy Corp b Boil er #3 225

TRIGEN - Colorad o Energy Corp b Boil er #4 360

TRIGEN - Colorad o Energy Corp b Boil er #5 650 387 2,675 3,708 2,583

Idaho
Amalgamated Sugar, Nampa S-B 1 105
Amalgamated Sugar, Nampa S-B 2 105
Amalgamated Sugar, Nampa S-B 3 250 242 1,008 1,660 1,787 1,697
Amalgamated Sugar Company, Paul S-B 1 200
Amalgamated Sugar Company, Paul S-B 2 200 155 608 306 217 1,322

Am alg am ate d S ug ar C om pa ny, T win Fa lls P-B 1 280

Am alg am ate d S ug ar C om pa ny, T win Fa lls P-B 2 268 203 599 1,364 1,053 1,053
Oregon

Boise Cascade c Power Boil er 6- 9 N/A 411 2,453 685 746 1,834
Amalgamated Sugar c B& W Bo ilers 204
Amalgamated Sugar c Foster Ril ey Boi ler 136
Amalgamated Sugar c Foster W heeler

Boil er 300 74 594 625 1,235 987

Ge orgia Pa cific W est c Power Boil er #1 Unknown 143
Pope & Talbot c Power Boil er #1 Unknown 107 39 161

W est Li nn Paper Co. a Boi le rs 1 & 2 365 211
Georgia -Paci fi c - Wauna c Power Boil er Unknown
Georgia -Paci fi c - Wauna c Package Boil er 18 277 254 165

W eyerh aeu ser S pring field Power Boil er Unknown 297

W eyerh aeu ser S pring field Package Boil er Unknown 65

W eyerh aeu ser S pring field Package Boil er 16 0

Utah
Sunnyside Cogenerati on Associates b FBC Boiler #1 700 1,270 0 1,006 970 1,054

Ke nne cott U tah C opp er C orp, N . Co nce ntato r b Un it 1 431

Ke nne cott U tah C opp er C orp, N . Co nce ntato r b Un it 2 431

Ke nne cott U tah C opp er C orp, N . Co nce ntato r b Un it 3 431

Ke nne cott U tah C opp er C orp, N . Co nce ntato r b Un it 4 838 700 2,905 2,141 2,200 2,534
Brigh am You ng U nive rsity Units 2, 3, and 5 128
Brigh am You ng U nive rsity Auxil iar y #7 5 0 248 90 158 125

Brush Wellman Inco rpor ated S-11 Main Boil er 81.2

Brush Wellman Inco rpor ated S-10 Back-up Boil er 12.66 23 161 175 208 179

### Table IV-3 (continued)

His to ri cal SO 2 Emissions

Fac ility Un it Capacity ( MM Btu/hr) SO 2 Floo r Allo catio n (tpy) 199 0 (tpy) 199 6 (tpy) 199 8 (tpy) 200 0 (tpy)

IV -8 Geneva Steel Po wer B oiler 1 411

Geneva Steel Po wer B oiler 2 411

Geneva Steel Po wer B oiler 3 411

Geneva Steel Po wer B oiler 4 205

Geneva Steel Po wer B oiler 5 205 17 8,473 2,020 881 979
Wyoming

So lvay M inera ls, Inc. b Boil er #18 350

So lvay M inera ls, Inc. b Boil er #19 350 294 101 72 52

Ge ne ral C he m ical b Bo iler C 534

Ge ne ral C he m ical b Bo iler D 880 750 4,196 5,651 4,538 5,000

Ho lly Sug ar-T orring ton P lant b 221 .2 23 374 266 154 178

FM C C orp - G reen Rive r Plan t b Boil er #6 887

FM C C orp - G reen Rive r Plan t b Boil er #7 887 956 4,795 5,256 4,533 4,901

Un iversity of W yom ing C entra l Hea ting P lant a Boil er #2 73.1

Un iversity of W yom ing C entra l Hea ting P lant a Boil er #3 73.1 22 152 154 223 193

Un iversity of W yom ing C entra l Hea ting P lant a Boil er #4 73.1
FMC Granger Boil er #1 358
FMC Granger Boil er #2 358 305 475 473 149 212

NOTES: a Fac il it

y wi th boi le rs as onl y SO 2 source

. b Fac ility has m ultiple so urce s, em ission s are total plan t.

c Fa cility ha s m ultip le so urc es , em issio ns are boile rs on ly.IV -9 

### Table IV-4 Example Use of

Capacity

Utilizati on Data f

or Floor A llocation E stimates

A B C D E F G H I J K L M N O P

Coal Oil Natural Gas

Fac ility Un it Year Throughput (ton/ yr) Heat Value

(MMB tu/ ton) Throughput

(gal/ yr) Heat Value (M M Btu /gal) Throughput

(MM cf/y r) Heat

Value (M M Btu /ft 3 ) Throughput

All Fu els Com bined (MM Btu/yr) Design

Ca pac ity (MM Btu/yr) Ca pac ity

Factor Primary

Fuel Sul fur Content ( % ) SO 2 EF

(l b/t on) SO 2

Reduction ( % ) SO 2

All ocati on (t ons)

Arizona

Abiti bi Consol idat ed Power Boil er # 2 1998 387,532 18.0 44,000 0.15 0.0 6,982, 176 70%

1,132 MMBtu/ hr 1999 353,163 18.0

- 0.15 0.0 6,356, 934 64%

2000 350,531 18.0 29 0.15 0.0 6,309, 562 64%

2001 327,428 18.0 193,000 0.15 0.0 5,922, 654 60%

18.0 9,916, 320 64% 1.00 35.0 85.0 978

NO TE : Thro ugh put is th e an nua l fuel co nsu m ption in the ca lend ar year.IV-10V-1 

## CHA PTER V PULP A ND PA PER I NDUSTRY

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

Th e pro cessin g of w ood for a va riety of p rodu cts is on e of th e ten large st indu stries in the U nited State s. To p rodu ce pa per o r pap erbo ard, w ood mu st be p ulpe d first. In ge nera l, the p ulp a nd p ape r prod uction proce sses ca n be divide d into three steps: pu lp m akin g, pulp processing, and paper/paperboard processing. The three basic types of pulping processes, which are the major sourc es of SO 2 , are ch em ical pu lping , me cha nical p ulpin g, an d sem ichemical pulpi ng. Chemic al wood pul ping i nvolves cooki ng wood chi ps or sawdust in an
aqu eous ch em ical solution to disso lve the lign in that bin ds the cellulo se fibers togeth er. Th ere a re tw o m ajor typ es of ch em ical pu lping use d: Kra ft/soda p ulpin g an d sulfite pulp ing. Kraf

t pu lpi ng ac count s f

or o ver 80 per cent of the c hemic al p ulp p rod uced in t he United States.

Sourc es of

SO 2 in a Kr aft mill inc lude : ( 1) b oil ers gener ati ng st eam for power and heat, usin g coal, oil, natural ga s, or bark/wo od w aste as fue l; (2) recovery furnace s wh ere SO 2 emiss ions occ ur f rom t he oxi dat ion o f r educ ed su lf ur c ompounds ; a nd ( 3) l ime ki lns when fuel oil i s being combusted.

All ocat ions fo r boi ler s ar e di sc usse d in Cha pte r I V, " Indus tr ial Boil ers and Co gen erato rs." Floo r alloca tions fo r recov ery fu rna ces an d lim e kiln s are d escribe d in th is chapt er. Note t hat t he cal culat ions f or t hese sour ces ar e the s ame as those for li ke configurations set f

orth in other chapters.



### 1. Recovery

Furnaces

After t he cooking peri od, t he pulp and the liquor in which it c ooked are separat ed, the spent liquor (black liquor) i s evaporated and con centrated to about 65 percent solids. Con centrated b lack liquo r is then spra yed into th e furna ce and the orga nic com poun ds are combuste d. The c ombustio n of bl ack l iquor in a re cover y fur nace re sult s in SO 2 emiss ions that vary wit h li quor pro per ti es ( i. e. , s ulf idi ty, heat val ue) , c ombust ion a ir and l iquo r f ir ing patterns, f

urnace design an d operational patterns.

SO 2 reducti on is achieved by al teri ng the proces s, r ather than applyi ng control tec hnolo gy. Str ate gie s t o lo wer l iquo r s ulf idi ty a nd opt imiz e co mbusti on and f ir ing p att erns in such way that yiel ds maximum and uniform temperatures i n the lower fur nace are used to mini mize SO 2 em issions. Flue gas desu lfurization is en ergy inten sive an d its efficiency uncert ain, consi deri ng the gene rall y low co ncentr ati ons and f luct uati ng level s of

SO 2 in t he furnace flue gases.



### 2. Lime Kilns

In a pul p and paper li me kiln, the i norgani c molt en smelt that for ms and col lec ts at the bo ttom of the furnace is w ithdraw n throu gh spo uts into a sm elt-dissolving tan k wh ere jets of w ater a re us ed to q uen ch th e m olten sm elt, form ing g reen liquo r. The gree n liqu or is t he n c omb in ed wi t h qu ic kl ime ( CaO)

, re su lt in g i n a w hi t e l iq uo r s ol ut io n c on t ai ni ng NaOH, Na 2 S an d l ime mud p re ci pi ta te ( mai nl y Ca CO 3 ). This li me mud is was hed, dri ed and calcine d in th e lim e kiln to rege nera te qu icklim e. Th e reg ene rated quick lime in the kiln acts as an in -situ-scru bbin g ag ent a nd th e V entu ri scrub ber th at us ually follow s the k iln fur ther reduc es SO 2 levels. Em issions from sme lt-dissolving tank s and lim e kilns are generally negl igibl e.V-2



### B. FLOOR ALLOCA TION ESTIMATION METHODS

The analysis was limit ed to pulp and paper f acil iti es that emit greater than 100 tpy of SO 2 from all pr ocesses. There are seven pulp and paper f acil iti es evaluated – si x locat ed in t he Stat e of Or egon and one i n Idaho. The Oregon Depart ment of Envi ronmental Quality provi ded data on the unit c apacit y for eac h Oregon facil ity. How ever, t he data given were the p ermit ted SO 2 em ission levels a nd the design ca pacity of produ ction of each

rec over y f

urnac e or kil n.

Abitibi in N avajo C oun ty, Arizona no lon ger ope rates a recov ery furna ce. They are no longer pulpi ng and have converted to r ecycl ed paper proc essing. Therefore, they recei ve no f loo r al loc ati on f

or r eco ver y f

urnac e ope rat ion.



### 1. Recovery

Furnaces

The floor allocation for rec overy furnaces is determined assum ing that the process provi des suf

fi cie nt SO 2 reduc ti ons. No furt her SO 2 reducti ons will be r equired when esti mating the fl oor all ocati ons. Pechan esti mated the floor alloc ation using t he emission fact or given in AP-42 in l bs/ai r-dr ied ton of pulp (ADT) and the designed pul p product ion
capac it y. The SO 2 fl oor all ocat ions are g ive n by t he equat ion:

where: A F = SO 2 all ocat ion f or r eco ver y f

urnac es i n the fac il it y, and EF SO2 = AP-4 2 emi ss io n f act or = 7 l bs/ ADT.

For f acil it ies wher e pulp p roduc ti on capac it y was not gi ven, but fuel thro ughput was
repor ted i n it s pl ace, SO 2 all ocat ions are e st imat ed as the f uel t hroug hput multi pli ed by t he EPA AP -42 SO 2 em ission factor.



### 2. Lime Kilns

The floor allocation for lim e kilns is determ ined in th e sam e m ann er as recove ry fur naces. The fl oor al loc ati on for li me kilns a ssumes no f urther SO 2 reduc ti ons wil l be
requ ir ed when es ti mati ng th e f loo r al loc ati ons. Using the e miss ion f act or f or l ime ki lns given i n AP-42, t he SO 2 floor alloc ation equati on for l ime kilns is given by:

where: A K = SO 2 all ocat ion f or l ime ki lns in t he f aci li ty, and EF SO2 = AP-4 2 emi ss io n f act or = 0. 3 l bs/ ADT.

For f acil it ies wher e pulp p roduc ti on capac it y was not gi ven, but fuel thro ughput was
repor ted i n it s pl ace, SO 2 all ocat ions are e st imat ed as the f uel t hroug hput multi pli ed by t he EPA AP -42 SO 2 em ission factor.



### C. FLOOR ALLOCA TION RESULTS

Ta ble V -1 pres ents th e floor a llocatio n ca lculatio ns for p ulp a nd p ape r plan ts in Ore gon bas ed o n th e pe rm itted cap acity o f the re cove ry furn aces a nd k ilns. U nit cap acity values were gi ven in ai r- dri ed tons of pul p per d ay. For the f loor cal culat ions, it was assumed that the fur nace was operated 365 days per year at 100 percent capacit y.V-3 Table V-2 presents the fl oor all ocati on for f acil iti es where the pulp produc tion
capa city w as n ot give n, bu t fuel th roug hpu t wa s repo rted in stead . The Potla tch facility listed in T ab le V -2 is lo cate d in Ida ho . All o the r pu lp a nd pap er m ills liste d in Ta ble s V -1 and V-2 are in Oregon. Theref ore, t he computed floor alloc ations by St ate are 1, 807 tpy for Idah o, and 5, 377 t py f or Or egon. The Cali for nia a ll ocat ion f or p ulp/ paper is base d on t he 1996, 199 8, and 20 00 hist ori cal SO 2 emissions dat a in Table V-3, and is 324 tpy.



### Table V-1 Facility SO 2 

### Floor A llocation E stimation for Pulp a nd Paper Faci lities

Based on Un it Capacity Values

Facility Un it Cap acity* (ADTP/d ay) SO 2 Allocations (tpy)
Boise Cascade Corpor ati on Recovery Furnace#2 450 575 Recovery Furnace#3 700 894

Lime Kil n#4 1,150 63

G eo rg ia- Pa cif ic (W au na M ill) Recovery Furnace 1,015 1,297

Lim e K iln 1,174 64

W eye rh au se r S pr ing fie ld #3 Recovery Boil er 1,150 760 #4 Recovery

Boil er 1,150 790

Lime Kil ns 2,156 118

NOTE: *Design and a ctual capacit y are unknown, the values given are the permitted level s.


### Table V-2 Facility SO 2 

### Floor A llocation E stimation for Pulp a nd Paper Faci lities

Based on Fuel Throughput

Facility Unit Fuel Throughput SO 2 Allocati ons (t py) Georgia-Pacific West, Inc. Recovery F urnace#1 DCE-BLS 242,725 tpy 129 Nat. gas Recovery F urnace#2 DCE-BLS 242,725 tpy 129 Nat. gas Lime Kiln#2 Nat. gas 553.7*10E6 ft3 /y 0 RFO #6 oil Lime Kiln#3 Nat. gas 553.7*10E6 ft3 /y 0 RFO #6 oil Willamette Industries, Inc. Recovery F urnace#5 BLS 495,000 tpy 235 Nat. gas 350 MM ft3 0 No.2 fuel oil 1E06 gal/y 39 Lime Kiln #3 Oil/nat.gas/LPG 1.35E05 ton lime mu d/y 36 Pope & Talb ot, Inc. Recovery F urnace BLS 461,081 tpy 67 Oil 1.2E06 gal/y 173 Lime Kiln CaO 55,536 tpy 0 Oil 1.8E06 gal/y 1 NCG/CaO 5,662 tpy 7 Potlatch #4 Recovery Boiler BLS 117,113 tpy 410 #5 Recovery

Boiler Pulp 393,548 tpy 1,377 #2 Lime Kiln CaO 10,247 tpy 2 #3 Lime Kiln CaO 61,467 tpy 9 #4 Lime Kiln CaO 60,147 tpy 9V-4



### D. COMPARISON WITH HISTORICA L EMISSIONS

Table V-3 s umm ariz es his tor ical SO 2 em ission s from pulp and pap er facilities. T his tab le pr ovi des a po int o f com pa rison wi th th e floo r allo catio ns s ho wn in T ab les V -1 a nd V-2 and hist ori cal emissi ons at each f acil it y. Not e that the hi sto ric al emis sions are t he tot al pl an t emi ss i on s, no t j us t t ho se r es ul t i ng f r om o pe r at i on of

t he r ec ov er y f

ur na c e a nd l i me kil n.

REFERENCES

AWM A, 20 00: Air and Wast e Management Asso ci ati on, “Ai r Pol lut ion Eng inee ri ng M anu al,” 2 nd edit ion, Chapter 18 -Wood Proc essi ng Indust ry, 2000.

EPA , 1998: U. S. Environmental Protec tion Agency, “Compilation of Air Pollut ant Emission Factors, AP-42, Fift h Edition, Volume I: Stati onary Point and Area Source, Secti on 10.2 Che mical W ood Pu lping,” Off ice of Air Quality Planning an d Standards, Researc h Triangl e Park, NC, 1998.V-5 

### Table V-3 Pulp and Pap er - Histo rical Emissions - 1990 to 2000

Sta te Sta te ID Co unty ID Fac ility

ID IAS

Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000
AZ 4 017 0007 43 2611 3 W oo d/P ap er/P ulp STONE CONTAI NER ABI TI BI 8,536 2,455 2,448 1,893
CA 6 023 21 10 2611 3 W oo d/P ap er/P ulp SIMPSON PAPER CO MPANY SI MPSON PAPER CO 1,021 315 315 CA 6 089 23 2611 3 W oo d/P ap er/P ulp SHAST A PAPE R- ANDERS ON 216
CA 6 013 3257 11 2611 3 W oo d/P ap er/P ulp GAYLORD CONT AI NER CORPORATI ON 263 0 0 CA 6 023 37 10 2611 3 W oo d/P ap er/P ulp LO UIS IAN A-P AC IFIC C OR P. 302 <100 42 42
CA 6 077 191 11 2621 3 W oo d/P ap er/P ulp NEW ARK SI ERRA PAPERBOARD CORP

. 270 0 0
ID 16 045 2611 3 W oo d/P ap er/P ulp BOISE CASCADE - EMMETT 252
ID 16 069 0001 3 2621 3 W oo d/P ap er/P ulp POTLATCH 1,379 700 700 1,694 OR 41 009 1849 6 2621 3 W oo d/P ap er/P ulp Boise Cascade Company 2,453 685 746 1,834 OR 41 041 0005 5 2631 3 W oo d/P ap er/P ulp Georgia-Pacif ic W est, I nc. 56 207 322 452 OR 41 019 0036 5 2631 3 W oo d/P ap er/P ulp Int ernat ional Paper 874 602 1,006 0 OR 41 007 0004 5 2621 3 W oo d/P ap er/P ulp James R iver I I, Inc. Ge org ia- P ac ific (W au na Mill) 331 573 617 643 OR 41 043 3501 5 2621 3 W oo d/P ap er/P ulp Pope & T albot Pulp, Inc. 485 133 92 293 OR 41 071 6142 5 2621 3 W oo d/P ap er/P ulp Smurfit Newspri nt Corp orat ion 2 592 368 461 519 OR 41 043 0471 5 2631 3 W oo d/P ap er/P ulp W il lamette I ndustri es, I nc. 396 54 485 327 OR 41 039 8850 5 2631 3 W oo d/P ap er/P ulp Colli ns Product s LLC W eyer haeuser Co. (Par ti cleboa rd) 202 0 3 1,721 OR 41 047 5398 5 2621 3 W oo d/P ap er/P ulp Ogden Martin Systems of Mari on, I nc. Covanta Marion, I nc. 127 18 22 17,287 6,210 7,259 9,886V-6VI -1 

## CHAPT ER VI CEMENT MA NUFA CTURI NG

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

The ce ment i ndust ry i nvol ves t he ca lc ini ng of li mesto ne in cl inke r and the subsequent crushi ng of the cl inker int o cement. Cement man ufactur ing acti viti es incl ude the process the mining a nd m ixture of raw materials such as limestone a nd other m aterials, the p ryo pro ces si ng of the r aw mater ial s i nto a cl inke r, and t he gr indi ng of the c li nker and other m aterials such as silicates into the fina l ceme nt. As of D ecem ber 20 00, there w ere 201 kil ns wit h a tot al c apaci ty of 84 mill ion t py. The kil n is a p redominat e sourc e of SO 2 emissi ons. The SO 2 emiss ions res ult fr om the c ombust ion o f t he sul fur in t he f uel a nd t he sulf ur ( general ly i n the f orm of py rit e) t hat ca n occur in t he feed sto ck.

Kilns generally take five forms:



### ! we t (wh ere the feed stock con tain s up to 4 3 pe rcen t wa ter);


### ! dry;


### ! semi-dry;


### ! dry w ith a pre-he ater; 

### ! and d ry with a pre-calciner.

SO 2 emiss ions vary by ki ln t ype g ener all y bas ed on ho w eff ect ive ly t he ki ln t ype mi xes t he SO 2 containi ng gases with the al kaline cal cium compounds. The pre-heater and precalc iner kil ns can r emove 90+ perc ent of the SO 2 in the gas stream w hile the dry process kil n removes about 70 perc ent. In addi ti on, t he type of par ti culat e cont rol devic es can impact the amount of SO 2 remove d in t he pr oce ss. Fabri c f il ter s, bot h bec ause t hey mix the SO 2 conta inin g ga ses w ith the particle s collecte d on the filter, a nd b ecau se the y op erate at a general ly l ower te mperatur e then el ect rost ati c par ti cip ator s (ESPs) , c oll ect more SO 2 than ESP s.



### B. FLOOR ALLOCA TION ESTIMATION METHODS

Esti mation of

the f loor all ocat ion pr ocedur e for the c ement indus try poses sever al dif fi cult ies. Firs t, ther e is no demonstr ated c ontr ol t echnol ogy f or c ontr ol of

SO 2 emiss ions fr om cement kil ns. Sec ond, emiss ions fr om kil ns var y co nsi der ably due t o numerou s vari ables incl uding ki ln t ype and sul fur cont ent of feed sto ck. Accor ding t o EPA AP-42 emi ss io n f

ac to rs , emi ss io ns ca n va ry by a s muc h as a f ac to r o f 20. Emis si on d at a f ro m two si mila r ki lns in Ut ah shows that chang es i n fe edst ock c an caus e a ch ange i n emiss ions up to a fac tor of

100. Becaus e of

thi s var iabi li ty a nd la ck of pre dic tabi li ty o f e miss ions , t he fl oor al loc ati on was based on t he average emissi ons f rom each pl ant over the pas t se veral
years.


### C. FLOOR ALLOCA TION RESULTS

Table VI-1 shows the all ocati on result s of t he emissions to eac h plant. As discuss ed above, the data are ba sed on the em issions reported in State i nventories unless otherw ise indi cat ed (Se e Table VI- 2). Several of t he sourc es added new kilns in t he past sever al
yea rs. For th ese so urces only em ission data after th e ne w k iln w ere in clude d. Pe rm itVI -2 

### Table VI-1 Floor Allocations

State Pl an t Na me SO 2 Floor Allocation (tpy) State T otals (tpy)
AZ Phoenix Cement

Portl and Cem ent Pl ant 320 1

320
CO Holci m Portland 3,374
CO Ho lcim Lap orte 1,402
CO Cem ex 160 4,936
ID Ash Grove Inkom 522
522
NV Nevada Cem ent 305
NV Royal Cem ent 143 2
448
NM Rio Grande 1,103 3 1,103
UT H olc im 267 2
267
W Y Centex 165 4
165
TOTA L 7,761 7,761

NOTES: 1 Pe rm it lim ited po ten tial to em it.

2 Only two y ears a ft er new k il n inc luded.

3 Only one ye ar of

data a vail able.

4 New kil n in 199 7.VI -3 

### Table VI-2 Cement Man ufacturin g - Histo rical Emissions - 1990 to 2000

Sta te Sta te

ID Co unty ID Fac ility

ID IAS Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000
AZ 4 019 3241 4 Ce m ent/C onc rete Ariz ona Port land Cement 101 13 10 8
AZ 4 025 41 3241 4 Ce m ent/C onc rete Phoenix Cement <100 197 339 539 CA 6 029 9 13 3241 4 Ce m ent/C onc rete CA L P OR TL AN D C EM EN T C O. 429 245 245 245
CA 6 029 20 13 3241 4 Ce m ent/C onc rete CALA VERAS CEMENT CO 286 286 286 286 CA 6 085 17 11 3241 4 Ce m ent/C onc rete KAI SER CEMENT CORPORA TI ON HANSON PERMANENT E CEMENT 474 464 416 474 CA 6 087 11 11 3241 4 Ce m ent/C onc rete LONE STAR I NDUST CEMENT PLANT RMC P ACIFI C MATE RIALS 250 286 393 314
CA 6 071 7000000 15 3241 4 Ce m ent/C onc rete MI TSUBI SHI CEMENT 28 574 946 298
CA 6 071 1200003 15 3241 4 Ce m ent/C onc rete RI VERSI DE CEMENT COMP ANY 0 527 527 164
CA 6 071 100005 15 3241 4 Ce m ent/C onc rete CEMEX- CALI FORNI A CEMENT 0 0 0 427 CA 6 071 15 3241 4 Ce m ent/C onc rete SOUTHW ESTERN PORTLAND CEMENT C SOUTHDOWN-VI CTORVI LLE PLANT 108 0 0 0 CO 8 069 0002 52 3241 4 Ce m ent/C onc rete HOLNAM LAPORTE H O LC IM 623 623 375 404 CO 8 043 0001 58 3241 4 Ce m ent/C onc rete HOLNAM PORT LAND H O LC IM 4,069 3,615 3,219 3,288 CO 8 013 0003 53 3241 4 Ce m ent/C onc rete SOUTHWEST PORTLAND CEMEX- LYONS PLT. 967 160 160 50
ID 16 005 0004 7 3241 4 Ce m ent/C onc rete ASHGROVE CEMENT 790 200 200 1,327
NV 32 019 0387 20 3241 4 Ce m ent/C onc rete NEVADA CEMENT COMPANY FERNLE Y PLA NT 360 340 346 172
NM 35 001 3241 4 Ce m ent/C onc rete RI O GRANDE PORTL AND CEMENT 0 0 0 1,103
UT 49 029 0001 31 3241 4 Ce m ent/C onc rete Holnam Incor porat ed H O LC IM 911 3 247 288 9,496 7,533 7,709 9,387VI -4

limits were select ed, si nce the kil n is under const ructi on and there was no actual emissi on dat a. Table VI- 3 pr ovi des a n exampl e of thi s c alc ulat ion.



### Table VI-3 Example Calculation

Facility SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000 Floo r

Estim ate 1

Nevada Cem ent 340 346 172 286

Ho lcim Lap orte 632 375 404 470

1 Floor esti mate base d on the average o f these 3 years.



### D. COMPARISON WITH HISTORICA L EMISSIONS

Table VI-2 shows a comparison of emissions t o the hist oric al emissions bas ed on Stat e emissi ons inve ntor ies. Since the f loor is bas ed on his tor ical emissi ons, the gener al match is very c lose , but for any indi vidual plant , t he fl oor may be hig her or lower t han recent emissions.

REFERENCES

EPA , 1995: U. S. Environmental Protec tion Agency, “Compilation of Air Pollut ant Emission Fa ctors (A P-42 ),” Cha pter 1 1.6, C em ent M anu facturin g, Office o f Air Q uality Planning and S tandar ds, Researc h Triangl e Park, NC, 1995.

PC A, 200 1: Portland Cem ent A ssociation, U.S. an d Ca nadia n Po rtland C em ent Ind ustry Plant Inf

ormat ion S ummary, Data as of December 31, 2000, Port land Cement Associ ati on, Eco nomic Resear ch Depart ment, 2001.VI I-1 

## CH APT ER VII NATURAL GA S PROC ESSING PLANTS

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

SO 2 emiss ions fr om natur al g as pr oce ssi ng pl ants res ult fr om the c ombust ion o f s our gase s. Sou r gase s m ay co ntain less th an 1 perce nt H 2 S to o ver 2 0 pe rcent H 2 S.

H 2 S is remove d f

rom t he nat ural gas b y sc rubbi ng wit h an amine s olut ion. The amine solution is heated to reg enerate the amine solut ion. Heati ng the amine also produces a very concent rated H 2 S stream. This H 2 S st ream c an be t reat ed t o pr oduc e sul fur . The most co mm on tr eatment i s by usi ng a Claus pl ant. The Claus pl ant ca n conver t about 80- 98.6 perc ent of t he H 2 S to sulf ur depending on the number of stages and t he concentrat ion of H 2 S. The ave rage r ecover y perc entage f or a 3- stag e Claus pl ant would be about 96
perce nt, on ave rage . The residu al H 2 S after the C laus plan t is eithe r flared o r conv erted to additional sulfur in a "tai l gas" treatment plant like the SCO T or Stretford- Beavo n process. H 2 S con versio n efficien cies of u p to 9 9.9 pe rcent a re po ssible . Resid ual H 2 S may be flared.

In addi ti on to t he plant tai l gas fl are, SO 2 emissions als o result from upset cond it ions at t he pl ant, or i n the well fi eld , o r emi ssi ons when ne w well s ar e bro ught in. Upsets at t he plant cause t he sulfur r ecovery pl ant to be bypassed and t he H 2 S is flare d to produc e SO 2 . Upse ts in th e w ell field m ay re sult in sou r na tural g as b eing flared a s a sa fety
pre cau tion to re du ce e xpo sur e to t oxi c lev els o f H 2 S.



### B. FLOOR ALLOCA TION ESTIMATION METHODS

Th e re qu irem en ts for, a nd the eco no m ics of, s ou r ga s con trol a re a fun ction of a

nu m be r of v aria ble s, inc lud ing the am ou nt o f H 2 S in t he of fg as, the s ize and age of the fac il it y, and the ai r pol luti on cont rol requi rements i n exis tenc e at t he ti me the fac il it y was buil t. Exis ti ng so ur ga s pr oce ssi ng pl ants may have be en bui lt in s it uati ons wher e no regulati ons exist ed, under t he 1987 NSP S, or under a BACT review under prevention of signific ant deterioration regulations.

It was decided that the current NSP S wou ld serve as the floor. The N SPS requ ires a variable s ulfur r emoval effi ciency based on t he H 2 S co nten t of the a ci d gas and t he amount of sul fur in t he gas . The requ ir ed emis si on re duct ion f or e ach f

aci li ty was base d on t he
equa tions in T able V II-1 since these are the lon g term reduction s called for in the N SPS . If a faci lit y had current c ontrol l evels higher than the assumed floor , t he actual average emissions over t he past thr ee years were assumed to be the f loor. Since emissi ons from flar ing operati ons, bot h in the plant and t he well fi eld, are not amenable to contr ol, floor

em ission s will b e ass um ed to b e the ave rage of thre e ye ars em ission s, wh ene ver th e da ta is available.VI I-2 

### Table VII-1 Sulfur Plan ts - Requ ired Minimu m SO 2 

### Emission Red uction Ef ficiency

H 2 S Conte nt of Acid Ga s (Y ), % Sulfur Feed Rate (x), Long To ns per Day
2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 300 .0 X> 300 .0

Y > 50 74.0

. . . . . . . 85. 35X 0.0144 Y 0.0128

. . . . . . .

or 99. 8, whi chever i s smaller

20 < Y<50 74.0

. . . . 85.35X 0.0144 Y 0.0128

. . . .

or 97. 5, whi chever i s smaller 97.5

10 < Y<20 74.0 85.35X 0.0144 Y 0.0128

or 90. 8, whi chever i s smaller 90.8 90.8

Y<10 74.0 74.0 74.0 74.0

Dat a a va i l ab i l i t y w as a s i gn i f i c an t i ss ue i n d et er mi ni ng t he f l oo r al l oc at i on f

or so me plan ts. The data from Ne w M exico wa s no t ade qua te to distin guish betw een proce ss plan t, upset flare, and well fiel d emissions.



### C. FLOOR ALLOCA TION RESULTS

1. General Plants

Table VII- 2 shows the f loo r al loc ati on ca lc ulat ion f or t he nat ural gas p roc ess ing plants in the 8 non-C alifornia Western Region al Air Partnership (WR AP) States.

In T able VII-2 , the pla nt n am e an d SC C co de a re tho se pro vided in the State inven tory. The e mission source colu mn (process or flare) notes w hethe r the em issions are likel y to come fr om the normal processing of natural gas ( process ) or t he result of upset or well fi eld emiss ions (f lar e). The di st inc ti on was made o n the basi s of comments in t he

em ission inve ntory an d confirm ed in con versation s with th e State. Cu rrent em issions are ba sed on the av era ge o f sev era l ye ars d ata (20 00 , 199 8, 19 96 ) if av aila ble , an d on on e ye ar's data if that was all that was availabl e. In some cases , new plants were under c onstruct ion and pe rmit lev els were us ed i n li eu of act uals . Cur rent red uct ions were b ased on dat a in t he State inventories and confirmed via conve rsations with State agencies.

Floor emissi ons vary by the H 2 S cont ent of the gas , t he amount of s ulf ur pro duced by the p lant, th e ag e of th e pla nt (olde r plan ts are n ot sub ject to the NS PS ), and S tate regulati ons. In Wyoming, alt hough individual pl ants vary, the average H 2 S content of natur al g as i s hi gher than i n oth er S tat es and the d egr ee of cont rol requ ir ed unde r t he NSPS is gr eat er

. In add it io n, newe r p la nt s t end to be l ar ger and hav e un der gon e a B ACT

re vi ew. In New Mex ic o, th e r el at iv el y l ow H 2 S cont ent means t hat l ess c ontr ol may be required under t he NSPS. This is due both to t he H 2 S co nten t as well as t he smal l amount of su lf ur pr odu ce d by th e p ro ce ss in g p la nt s. Howev er , a St at e r ul e ( 20. 2. 35 NMAC) requires a minimum of a 90 perc ent reduct ion for plants t hat releas e more than 5 tons per day of sulf

ur from exist ing plants regardl ess of t he H 2 S content of the gas.

The le vel of

cont rol ass umed to be t he f loo r wil l be the mos t s tr inge nt of all of the potenti al regulat ory requir ements. However, the appl icat ion of t he potential floor
proc edures can re sult in no SO 2 control s having to be appli ed on some sources. For example, the Duke Energy Artesia pl ant in New M exico pr ocesses less t han 2 long tons per day of sulf ur ( this is e quival ent t o about 1, 600 tpy o f SO 2 emiss ions ) and ther efo re t he NSPS does not apply. St ate regulat ions do not appl y, si nce the sulf ur throughput i s below the r egul ato ry t hres hold . The fl oor fo r t his pla nt i s bas ed on t he aver age emi ssi ons o ver the past three years.VI I-3



### 2. Specific Examp le

The Burli ngton Nort hern Lost Cabin fac il it y in Wyoming pro vided addit ional inform ation nee ded to dem ons trate h ow the floo r calcu lation s cou ld be app lied to a specific facility. Th e Lo st Ca bin fa cility con sists of tw o ex isting g as pro cessin g line s with a cap acity of 133 MM CF/day and has one new trai n with a capacit y of 133 MM CF/day. Both li nes process a gas with a methane concentrati on of 68 percent , a car bon dioxide conc entrati on of 20 per cent , a nd an H 2 S con tent o f 12 p ercen t.

Ea ch train is con trolled b y a th ree sta ge C laus un it follow ed b y a S CO T tail g as u nit. The unit is requ ired to hav e a con version e fficiency of 99.8 percen t. Plantw ide em issions are limited to 642 lbs/ hr and 1,367 tpy.

The pl ant und erwent a BACT revi ew under PSD and exc eeds all requ ir ements of the NSPS. Under t he NSPS, a red uct ion o f 97 .5 per cent would have be en re quir ed si nce t he H 2 S co nten t of

the a ci d gas st ream i s 37 p erc ent ( whic h is def ined as t he gas st ream l eavi ng the am ine reg en era tor a nd can be calcu late d as the ratio of th e a cid g ase s [H 2 S an d CO 2 ] in the in put g as stre am ) and the su lfur pro ductio n ex ceed s 30 0 lon g ton s per d ay (se e Ta ble VII- 1). Sinc e the requ ir ed r educ ti on exc eeds the f loo r l evel , t he per mitt ed l evel s r epr esent the floor.

Sinc e much of

the p lant is new, n o dat a on ups et e miss ions is avai labl e. Emiss ions from w ell-field activities are very varia ble. We lls are very larg e at this plan t and on e very larg e well c an have up to 1,000 t ons of emissi ons. The plant est imates that annual SO 2 emissions of

about 500 tpy fr om w ell f ield ac tivi ties can be expected.



### D. COMPARISON WITH HISTORICA L EMISSIONS

Table VII -3 s umm ariz es his tor ical SO 2 em ission s from natu ral ga s proce ssing plan ts locate d in th e 9 W RA P S tates. C aliforn ia facilities are in clude d in th is table . This ta ble provides a point of

comparison with t he floor alloc ations s hown in Tab le VII- 2. For Wyom ing, t he histor ic emissi ons are cl ose to f loor f or most sourc es due to the hi gh level of control . However, a dir ect c omparison is di ff icult since t he histor ical emissions may include well fi eld and upset emissi ons. Two New M exico sour ces will require addi tional c ontrol or additional emission allocations.VI I-4 

### Table VII-2 Possible Floor - Natural Gas Processing Units

State Plant SCC Emissio n Source (Proc ess vs Fl are) Current % Reducti on Pe rm it Emissio ns Floo r

Emissio n Reducti on Po ss ible

SO 2 Floo r (tpy)
NM Conoco-Mal jamar 31000028 Plant 0 3,574 87 222
NM W estern Gas Reso urces 31000208 Plant 90 3,127 90 3,127
NM Agave Energ y 31000205 Plant 0 2,983 86 .3 365
NM Duke Energy

Eunice 31000208 Plant 90 2,756 90 2,250

NM Duke Energy

Arte sia 31000208 Plant 0 1,459 0 1,192

NM Dyner gy Mi dst ream

Monument 31000208 Plant 90 1,431 90 675

NM Dyner gy Mi dst ream

Sau nde rs 31000208 Plant 90 1,387 90 163

NM Duke Energy

Pla nt 5 31000205 Plant 96 .4 1,300 96 .4 1,181

NM Sid Ri chards on 31000201 Plant 91 .7 1,206 91 .7 1,206
NM JL Davi s Gas Proc essi ng

Denton Pl ant 31000205 Plant 0 1,158 0 840

NM M ara thon Oil 31000201 Plant 90 1,100 90 665
NM Duke Energy

Lee Gas 31000299 Plant 93 818 93 0 4

NM ARCO Permian

Empire Abo Pl ant 31000208 Plant 96 565 96 431

NM Duke Energy

Bu rton Fla ts 31000205 Plant 0 246 0 164

NM Duke Energy

Dagger Draw Pl ant 31000208 Plant 98 243 98 218

NM Duke Energy

Huber Gas Pl ant 31000205 Unknown 0 231 0 163

UT Tom Brown- L isbo n Plant Plant 95 1,593 2 95 1,593
W Y Ho we ll Pe troleu m - Elk B asin 31000205 Plant 93 .5 1,200 93 .5 1,200
W Y Burl ingt on Resourc es

Lo st C ab in Plant 99 .8 1,367 2 99 .8 1,367

W Y Burl ingt on Resourc es

Lo st C ab in Flare 0 500 1 0 500

W Y KC S M ou ntain

Ains worth Flare 31000205 Flare 0 843 0 843

W Y KC S M ou ntain

Ru shm ore F lare 31000205 Flare 0 118 1 0 118

W Y Ma rathon Pitchfo rk Ba ttery 31000205 Flare 0 61 1 0 61
W Y Exxon Shute Cr eek 31000205 Plant 99 .7 1,206 99 .7 1,206
W Y Exxon Shute Cr eek 31000205 Flare 0 330 1 0 330
W Y Amoco W hit ney Cany on 31000205 Plant 99 5,379 99 5,379
W Y Amoco W hit ney Cany on 31000205 Flare 0 223 1 0 223
W Y Texaco Byr on 31000205 Plant 0 200 0 200

### Table VII-2 (continued)

State Plant SCC Emissio n Source (Proc ess vs Fl are) Current % Reducti on Pe rm it Emissio ns Floo r

Emissio n Reducti on Po ss ible

SO 2 Floo r (tpy)

VI I-5 W Y Chevron Car ter Creek 31000205 Plant 99+ 0 3 0
W Y Chevron C arter Creek 31000205 Flare 0 200 0 200
W Y Hall wood Petr oleum Federal Packsaddl e 1-24 31000205 Flare 0 133 0 133

W Y Hall wood Petr oleum Federal Packsaddl e 1 31000205 Flare 0 960 1 0 960

W Y Oregon Basi n Gas Plant 31000205 Plant 90 391 90 391
W Y KC S G old E agle Flare 31000205 Flare 0 790 0 790
W Y Int erener gy

Hil and Gas Pla nt 31000205 Flare 0 281 1 0 281

W Y M ara thon Oil

Mill Ir on 31000205 Flare 0 247 0 247

Em iss ion To tals 39,606 28,884

NOTES: 1. Only

one y ear of d at a avai lab le; 2. Fl oor based on per mit le vel s; 3. Pla nt does n ot in ci ner at e t ail gas - no SO 2 emit ted; 4. Pl ant ha s no emis sion s li ste d for the past t hree years. Sta te SO 2 floor alloc ations bas ed o n the e stima tes in this tab le are N M (1 2,862 tpy), UT (1,5 93 tpy), an d W Y (14,42 9 tpy).VI I-6 

### Table VII-3 Oil and Gas Pr

oduction - Histor ical Emissions - 1990 to 2000

Sta te Sta te ID Co unty ID Fac ility

ID IAS

Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000

CA 6 029 1141 13 1311 6 Oil/ Gas SANTA FE ENE RGY TEXACO CA I NC 1,539 855 2,050 2,050

CA 6 029 1129 13 1311 6 Oil/ Gas TEXACO E XPL OR & PROD I NC 1 89 112 63

CA 6 029 206 13 1311 6 Oil/ Gas BERRY PETR OLEUM COMP ANY 237 0 0 0

CA 6 019 71 12 1311 6 Oil/ Gas CHEVRON USA I NC. - COALI NGA 809 0 0

CA 6 029 272 13 1311 6 Oil/ Gas M H WHITTI ER SENECA RESOURCES 347 0 0

CA 6 053 19 12 1311 6 Oil/ Gas MOBI L OI L COR P - SAN AR DO AERA E NERGY 304 0 1 6

CA 6 029 1135 13 1311 6 Oil/ Gas SHELL KERNRI DGE AERA ENER GY LLC 294 <100 82 55

CA 6 019 64 12 1311 6 Oil/ Gas SHEL L WESTERN E &P I NC. - COAL I NGA 144 0 0

CA 6 029 331 13 1311 6 Oil/ Gas SW EPI -WEST COAST DI VI SI ON AERA ENER GY LLC 775 <100 10

CA 6 053 30 12 1311 6 Oil/ Gas TEX ACO I NC - SAN AR DO 100 <100 36 32

CA 6 029 299 13 1311 6 Oil/ Gas UNOCAL - BAKERSFI ELD UNOCAL OI L & G AS DI VI SI ON 159 0 0

CA 6 059 42775 14 1311 6 Oil/ Gas W EST NE W PORT OI L CO 297 <100 10 11

CO 8 045 24 51 1311 6 Oil/ Gas UNOCAL RETORT-PARACHUTE 679 0 0 0

CO 8 045 0025 51 1311 6 Oil/ Gas UNOCAL UPGRADE 177 0 0 0

NM 35 015 0024 65 1311 6 Oil/ Gas AGAVE ENERGY/ YATES PL ANT 962 962 962 2,983

NM 35 015 0002 65 1311 6 Oil/ Gas ARCO PERMI AN/ EMPI RE ABO GAS PL NT 700 565 565 565

NM 35 015 0006 65 1311 6 Oil/ Gas GPM GAS/ I NDI AN HI LLS AMI NE PLNT 900 450 450 900

NM 35 025 0046 65 1311 6 Oil/ Gas GPM GAS/ LEE GAS P LANT 818 0 818 818

NM 35 025 0007 65 1311 6 Oil/ Gas J. L. DAVI S GAS P ROCESS/ DENTON 385 890 891 1,158

NM 35 025 0052 65 1311 6 Oil/ Gas TEXACO/ EUNI CE NORTH GAS PL ANT 673 1,076 1,346 673

NM 35 025 0051 65 1311 6 Oil/ Gas TEXACO/ EUNI CE SOUTH GAS PL ANT 4,019 4,386 3,355 5,476

NM 35 015 0003 65 1311 6 Oil/ Gas TRANSWESTERN PIP E DUKE ENERGY/ HUBER GAS 221 231 231 231

NM 35 041 0001 63 1311 6 Oil/ Gas W ARREN PETROL EUM/ BLUI TT GAS PL ANT 270 3,348 582 270

NM 35 025 0061 65 1311 6 Oil/ Gas W ARREN PETROL EUM/ MONUMENT PL ANT MONUMENT PL ANT 1,460 1,709 1,432 1,432

NM 35 045 0247 60 1311 6 Oil/ Gas W ESTERN GAS PROCES SORS/ SAN JUAN R VR 5,475 980 980 3,138

NM 35 025 0128 65 1311 6 Oil/ Gas CI TATI ON/A NTELOPE RDG GAS PLANT 291 0 NA

NM 35 025 0118 65 1311 6 Oil/ Gas CON OCO /BELL LAKE 2 W ELL #6 129 0 NA

NM 35 015 0125 65 1311 6 Oil/ Gas FEAGA N ENE RGY/W DAGG ER DR AW GAS P LT 240 0 NA

NM 35 005 0050 65 1311 6 Oil/ Gas YATES PET ROLEUM/ PATHFI NDER AMI NE 227 57 57

### Table VII-3 (continued)

Sta te Sta te ID Co unty ID Fac ility

ID IAS

Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000

VI I-7 UT 49 037 35 1311 6 Oil/ Gas UNOCAL CORPORA TI ON TOM BROWN - LI SBON PLANT 1,575 1,391 1,478 1,252

W Y 56 029 0012 9 1311 6 Oil/ Gas AM O C O - E LK BA SIN H O W EL L P ET R O LE U M - EL K B AS IN 1,096 1,218 1,422 2,638

W Y 56 041 0012 9 1311 6 Oil/ Gas AMOCO - WHITNE Y CAN YON 6,401 5,835 11,130 6,889

W Y 56 041 0009 9 1311 6 Oil/ Gas CHEVRON - CARTER CREEK 1,537 1,165 3,330 2,096

W Y 56 023 0013 8 1311 6 Oil/ Gas EXX ON - SHUTE CREEK 1,078 1,999 2,015 1,383

W Y 56 1311 6 Oil/ Gas EXXON BLAC K CAN YON DE HY & W ELL FIELD 167

W Y 56 017 9 1311 6 Oil/ Gas KCS MO UNTA IN RESOU RCES - GOLDEN E AGLE 558 942 17

W Y 56 003 9 1311 6 Oil/ Gas KCS MOUNTAIN RESOURCES - AI NSW ORTH 807 845 0

W Y 56 029 0007 9 1311 6 Oil/ Gas MA R AT H O N G AS PL AN T - O R EG O N BA SIN 406 456 388 358

W Y 56 017 9 1311 6 Oil/ Gas MARAT HON OI L - MI LL I RON 234 260 0

W Y 56 003 0012 9 1311 6 Oil/ Gas TEXAS- BYRON PL ANT BI G HORN GA S PROCE SSI NG - BYRON 192 169 605 257

W Y 56 037 0008 9 1311 6 Oil/ Gas UNI ON PAC - BRADY RME PETRO LEUM - BRADY 415 331 576 300

W Y 56 013 008 9 1311 6 Oil/ Gas DEVON S FS OP ERATI NG CO. BEAVER CREEK 831

W Y 56 037 0014 9 1311 6 Oil/ Gas COLORADO I NTERSTATE GAS - TABLE ROCK 522 20 39

W Y 56 003 0013 9 1311 6 Oil/ Gas MARATHON OI L COMPANY - GARLAND 257 7 10

W Y 56 013 9 1311 6 Oil/ Gas LO U ISIA N A L AN D & E XP LO R - LO ST CA BIN BU R LIN G TO N RE SO U R C ES -LO ST CA BIN 4,547 1,336 1,700

36,111 34,735 38,346 37,749VI I-8VI II-1 

## CH APT ER VIII ELEMENT A L PHOSPH ORUS PRODUC TI ON

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

P4 Pro ductio n h as a n ele m enta l pho sph orus facility n ear S oda Sprin gs, Ida ho. T his is one of t he two el emental phos phorus p roduc ti on fac il it ies i n the Unit ed Stat es. Year 2000 SO 2 emissions f rom this f

acil ity ar e esti mated to be 15,861 tpy. This ref lect s incr eased util izat ion c ompared wit h 1996 and 1998 oper ati ons. This f acil it y has no SO 2 emiss ions limit in its ope rating perm it. The Idah o D epa rtme nt of E nviro nm enta l Qu ality is cu rrently evaluat ing t his f

acil it y’s SO 2 emissions si tuation. For the purposes of thi s report , t he floor all ocat ion f

or P4 Prod ucti on is s et at it s year 2000 SO 2 em ission s leve l of 15 ,861 tons. It is
exp ected that th e Sta te of Ida ho w ill perform a m ore d etaile d ev alua tion o f this facility du ring pre pa ratio n o f its reg ion al h aze Sta te Im ple m en tatio n P lan (SIP ).



### B. FLOOR A LLOCA TION ESTIM AT ION PROCED URES

Recent hi sto ric al emis sions for P4 Product ion ar e li ste d below i n Table VII I- 1.VI II-2 

### Table VIII-1 Elemental Pho sphorus Pro duction - Historical Emissions - 1 990 to 2000

Sta te Sta te

ID Co unty ID Fac ility

ID IAS Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000
ID 16 029 0001 7 2819 5 Chem icals/ Plasti cs MONSAN TO/ P4 P RODUCTI ON P4 P RODUCTI ON 7,543 7,988 7,601 15,861IX-1 

## CH APT ER IX GLA SS MA NUFA CTURI NG

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

The air e missi ons f

rom glas s manufact uring a re i n three zones: (1) raw materi al blen ding and trans port, (2) m elting , and (3) form ing a nd fin ishin g. Th e m ajority o f air emiss ions are i n the melt ing f urnac e ope rat ion.

Melt ing f

or c onta iner and f

lat gla ss i s gen eral ly c onduc ted in a c onti nuous reverbator y furnace f ired by natur al gas or oi l. Electr ic boost furnaces have been introduced in some o perations to minim ize flue gas emissions.

The major so urce o f SO 2 emiss ions in t he gl ass indu st ry i s t he gl ass melt ing
oper ati on. Formi ng and an neal ing o per ati ons ar e minor sour ces . Fur nace emiss ions
app ear to be a ttributa ble to both the m anu facturin g pro cess a nd th e fue l burn ed. F uelderi ved SO 2 emissions are l ower from natural gas- fir ed furnaces t han from oil- fir ed fur naces, unless the oi l has be en desul fur ized . Fl ue gases fr om furnac es burni ng natura l gas have bee n repor ted t o cont ain 2 par ts p er mil li on (pp m) SO 2 , or l ess. About 600 ppm SO 2 can be expe ct ed i n fl ue gas fr om a fur nace burni ng f uel o il cont aini ng one p erc ent sulf ur. Greater use of

elec tri c f

urnaces or el ect ric boost ing may decr ease SO 2 emissions.

Proces s modif

icat ions t hat may reduc e SO 2 emissi ons inc lude al ter ing t he raw material charge to reduce the sulfur content or to increase the fracti on of recycled glass, changing the furna ce controls or equipment, and altering the pull rate. Process

mo difications that redu ce the salt cak e conten t in the raw batch ca n significan tly reduce SO 2 em issions. For ex am ple, one C alifornia flat-glass plan t reportedly redu ced furna ce emissi ons of

SO 2 by 78 pe rce nt f rom 2.1 to 0 .5 k ilo gra m s pe r m eg ag ram (kg /M g) (5 .0 to 1.1 lbs/ ton) by reduc ing t he salt cake i n the r aw batch 60 pe rce nt ( fr om 12 to 5 kg/ Mg, 30 to 12 lbs/ton of san d). Sim ilarly, an othe r Ca lifornia flat-glass plan t has repo rtedly re duce d its SO 2 em issions 75 percent (from 1.6 to less than 0.4 kg/M g, 4 to less than 1 lbs/ton of ba tch

cons tituen ts) by re ducin g the inpu t of salt ca ke. G lass q uality wa s no t com prom ised in eit her c ase. The sal t c ake c annot be re duce d bel ow cer tai n minimums wi thou t ef fec ti ng glass qua lity. Th e m inim um salt cak e req uired varie s dep end ing u pon furna ce type , pull rate, glass t ype, and other variables.

Fuel change s have al so been s hown to red uce SO 2 emissions. These include swit chi ng to natur al g as or low- sul fur fue l oi l, swit chi ng to all -el ect ri c mel ti ng, and us ing elec tri c boos ti ng for melti ng. El ect ric melter s si gnif icant ly r educe SO 2 , NO

x , a nd particu late e m ission s beca use they elim inate the co m bus tion o f fossil fuels . Electric melti ng also is r eport ed to mini mize SO 2 and other gaseous los ses fr om the vaporizati on of raw materials because t he surface of the melt is insulated by a semisolid c rust. Gases dis ch arg ed thr ou gh the cru st o f th e m elt c on sist m ain ly o f ca rbo n d iox ide an d w ate r. Today, boro si li cat e, opal , a nd gr een gl ass are p rod uced wit h ele ct ri c f urnac es. The
capa cities of su ch furn aces a re ab out 1 00 to 110 M g/day (110 to 12 0 ton s/day). E lectric melters have n ot been dem onstrated for larger operati ons, such as large container furnaces, the nom inal capacities of which are ab out 220 M g/day (240 tons/day), and flat -glass furn ace s, w hich ran ge fr om ab ou t 60 0 to 80 0 M g/da y (66 0 to 88 0 to ns/d ay ).

Several emissi on control systems that are availabl e to the gl ass indust ry for part icul ate c ontr ol ar e als o capabl e of ac hievi ng vari ous le vels of s econdar y SO 2 con tro l. For example, a ventur i sc rubber syst em can cont rol SO 2 emissions from com mercial glass plants. Th e system includes a packed tower w here p art of the sulfate p articulates are removed f

rom the hot fur nace f lue gas es, a dual- thro at vent ure sc rubber , where SO 2 andIX-2

add itiona l particu lates a re rem ove d by alka line w ash ing, a nd a cyclon e for fina l particu late collection . Cur rently , only th e con taine r glass segm ent o f the gla ss ind ustry is repo rted to

use scrub ber sy stem s for em ission contro l.

Injectin g a so rben t such as alu m ina, lim eston e, or n eph eline syen ite into a fab ric fi lt er sy ste m can eff ect ivel y remove SO 2 fr om furnac e fl ue gases . The s pent s orbent may be landfi lled or possibl y recyc led.

One pat ente d sy st em of d ry r emoval invo lve s t he co mbined u se of hydr ate d li me and
nep helin e sye nite for acid g as n eutra lization and fine p article a gglo m eratio n. In th is system , hot furnace flue gas is first mixe d with q uen ch w ater, hydrate d lime for prima ry SO 2 removal, and sec ondary ai r t o cool the gas str eam to a te mperatur e range of 94 o to 427 o C (200 o to 800 o F). Next, ne pheline syenite is ad ded to the gas stream to capture resi dual SO 2 and su bm icrome ter particulates. Th e gas strea m e nters the fab ric filt er wh ere the soli d product is removed for either r ecycl ing to t he furnace or l andfil ling.

Dry sor bent sy ste ms at sev eral commerci al gl ass f urnaces reduc ed SO 2 by 80 to 9 5
perc ent at a cont ainer glas s fur nace, 50 to 90 p erc ent at a fi bergl ass f urnace, and 88 to 98 percent at a flat -glas s furnace.

Mist el iminat ors ap parent ly have no e ff ect on SO

x gases. One sam pling test indi cat ed no dec rease in SO 2 and SO 3 co nc ent ra ti ons th ro ugh th e c ont ro l d evi ce ( EPA, 19 81 ).



### B. FLOOR ALLOCA TION ESTIMATION METHODS

It i s expect ed that t he floor alloc ation f or glass manu fact uring plants will be set

acco rdi ng to r ecent hist ori cal SO 2 emissi ons f rom these fac il it ies. These SO 2 em issions are li ste d in Tabl e IX- 1.

REFERENCES

AWM A, 20 00: Air and Wast e Management Asso ci ati on, “Ai r Pol lut ion Eng inee ri ng M anu al,” 2 nd edit ion, Chapter 15 - Miner al Prod ucts Indust ry, 2000.

EPA , 1981: U. S. Environmental Protec tion Agency, “Control Techniques for Sul fur Oxide Em ission s from Statio nar y So urces ,” Secon d E dition , EP A-4 50/3 -81-0 04, O ffice of Air Qualit y Planning and Standar ds, Researc h Triangl e Park, NC, Apri l 1981.IX-3 

### Table IX-1 Glass Manufa cturing - Historical Emissions - 1 990 to 2000

Sta te Sta te

ID Co unty

ID Fac ility

ID IAS Region SIC MTF

Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000 Floor All ocati on

CA 6 037 106797 14 3221 8 Glass BALL -F OSTER GLASS CONTAI NER CO SAI NT- GOBAI N CONTAI NER <100 <100 166 174

CA 6 099 1662 11 3221 8 Glass GALLO GL ASS CO 61 271 269 440

CA 6 039 801 12 3221 8 Glass MADERA G LASS COMPA NY 108 170 190 104

CA 6 077 593 11 3221 8 Glass OW ENS I LLI NOI S OW ENS- BROCKWAY GLASS CONTAI NER 319 285 218 248

CA 6 037 7427 14 3221 8 Glass OWENS-BRO CKWAY GLAS S CONTA I NER - VERNON 193 323 280 435

CA 6 001 2086 11 3221 8 Glass ANCHOR GLASS CONTAI NER CORPORA 119 0 0

CA 6 001 30 11 3221 8 Glass OW ENS- BROCKWAY GLASS CONTAI NER - OAKLAND 122 128 64 57

CO 8 059 0008 53 3221 8 Glass COORS GLASS ROC KY MOU NTAIN BOT TLE 159 221 234 255 237

OR 41 051 1876 5 3221 8 Glass Owens-Brockway Glass Container, I nc. 103 169 116 108 131
1,284 1,667 1,537 1,821IX-4X-1 

## CHA PTER X COPPER SMEL TERS

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

Prim ary co ppe r sm elters in the W RA P S tates p rocess copp er su lfide ore conce ntrate to produce anode c opper. There are six pr imary copper smelt ers in t he WR AP region. Five of th e p rim ary cop pe r sm elte rs a re n ea r th e co pp er m ine s in the sou thw est U nit ed Sta tes

. These smelters use a batc h copper conver ting pr ocess ( either Pi erce- Smith or Hoboken

conve rter designs) to prod uce blister copp er. Curren tly, only two o f these sm elters are producing c opper (t he ASAR CO sm elter in Hayden, Arizona and the Phelps Dodge smelter in Miami, Arizona). The other three smelt ers have suspended operat ions and are not producing c opper at t his ti me.
The sixth pri mary copper smelter in the WRAP States i s the Kennecott Utah Copper Corpor ati on near Garf iel d, Ut ah. The Kennecot t smel ter was buil t dur ing t he mid-1990s (rep lac ing the ex istin g sm elte r at the site ) an d u ses a fla sh cop pe r co nv ert ing tec hn olo gy

. This technology allow s blister c opper to be produced in a con tinuous process.

All pr imary c opper smelte rs i n the r egion c ontr ol SO 2 emiss ions by r outi ng th e proce ss off-gas es from the sm elting and conv erting proce sses to dou ble co ntact s ulfuric a cid plants.



### B. FLOOR ALLOCA TION ESTIMATION METHODS

Because of the uniqueness of the exist ing copper s melters, retr ofit technology analysis must be per formed on a smelter- by-smelter basis. Currently, the Hidalgo smelter is t he only BAR T-eli gible sour ce in thi s categor y. A double cont act aci d plant i s consid ered the a ppro priate retrofit con trol eq uipm ent (a ll sm elters in the w estern State s are cu rrently equippe d with do uble c ontac t ac id pl ants) . On August 21, 2000, New M exic o complet ed an engineer ing anal ysis that veri fi ed earl ier deter minati ons by t he MTF that the f ugit ive SO 2 capt ure sys tem at Hida lgo s ati sfi es BART at 96 perc ent over all SO 2 capture.

The A nne x t o t he Gr and Cany on Vi si bi li ty Tr ans por t C ommi ss io n’ s ( GCVTC)

rec ommendations de fi nes st epped r educt ion mil est ones t hrough 2018 f or SO 2 emiss ions fr om lar ge i ndust ri al s ourc es i n the 9-S tat e Commiss ion Tr anspo rt Regi on. The cur rent year SO 2 alloca tion for the six copp er sm elters in the 9 -State re gion is 86,0 00 to ns. T his all ocat ion i s r educ ed t o 78, 000 t ons by 2013 and is the s ame in 20 18. For t he re cent Emissio n Forecas ts t o 2018 analys is, the pl ant- level dif fer ence SO 2 em issions difference between 86,000 tons and 78,000 tons was si mulated by subtract ing 2,000 tons each from the four l argest s melters, which are ASAR CO-Hayden , BHP-San M anuel, Phelps- Dodge Chino Mines, and Phelps Dodge-Hid algo. The resul ti ng all ocat ions o f 2018 SO 2 emiss ions by fac il it y are s hown in Table X- 1. Not e that the 78, 000 tons of SO 2 alloc ation f or copper

sm elters is a n ag greg ate v alue for the regio n, rath er tha n a re quire m ent fo r each sm elter to reduc e emissi ons to pres cri bed lev els. Table X- 1 il lust rat es one way t hat t his r egional alloc ation might be met. Many other examples are pr ovided in t he EPA regional haze r ule.X-2 

### Table X-1 Copper Smel ter SO 2 

### Em is si on Pr oje ct io ns (tp y)

State Fa ci l i t y Na me 2018

AZ ASARCO Smelter- Hayden 21,000

AZ BHP-San Manuel 14,000

AZ Cyprus Mi ami Mine 8,000

NM Phelps Dodge- Chino Mine s 14,000

NM Phelps Dodge- Hidal go Smelter 20,000

UT Kennecott

Utah Copper Corp. 1,000

Total Copper Smelter 78,000



### C. COMPARISON WITH HISTORICA L EMISSIONS

Table X- 1 SO 2 em ission estim ates ca n be com pare d w ith rece nt h istorical (1 990 to 2000) emis sions for those smelt ers s hown in Table X- 2.X-3 

### Table X-2 Recent Hist orical Copp er Smelter SO 2 

### Emissions

State State

ID Co unty ID Fac ility

ID IAS Region SIC MTF

Sector Sector

Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent fro m 1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000

Smelter

Sector

AZ 4 007 0004 45 3331 2 Copper ASARCO SMELTER - HAY DEN 29,814 33,124 22,077 16,753

AZ 4 021 0032 46 3331 2 Copper BHP (Magm a Metals) BHP - San Manuel 15,900 16,678 10,409 0

AZ 4 007 0006 45 3331 2 Copper CYP RUS MI AMI MI NE 5,676 5,737 6,097 6,810

AZ 4 019 0040 46 1021 2 Copper Cyp rus Sie rrita 800 548 <100 <100

NM 35 017 0001 64 3331 2 Copper PHELPS DODGE/CHI NO MINES 28,058 14,784 15,685 11,420

NM 35 023 0003 64 3331 2 Copper PHELPS DODGE/HI DALGO SMELTER 41,433 32,121 29,188 0

UT 49 035 0030 32 3331 2 Copper Kennecot t Ut ah Copper Cor p. 26,829 1,556 762 937
148,51 0 104,54 9 84,218 35,920X-4XI-1 

## CHAPT ER XI A LUMI NUM PRODUCTI ON

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

Primary al uminum product ion pl ants i n the Unit ed Stat es pr oduce al uminum m etal by elec tro lyt ical ly r educi ng alumina t hat have bee n ref ined f rom bauxit e ore. There are 23 primary aluminum plants in the United St ates. There are only 2 plants in the st udy region and bot h are loc ate d in Or egon.

Alu m inu m prod uction is carried out in a sem ibatch ma nn er in la rge e lectrolytic ce lls cal led po ts w ith a d ire ct cu rre nt i np ut o f up to 2 80 ,00 0 a m pe res at a bo ut 5 vo lts. T he po t, a rect angular steel shell r anging in size f rom 30-50 feet l ong, 9-12 f eet wide, and 3-4 feet high, is lined w ith a refractory insu lating she ll on w hich carb on blo cks are pla ced to form the cathode.

An alumin um pot wi ll typ ic all y emit 20- 35 kg p er met ri c t on of gase ous and particu late flu oride and roug hly a n eq ual a m oun t of particu late m atter. T he N SP S lim its emissions t o no more than 1 kg fluoride/ Mg (2.0 lbs/ ton) of

aluminum produced f or potr oom groups at Sode rber g plant s, 0.95 kg /Mg (1. 9 lbs/ ton) of al uminum produced at pre- bake plants, and 0.05 kg/Mg (0.1 lbs/ton) of aluminum equivalent for anode b ake plants.

The r edu ct io n c el ls in us e f or al umin um pr odu ct io n i n t he Un it ed St at es ar e of two basic types – prebak e and Soderb erg. The re are tw o types of So derberg cells that are desi gnat ed ac cor ding to t he manner o f mount ing t he st ud in the c arbo n anode : v ert ic al s tud So der be rg (V SS ) or h oriz on tal stu d So der be rg (H SS ).

Preba ke ce ll s ar e so n amed bec ause t he anod es ar e pr efo rmed and then baked in a
sepa rate fa cility often referre d to a s an ano de b ake plan t. The ano des a re the n m oun ted in the ce ll and are co nsu m ed in the a lum inu m prod uction . The ano de b utts, w hich rem ain after the anode is consum ed, are recycled f or use in the preparation of new anodes.

In t he Sod erbe rg p roc ess , c onti nuousl y f ormed, cons umable an odes are u sed. The

ano de pa ste is ba ked by th e he at ge nera ted in the re ductio n cell.

The pr imary sour ce o f s ulf ur ox ide emiss ions in al uminum pro duct ion i s t he sul fur in t he co ke ( normal ly p etr ole um coke) and t he co al t ar p it ch bi nder used to p rod uce t he anodes. In t he prebake process , t he combustion fuel t o bake the anodes may be a signi fi cant S O 2 em ission sou rce. Petroleum coke u sually con tains 2.5 to 5 percent su lfur, but may v ary f

rom 1. 5 to 7 per cent sul fur . Pi tc h normal ly c onta ins about 0. 5 per cent sul fur . The sul fur cont ent o f t he co ke dep ends on th e cr ude pe tr ole um sto ck and the tend ency of

the s ulf

ur t o co ncent rat e in t he st il l bo tt oms at the r efi nery and t hus i n the coke.

As t he co ke i s pr oce sse d ( duri ng pr ebake) or c onsumed i n the red uct ion c ell , s ulf ur oxides are r eleased. The em issi ons include t hose from the anode prebake operat ion (pre ba ke ), the “prim ary ” em issio ns (w hich are cap ture d by the pot h ood exh au st sy stem ), and the “sec ondary” emissi ons (which esc ape the primary exhaust s ystem and exit t hrough the r oof monit ors) . The gr eat major it y of SO 2 emissions are c ollec ted by the pot hood

ex ha us t sy st em.

One sourc e repor ts unc ontr oll ed SO 2 emi ss i on s f r om a no de ba ke pl an t s r an ge f r om 5 to 47 pp m, which i s 0. 7 to 2 kg SO 2 /Mg aluminum produc ed (1. 4 to 4 l bs SO 2 /t on al uminumXI-2

produc ed). Other dat a indi cat e that emissi ons are in t he range of 0.09 t o 1.7 k g SO 2 /M g aluminum produc ed (0. 18 to 3. 4 lbs S O 2 /ton alu m inu m pro du ced ).

The tot al amount of SO 2 gener ate d per unit of alumi num prod uced is ess enti all y the same for the prebake, VSS, and HSS cases. The “pri mary” cell hooding confi guration f or col lec tion of p roc ess fum es i s a ffec ted by the ch ara cte rist ics o f th e d iffer en t ce ll ty pe s. There are two types of prebake cell s, c enter- worked prebake cell s (CWPB ) and side- worked preb ake cells (SW PB ), as we ll as the two Sod erbe rg pro cesse s, VS S an d H SS, w hich are in

use by th e do m estic alu m inu m indu stry. Inform ation from seve n prim ary a lum inu m plan ts indicat es the f

ollowing:

Cell Type Primary Hood Collecti on Ef ficie nc y, % Prim ary C ollector Ex hau st Ra te (10 6 sq ua r e c ub i c f ee t pe r t on of al umi nu m) CWPB 65 to 98 (4. 11 to 5. 05) SWPB 85 (3. 44) VSS 81 (0. 67) HSS 80 to 95 (5. 06 to 7. 85)

Th is in form atio n in dica tes th at th e ga s vo lum e a ssoc iate d w ith th e pr odu ction of a fixed amount of al uminum is i n the range of 5 t o 12 times (aver age 8 times) gr eater f or CWP B, SWPB, or HSS t han for VSS. Conseque ntly , t he conc entr ati on of SO 2 in a volume of exhaust gas in t he primary coll ector system can be expect ed to be about 8 ti mes greater f or a VSS unit than for other units.

Report ed dat a on uncont rol led “ pri mary” exhaus t sy ste m SO 2 emissi ons are as follows:

Un it Source SO 2 Concentrati on, ppm Total SO 2 emissions, kg SO 2 /Mg Al uminum (l bs SO 2 / t on al umi nu m)
Pre bak e C ell A 5 Not report ed

B Not report ed 20.9 t o 23.4 (41. 7 to 46. 8) [ave rag e of 2 2.4 (4 4.8)] C Not report ed 30 (60) [ 3% sulfur in t he coke] VS S C ell A 80 Not report ed

B 200 to 300 17.5 t o 25 (35 t o 50) C 200 (average) Not report ed

Th e tr en d in con stru ctio n o f ne w alu m inu m pla nts is to w ard pre ba ke sys tem s. A

m ajor fac tor influ encin g this tre nd is th e low er po we r requ irem ent o f the pr eba ke ce ll compared with Soderberg c ells . It is rep orted t hat 9 of t he 11 aluminum plants opened since 1960 are of the prebak e type, and 99 percent of the 324 G igagrams (357 ,000 tons)
capa ci ty a dded si nce 1 973 has been at pre bake f aci li ti es. Of t he 23 pr imary alumi num production plants in th e Un ited States, 18 u se the pre bake process an d 5 use the Sod erberg
process.



### B. FLOOR ALLOCA TION ESTIMATION METHODS

Th ere a re tw o alu m inu m sm elters lo cated with in the study regio n, an d the y are both locate d in O rego n. Th e da ta pro vided by th e O rego n D epa rtme nt of E nviro nm enta l Qu ality on the uni t c apaci ti es and SO 2 em ission s pote ntial fo r these two sm elters is p rovid ed in Table XI- 1. Thi s tabl e shows t hat t he SO 2 em ission s pote ntial fo r Re yno lds M etal, if operat ed at i ts d esig n capac it y, i s 4, 700 tpy. This i s the s ame as thei r per mitt ed SO 2 emissi on li mit. For NW Aluminum, the SO 2 emissions pot ential i s 518 tpy.XI-3 The NSP S for pr imary aluminum plants l imits f luoride emiss ions, but does not aff ect SO 2 emissi ons. Washington i s the o nly St ate t hat has es tabl ished an SO 2 emission limit sp ecifically fo r prim ary a lum inu m plan ts. The rule lim its the m axim um allow able tot al SO 2 emiss ions fr om all sour ces wit hin t he pl ant t o 60 l bs pe r t on of alumi num produc ed on a monthly basis . Base d on the SO 2 emission rat es by proces s for Reynolds Metal, which i s 65. 3 lbs S O 2 per ton of aluminum produced, applying t he State of Washington r ule would o nly pr ovide an 8 perc ent r educt ion i n SO 2 emissions.

Comparing t he capac it y-bas ed SO 2 emiss ion e st imat es i n Table XI- 1 wit h rec ent hist ori cal emissi ons ( see Tabl e XI- 2) s hows that rec ent hi sto ric SO 2 emissions f rom Reynolds Metals ar e consi derabl y below t heir capac it y/p ermit ted emis sion l imit , and t hat they var y consi derabl y fr om year-t o-ye ar. NW A luminum SO 2 emissi ons in t he peri od 1996 to 2000 average about 80 percent of tot al capaci ty.

The f loo r c ontr ol t echno log y f or al uminum smelt ers was det ermi ned by eval uati ng the emissions performa nce of Reyno lds Metals and N W A luminu m. NW Alum inum uses a wet sc rubber to ac hieve a 70 p erc ent SO 2 emission reduct ion. Theref ore, a wet s crubber with a 70 pe rce nt SO 2 red uct ion was sel ect ed as the f loo r t echno log y f

or al uminum smelters. The effect of thi s fl oor tec hnology applic ation is shown in the rightmost c olumn of Table XI- 1.

REFERENCES

CFR , 2001: Code of

Federal Regulati ons, “ Subpart S - St andards of Perf ormance for Primary Al uminum Plants ( 60.190- 60.195) ,” July 1, 2001.

EPA , 1981: U. S. Environmental Protec tion Agency, “Control Techniques for Sul fur Oxide Em ission s from Statio nar y So urces ,” Secon d E dition , EP A-4 50/3 -81-0 04, O ffice of Air Qualit y Planning and Standar ds, Researc h Triangl e Park, NC, Apri l 1981.XI-4 

### Table XI-1 Aluminum Plant Data Used to Estimate Floor A llocations

Company Em iss ion s U nit Fuel Typ e Act ual Ca pac ity Ca pac ity

Un its Control

Devi ce SO 2 Emissio n

Factors (l bs/t on) SO 2 Contro l

Eff ici ency SO 2 Emissio ns

Actua l Cap acity (tons/yr) Floo r Al locat ion

at 70% Cont rol (tons/yr)

Re ynold s M etals Carbon bakes Potr oom fugi ti ves Potr oom emissi ons Backup f uel Plant tot al Natur al gas

N/A N/A #2 fue l oil N/A N/A 0.18- .19 2.5 62 .5 0.105 N/A

N/A 27 177 4,488 7.5 4,700 27 177 1,346. 4 7.5 1,557. 9

NW Alumin um Cell li ne Cell li ne Casthouse furnace Plant tot al N/A

Propane Natur al gas 97,500

144,00 0 80,000 ,000 TA P/yr

ga llon s/yr

cu bic fee t/yr W et s crubbe r

No No 0.7 N/A N/A 517

<0.1 1 <518 517 <0.1 1 518

Total 5,218 2,076

NOTES: Cont ro l Devi ce: Whi l e t her e ar e no phy si cal con tr ol dev i ces , t he mo st ef fe ct i ve f

or m of SO 2 contr ol i s li miti ng the amount o f sul fur in f uel oi l. For example, the sul fur

con te nt i n di st i l l at e f uel oi l sol d i n NW usu al l y av er age s much l ess th an 0 .1 , wh er eas th e r ul e l i mit i s 0. 5. Act ual Capa ci ty Emis si on i s l i mit ed b y t he SO 2 PSEL. SO 2 emission f

actor s are i n lbs per ton of aluminu m produced.XI-5 

### Table XI-2 Alu minum Smelt ing - Hist orical Emission s - 1990 to 200 0

Sta te Sta te

ID Co unty

ID Fac ility

ID IAS

Region SIC MTF Sector Sector Descri pti on Facil it y Name (1990) Current Faci li ty Name (i f di ff erent f rom 1990) SO 2 tpy 1990 SO 2

tpy 1996 SO 2

tpy 1998 SO 2

tpy 2000

100 tp y or More SO 2

OR 41 065 0001 5 3334 10 Me tals /Min ing /Min era ls Northwest Aluminum Com pany, I nc. 423 448 375 397

OR 41 051 1851 5 3334 10 Me tals /Min ing /Min era ls Reynol ds Metal s Company 3,340 0 503 1,510

3,763 448 878 1,907XI-6XII -1 

## CH APT ER XII SULFURIC ACID PLANTS

Sulfu ric acid is th e m ost w idely u sed in dus trial che m ical. Th e chie f uses of sulfu ric aci d ar e in p rod uct ion o f f ert il ize r, manufac tur e of chemi cal s, oil ref

ini ng, pig ment produc ti on, i ron and st eel pr oces sing, synthe ti c f iber produc ti on, and met all urgi cal operation s. The pre dom inan t process use d for the prod uction of su lfuric acid is the contact process. The entire discussion in this c hapter focuses on the contact process.

Sulf uric aci d is produc ed by burni ng sulf ur or s ulf

ur- beari ng materi als t o for m SO 2 . Sourc es of

SO 2 include: (1) elemen tal sulfur; (2) spent acid; (3) smelter off -gas; ( 4) pyrites; and (5) waste gas from fossil-fuel- fired boilers

. 

### A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

Contact sulf

uric aci d plant s are c lass if ied as hot gas (sul fur burning) or c old gas (metallur gical and spent acid) systems. Plants operat ing on elemental sulf ur recei ve hot SO 2 gas di rec tl y fr om the sul fur burner and waste heat rec overy s yst em. When SO 2 gas from a m etallurgical operati on or other byprodu ct source (s uch as spent acid or iron pyrites) is used, it is received cold f rom the w et scrubber-cooler and purific ation systems.

A basic variation of the contact process i s the double absorption techniqu e, also known as double catalysi s. This design is largel y based on the need to meet air p ollut ion control regulations.

The onl y si gnif

ic ant s ourc e of

air emiss ions fr om a cont act sul fur ic aci d pl ant i s t he tai l gas leavi ng the f inal absorb ing t ower. This gas cont ains s mall amounts o f SO 2 and even smaller amounts of

SO 3 , sulfuric v apo r, and sulfu ric acid m ist.

SO 2 emissions are det ermined primaril y by overall plant desi gn (e.g. , number of cataly st pass es, am oun t of cataly st, dua l or sing le ab sorptio n, etc.). Ne w p lants are u sua lly desig ned to m eet N SP S em ission limits u sing th e du al ab sorptio n pro cess. In ce rtain situ ati on s, pl an ts ca n a ch iev e b ette r th an N SP S li m its u sin g th e d ua l ab sor ptio n p roc ess

. For example, in a metal lurg ical aci d plant , l ower SO 2 emissions can someti mes be achieved cat alyt ical ly i f t he proc ess gas fr om a smelter has a suf fi cie ntly high oxyg en-t o-SO 2 rat io. Prop er c atal yst vol umes and i nter pass coo li ng ca n be i ncor por ate d int o the ini ti al d esi gn, however. Exist ing pl ants t hat ar e requi red t o reduc e thei r SO 2 em ission s usu ally ch oose to

conve rt to dual ab sorption or in stall a tail gas scrub ber.

Dual absor pti on has been gener all y acc epted as BACT. Concept ually , dual ab sorp tion is th e a ddit ion of an oth er co nv erte r an d ab sorb ing tow er o n th e ta il en d of a single abs orption plan t (with app ropria te he ating and coolin g of the gas s tream ) so the re is no new technology involved. Only sulfuri c acid is pr oduced in the dual absor ption
equ ipm ent.

Various scr ubbing, or t ail gas, tec hnologi es are avail able f or r emoving SO 2 fr om gas stream s. Tail g as trea tme nt is ra rely u sed to ach ieve NS PS limits fo r new plan ts. A tail
gas proce ss at the en d of a du al abso rption plan t ma y be the preferred techn ology w here local regulations require substantially l ower than NSP S em ission rates.

Tail gas p roc ess es t hat p rod uce a by- pro duct that can be rec ycl ed t o the aci d pl ant (e.g., wea k su lfuric acid ) are o f specia l intere st beca use they elim inate the n eed for off-site by-pr oduct dis posal . Two suc h proc esses are hydr ogen per oxide scr ubbing and SO 2 oxi dat ion wi th ac ti vat ed c arbo n.XII -2



### B. FLOOR ALLOCA TION ESTIMATION METHODS

Based on t he inf

ormati on avail able f or sul fur ic a cid plant s in t he west, it was det er mined tha t i t i s ap pr opr ia te to est imat e t he f lo or al lo cat io n by a ppl yi ng t he NSPS
requ irem ents to each sulfu ric acid p lant.

Su bpa rt H - S tand ards o f Perform ance fo r Su lfuric Acid Plan ts

60.82 Standa rd f

or Sul fur Diox ide

On or after the date on w hich the perform ance test required to be con ducted b y Sec. 60.8 is com pleted, no ow ner or operator su bject to the provisions of this subp art shall cause
to be d is cha rg ed i nto the at mosp her e f ro m any a ff

ec te d f ac il it y any gas es whic h co nta in SO 2 in exce ss of

4 lbs pe r ton of

acid pr oduced. Achi eving t his st andard requir es a c onversi on ef fi ci enc y of 99. 7 pe rc ent in an unc ont ro ll ed p la nt, or the equ iv al ent SO 2 coll ect ion mechanism in a contr oll ed fac il ity.

Table XII-1 l ist s the sulf uric ac id plant s, t heir charac teri sti cs, and the esti mated annual SO 2 fl oor al loc ati ons. An init ial SO 2 fl oor all ocat ion was est imat ed by mul ti ply ing the dai ly t hroughput li mit by t he NSPS emissi on rat e (4 l bs SO 2 per ton 100 perce nt acid produce d), times 365 days pe r year, conv erted from lbs to tons by dividing b y 200 0. In equation form, this is:

This bas ed on thr oughput i niti al f loor all ocat ion was f ound to ex ceed t he annual SO 2 permit limits for each of these units. Therefore, the estimated floor allocati ons for these sulf uric aci d plant s was est abli shed usi ng rec ent hi sto ric SO 2 emissions data. These hist ori c emiss ion val ues are all sli ghtl y below t he annual SO 2 permit limits.

REFERENCES

AWM A, 20 00: Air and Wast e Management Asso ci ati on, “Ai r Pol lut ion Eng inee ri ng M anu al,” 2 nd edit ion, Chapter 12 - Chemical Proces s Indus try , 2000.

CFR , 2001: Code of

Federal Regulati ons, Subpart H - Standards of Performance for Sulf uric Acid Pl ants ( 60.82) , Jul y 1, 20 01.

Idaho DEQ , 2002a: St ate of I daho, Department of Environmental Qualit y, Air Quality Tier 1 Operat ing Per mit, J.R. Simplot Co. - Don Siding Plant, 2002.

Idaho DEQ , 2002b: St ate of I daho, Department of Environmental Qualit y, Air Quality Tier 1 Operating P ermit, Nu-We st Industries, Inc.; Agrium Conda Phosph ate Operations, 2002.XII -3 

### Table XII-1 Sulfuric Acid Plants

State Fa ci l i t y Na me Start Da te Su lfur ic Ac id

Pla nt ID Process Control Techni que Ann ual SO 2 Pe rm it Lim it (t ons) Da ily

Through put Limi t ( tons) Based on

Through put SO 2 Floo r Alloc atio n (tp y) Floo r Al locat ion Us ing His tor ic Emissio ns Ave ra ge (tpy)

Idaho Nu-W est Indus tr ies East NA NA 945 1,550 1,131 612

Idaho JR Simplo t 300 Single contact 2 st age scr ubber s yst em 750 1,750 1,277 1,939

400 Doub le contact Doub le contact wit h mist eli minat or 1,458 NA 1,458

W yom ing SF Pho sphates, Inc. 1995 Source 9b MEC 96 3.6 1,320 964 1,638

1984 Source 9a Lurgi 1,387 1,900 1,387

W yom ing Koch Sulf ur

Pro du cts EU -1 NA 719 NA 719 1,197

EU -5 NA 721 NA 721

NA = not avai labl e.XII -4XII I-1 

## CH APT ER XIII META LLURG IC COKE PRODUC TI ON

A. SECTOR DESC RIPTION A ND SIGNIFI CA NT SO 2 

### SOURCES

M eta llu rgi cal cok e is de riv ed from coa l an d u sed in i ron an d st ee l in du stry pro ces ses

. Coke is m anufactured by pyrolysis, the heating of coal in the absence of air. In this pr ocess, high grad e, bitum inou s coal is hea ted in a en closed cha m ber to app roxim ately 105 0°C (192 5°F ), which rem ove s all vo latile co m pon ents o f the co al. Th e resu lting p rodu ct is a solid mater ial cons is ti ng of ele mental car bon and a ny miner als that were no t vo lat il ize d in t he heating process.



### 1. By Product Coke Ovens

In a ty pic al c oking op erat ion, 35 to 100 c oke ovens a re l ocat ed in a r ow refe rre d to as the oven ba ttery. Each ove n has three m ain parts: coking chambers, heating cham bers, and regenerativ e chambers. The coking chamber has port s in the t op for c harging (l oading) of the coal. A typical U.S. coke oven produces 7.5 tons to 39 tons of coke per cycle. Most coke plants are co-located with iron and steel production facil ities.

Al l ov en s cu rre ntl y o pe rat ing in t he U nit ed Sta tes are by -pro du ct re cov ery ov en s. The se oven s operate b y reusin g gase s (volatiles) emitted b y the h ot coal. In by-prod uct
recovery o vens, the v olatiles from th e coal are collected and sent to a b y-product recov ery pla nt. The of

f g as i s c ondens ed and sepa rat ed i nto a li quid fr act ion ( coal tar ) and a gas eous frac tion ( coal gas) . The coal gas contains a number of cont aminants includi ng hydrogen sulfide . Som e by -produ ct recov ery p rocess es rem ove the su lfur from the g as prio r to combustion. Approxi mately 33 percent t o 40 percent of the clean c oal gas is then returned to the oven batt ery to be used as f uel. The remaining coal gas can be used as fuel for ot her processes at the plant or sold to ot her facili ties.

Emissio ns of

SO 2 fr om coke ovens oper ati ons p ri maril y re sul t f rom co mbusti on of

the byprod uct c oal gas in t he oven. A small por ti on of SO 2 emissions comes f rom uncontrolled “char ging” , t he proc ess of loadi ng coal int o the ov en. Cont rol of SO 2 fr om combusti on of c oal gas is pr imarily ac complished by; (a) r emoving the sulfur f rom the gas prior to combustion or (b) util izing l ow sulfur coal in the coki ng process. There are a numb er of methods f or removing sulfur from the coal gas, s uch as wet scrubbi ng.



### 2. Rotary

Calciners

There is only one known rotary c alci ner used for coke product ion in the United States, P4 P roduction in Ro ck Spring s, WY . It uses a Sale m B rosius, 65 foot dia me ter, continuous f

eed rotar y hearth calc iner. Basicall y, t he process i nvolves feed ing a mixture of coal a nd p etrole um (pet) cok e on to a ro tating table locate d insid e a fu rna ce. Th e coa l is heat ed t o a hi gh te mperat ure a s i t r ota tes to p rod uce c oke. The co ke exi ts the h eart h and ente rs a coo li ng cha mber. Like bypr oduc t r eco ver y ove ns, the f urnac e ope rat es by reus ing the v olatile g ases em itted from the co al. H ow eve r, in this p rocess , the furn ace is in itially st art ed wit h natur al g as. Once s tar ted , t he co al g as be ing e mitt ed dur ing t he co king process is utilized a s fuel directly. The w aste gas is th en du cted to an in cinerator. Byp ro duc ts of

th e p ro ce ss in cl ude f in e c oke

, as h, CO 2 , SO 2 , and r ock.

Emissio ns of

SO 2 from a rotar y hearth calc iner are pr imarily due t o the volat iles from the h eat ed c oal . The wast e gas is duct ed t o an i nci nera tor and bag house pri or t o bei ngXII I-2

emitted t o the atmosphere. There is no desulf urizati on of the waste gas. The am ount of SO 2 em itte d fro m the fac ility is a fun ctio n o f th e p rop ert ies of th e fe ed coa l.



### B. FLOOR ALLOCA TION ESTIMATION METHODS

The analysi s was li mited t o fac il it ies whi ch emit great er t han 100 tpy o f SO 2 in t ota l. Th ere a re thre e facilities w hich hav e be en id entified . Tw o are cokin g pla nts, A staris Co king Pla nt in W yom ing a nd G ene va S teel in Uta h. Th ere is o ne ro tary ca lciner in Wyom ing, P4 Product ion, Rock Spr ings Coal Calci ning Plant. The air pollut ion agencies f or Wyom ing and Utah provided inf ormation on the coking and cal cining f acil iti es for est im ati ng floo r al loc ati on s.

Astaris Coking Plant was shut down in April of 2001. Therefor e, t his fac ili ty does not r ecei ve an SO 2 all oca tion

.
Geneva Steel has committ ed to c easi ng all SO 2 emiss ions fr om the c oke ov ens and the sint er plant. These emissions have been banked for fut ure use or tr ading as prec ursor pol lut ant s wi thi n th e c urr ent lo cal Utah Count y PM 10 SIP. Th e Uta h A ir Qua lity Board
approv ed thi s change o n June 5, 2002. Since the SO 2 emissi ons f or c oking and s inte ring at the pl ant ar e now essent ial ly ze ro, the SO 2 floo r al loc ati on for c ok ing is a lso ze ro.

Th e third facility is P 4 P rodu ction, R ock S pring s Co al C alcinin g Pla nt. Th e pla nt is de sig ne d to pro ces s 2 20 ,00 0 tp y o f fee d m ate ria ls to pro du ce 1 10 ,00 0 tp y o f cok e p rod uc t. Th e pla nt op erate s for up to 8,00 0 ho urs p er ye ar. Th is wo rks ou t to a de sign p rocess rate of 27. 5 to ns pe r hour (t ph) or 66 0 to ns pe r da y ( tpd ) o f f eed. Acc ord ing t o the oper ati ng perm it, the tota l facility po tentia l to em it is 2, 841.1 t py of SO 2 base d on 8, 760 ope rat ing hours. There are no NSPS requir ements t he fac il it y must co mply wit h for SO 2 . This rotary coke r wa s bu ilt in 19 72 a nd th us is "g ran dfath ered " from the W yom ing A ir Qu ality Div ision's p erm it requ irem ents. T he h istorical e m ission s for this fa cility are prese nted in Table XII I- 1.



### Table XIII-1

Historical S O 2 

### Emissi ons at P4 Pro ducti on, R ock Sp rings , WY

Hist ori cal Emissi ons of SO 2 (tpy) Aver age Annual SO 2 Em issions (tpy)

1990 1996 1997 1998 2000 1996 - 2000

933 663 586 642 633 631

As sta ted pr evious ly, the SO 2 emitted is a function of the feed coal. The plan t uses a ble nd of

coal and pe tr ole um coke ( pet coke ). The 1994 a nnual i nvent ory showed that the pet c oke blend was 7.2 p erc ent f or t he year, with SO 2 emiss ions of 420. 0 tp y; up 15 pe rc ent fr om the 36 5. 6 tp y emit ted in 19 93, when st rai ght c oal was use d as 1 00 per cent of the feedst ock. The most rec ent year' s data shows that t he pet coke blend was 25 percent for 1998, t he maximum allowable amount t o maintai n compli ance wit h the SO 2 emiss ions limit.

The procedure for esti mating the fl oor all ocati on for P4 Producti ons is di ff icult for several rea sons. First, there are no iden tified control techno logies ava ilable for the rota ry calcine r. Secon d, there are n o N SP S req uirem ents. T hird, P 4 P rodu ction h as a poten tial to emit 2, 841.1 t py based on 8,760 ho urs of operat ion. This i s much higher than t he annual emissi ons rep ort ed by t he plant . Last ly, the SO 2 emissions f rom the rotary c alci ner are a function of the sulfur content of t he feed wh ich varies over time. Since the coking process at P4 Pr oduc ti on is unique and c annot be co mpared wit h emiss ions fr om othe r f aci li ti es, the SO 2 alloca tions fo r P4 Pro ductio ns w ill be b ased on its a vera ge a nn ual e m ission s. Th is isXII I-3

consist ent with the al locat ion approach devel oped for s ource cat egories wit h no technology available f

or reduci ng sulfur and vari able sulf ur content i n the feed suc h as flar ing.

The all ocat ion f

or P4 Prod ucti on will be based o n emissi ons of SO 2 fr om years 1996, 1997, 1998 and 2000. Averaging hist oric al emissions r esults in a fl oor all ocati on of 631 tpy of SO 2 for the P4 Prod ucti on fac il it y. As stat ed pre vious ly, the SO 2 floor alloc ations f or Astaris and Geneva Steel are zero.



### C. COMPARISON WITH HISTORICA L EMISSIONS

Table XII I- 2 pres ents t he hist ori cal SO 2 emissi ons and t he SO 2 floor alloc ations f or all thre e coki ng fac il it ies. Note t hat Geneva St eel has an SO 2 allocation for i ts boilers, whi ch is di sc uss ed in Sec ti on I V.



### Table XIII-2

Coking Plan t - Histo rical Emissions - 1990 to 2000

Sta te Co unty

ID Fac ility

ID SIC MTF

Sector Sector

Descript ion Facil it y Name (1990) Current Faci li ty Name

(i f di ff erent f rom1990) SO 2 tpy 1990 SO 2 tpy

1996 SO 2 tpy

1998 SO 2 tpy

2000 SO 2 Floor

All ocati on

W Y 037 0003 10 Metal s/Mi ning/ Min era ls Sweetwater

Resources P4 Production - Rock Sprin gs 933 663 642 633 631

W Y 023 001 10 Metal s/Mi ning/ Min era ls FMC Coking Plant Astar is Coki ng Plant 1,194 1,413 1,454 1,409 0

UT 049 0027 3312 10 Metal s/Mi ning/ Min era ls Geneva Steel 8,473 2,020 881 979 0

REFERENCES

AWM A, 20 00: Air and Wast e Management Asso ci ati on, “Ai r Pol lut ion Eng inee ri ng Manual,” 2nd edit ion, Chapter 14 - Metal lurg ical Indust ry, 2000.

EPA , 1981: U. S. Environmental Protec tion Agency, “Control Techniques for Sul fur Oxide Em ission s from Statio nar y So urces ,” Secon d E dition , EP A-4 50/3 -81-0 04, O ffice of Air Qualit y Planning and Standar ds, Researc h Triangl e Park, NC, Apri l 1981.

EPA , 1998: U. S. Environmental Protec tion Agency, “Compilation of Air Pollut ant Emission Factors, ” AP-42, Fif

th Editi on, Volume I: Stat ionary Point and Area Source, Secti on 12.2 C oke P roduction ” Office of Air Qu ality Plan ning a nd Sta ndard s, Resea rch Triangl e Park, NC, 1998.XII I-4XIV -1 

## CH APT ER XIV FLOOR A LLOCA TI ON SUMMA RY

Table XIV- 1 summarizes t he SO 2 fl oor all ocat ion e st imat es f rom al l of

the p rev ious chapters by State and by sect or. Cali forni a estimates l ist ed in Table XIV-1 are based on
average SO 2 emiss ions in t hese sec tor s f rom 1996 , 1 998, and 2000 . Ta ble XIV- 1 shows the est imated SO 2 floor allocation for n on-utility sources in the 9-State C om mission Tran sport Region t o be about 195 thousa nd tons . I f c opper smelte r SO 2 allocations in 2018 are subtracted from this am oun t, the floor allocation is 11 7 thou sand to ns. The non -smelter, non-Cali for nia SO 2 emissions total is 89,000 tons.

Table XIV- 2 provi des a c omplete li st o f t he fac il it y-l evel SO 2 fl oor all ocat ions , a nd incl udes year 2000 SO 2 emiss ions as a p oint of compar is on.XIV -2 

### Table XIV-1 State/Sector

Summary

of SO 2 

### Floor Allocations (tons per

year)

Sectors

States Refiner ies L i m e Manufacturi ng* Indust rial Boilers Pulp and

Paper Cement

Manufacturi ng Natural Gas

Processing Elemental

Phosphorus ** Glass

Manu facturi ng*** Copper Sm elters Aluminum

Pla nts Su lfuric

Acid Plan ts Coke

Producti on Total

Ariz ona 1,365 978 320 43,000 45,663

Ca liforn ia 27,335

Colora do 1,614 387 4,936 237 7,174

Idah o 601 1,807 522 15,861 2,551 21,342

Nevada 435 448 883

New Mexico 2,244 1,103 12,862 34,000 50,209 Oregon 1,585 5,377 131 2,076 9,169

Utah 4,142 303 2,010 267 1,593 1,000 9,315

W yom ing 3,418 2,350 165 14,429 2,835 631 23,828

Total 11,418 2,103 7,911 7,184 7,761 28,884 15,861 368 78,000 2,076 5,386 631 194,918

NOTES: *Ba sed on 199 8 an d 20 00 h is to ri cal SO 2 emission esti mates.

** Base d on y ear

200 0 SO 2 emission esti mates for P4 Producti on, which ar e substanti ally higher t han 1996 or 1998 emissions.

** *Ba sed on 199 6, 199 8, and 200 0 hi st or ic al SO 2 emission esti mates.XIV -3 

### Table XIV-2 Facility -Level SO 2 

### Floor Allocations Comparison with Year 2000 SO 2 

### Emissions (t ons per y ear)

State Facility

ID Sector Des cription Facility N ame (1990) Current Facility Name In Current Report Comments SO 2 Emissions Year 2000 SO 2 NonBoiler Allocation SO 2

Boiler Allocation Total

SO 2 Allocation State

Totals
AZ Cement/ Concrete Arizona Portlan d Cemen t X 320 0 0
AZ 0011 Metal s/Min ing/M inerals CHEMICAL LIME (CHEMSTAR) CHEMIC AL LIME - NELSON X 702 632 632
AZ 0003 Metal s/Min ing/M inerals Chemical Lime (Douglas) X 742 733 733
AZ Cement/ Concrete Phoenix Ce ment X 539 320 320
AZ 0007 Wood/Pap er/Pu lp STONE CONTAINER ABITIBI X 1,893 0 978 978
AZ 0001 Oil/Gas Intermou ntain Refining X Closed 0 0 0
AZ 0004 Copper ASARCO SMELTER - HAYDE N X 16,753 21,000 21,000
AZ 0032 Copper BHP(Magma Metals) BHP - Sa n Manuel X 0 14,000 14,000
AZ 0006 Copper CYPRUS MIAMI M INE X 6,810 8,000 8,000
AZ 0040 Copper Cyprus Sierrita X 0 0 0 45,663 CO 0048 Metal s/Min ing/M inerals CFI 267 0 CO 0004 Oil/Gas COLO REFINING X Refinery 545 562 562 CO 0003 Oil/Gas CONOCO DENVER X Refinery 1,972 1,052 1,052 CO 0008 Glass COORS GLASS ROCKY M OUNTAIN B OTTLE X 255 237 237 CO 0002 Cement/ Concrete HOLNAM LAPORTE HOLCIM LAPORTE X 404 1,402 1,402 CO 0001 Cement/ Concrete HOLNAM PORTLAND HOLCIM PORTLAND X 3,288 3,374 3,374 CO 0097 Misc. METRO WASTEWATER 56 0 CO 0003 Cement/ Concrete SOUTHWEST PORTLAND CEMEX -LYONS P LT. X 50 160 160 CO 9 Misc. GENERAL SERVIC ES ADM INISTRATI ON 0 0 CO 0001 Oil/Gas LANDMARK PETROLEUM 0 0 CO CHP TRIGEN-COLORADO ENERGY CORP. X 2,583 0 387 387 CO 24 Oil/Gas UNOCAL R ETORT-PAR ACHUTE X 0 0 CO 0025 Oil/Gas UNOCAL UPGRADE X 0 0 CO 0001 Food WESTERN SUGAR 1 19 0 CO 0002 Food WESTERN SUGAR 2 0 0 7,174
ID Wood/Paper/Pulp/Coge neration Tamarack Energy 117 0
ID 0004 Cement/ Concrete ASHGROVE CEMENT X 1,327 522 522
ID Power Avista 130 0
ID Food Basic American Foods (Shelly) 149 0
ID Wood/Pap er/Pu lp Boise Cascad e - Em mett 252 0
ID 0001 Misc. DOE-INEEL 460 0
ID 0005 Chemicals/Plastics FMC ASTARIS 0 0
ID Food MAGIC VALLEY FOODS 0 0
ID 0001 Chemicals/Plastics MONSAN TO/P4 PRO DUCTION P4 Product ion X Elementa l Phosphorus 15,861 15,861 15,861
ID 0003 Chemicals/Plastics NU WEST INDUSTRIES Sulfuric acid plants 86 612
ID 0001 Wood/Pap er/Pu lp POTLATCH X Paper Mill 1,694 1,807 1,807
ID Misc. RICKS C OLLEGE 0 0
ID 0006 Chemicals/Plastics SIMPLOT Sulfuric acid plants 543 1,939
ID 0010 Food TASCO (NAMPA) Amalgam ated Sugar (N ampa) 1,697 242 242
ID 0001 Food TASCO (PA UL) Ama lgam ated S ugar (P aul) 1,322 155 155
ID 0001 Food TASCO (TWIN) Amalgam ated Sugar (T

win) 1,053 203 203
ID Food Ida ho Su pre me 0 0
ID 0001 Misc. MTN. HM . AFB 144 0 21,341
NV 0003 Metal s/Min ing/M inerals CHEMSTAR APEX CHEMICAL LIME CO-APEX PLANT X Lime plant 210 193 193
NV 0387 Cement/ Concrete NEVADA CEMENT COMP ANY FERNLEY PLANT X 172 305 305
NV Cement/ Concrete Royal Cem ent Not in previous report 143 143

### Table XIV-2 (continued)

State Facility

ID Sector Des cription Facility N ame (1990) Current Facility Name In Current Report Comments SO 2 Emissions Year 2000 SO 2 NonBoiler Allocation SO 2

Boiler Allocation Total

SO 2 Allocation State

Totals

XIV -4 NV 0261 Metal s/Min ing/M inerals GRAYMONT WESTERN US INC PILOT PEAK X Lime plant 249 242 242
NV 0451 Metals/Mining SANTA FE PACIFIC GOLD CORP TWIN CREEKS/NEWMONT MINING CORP 113 0
NV 0433 Metal s/Min ing/M inerals BASIC INC.(Now PREMIE R CHEMICALS LLC) PREMIER SERVICES (Gabbs Facility) 0
NV 0863 Misc. HAWTHORNE ARMY 0
NV Metals/Mining Independence Big Springs ANGLO GOLD 0
NV 0019 Metal s/Min ing/M inerals TITANIUM METALS 0 883
NM 0024 Oil/Gas AGAVE ENERGY/YATES P LANT Agave Plant X 2,983 365 365
NM 0002 Oil/Gas ARCO PERMIAN/EMPIRE ABO GAS PLNT X 565 431 431
NM 0004 Oil/Gas CONOCO/MALJAMAR GAS PLANT MALJAMAR GAS PLAN T X 3,574 222 222
NM 0023 Oil/Gas GIANT INDUSTRIES/BLOOMFIELD REF X Refinery 920 414 414
NM 0008 Oil/Gas Giant Refining/Ciniza Refinery (Gallup) X Refinery 1,779 603 603
NM 0044 Oil/Gas GPM GAS EUNICE GAS PLANT VERSAD O GAS PR ODUCERS

LLC X 2,759 0
NM 0011 Oil/Gas GPM GAS/ARTESIA GAS P LANT DUKE ENERGY/ARTESIA GAS PLANT X 1,459 1,192 1,192
NM 0006 Oil/Gas GPM GAS/INDIAN HILLS AMINE PLNT 900 0
NM 0046 Oil/Gas GPM GAS/LEE GAS PLA NT Duke Energy Lee Plant X 818 0 0
NM 0035 Oil/Gas GPM GAS/LINAM RANCH GA S PLANT Duke Energy Plant 5 1,304 1,181 1,181
NM 0007 Oil/Gas J.L. DAV IS GAS P ROCESS/ DENTON X 1,158 840 840
NM 0008 Oil/Gas MARATHO N OIL/INDI AN BSN GAS PLT X 1,100 665 665
NM 0010 Oil/Gas NAVAJO REFINING/ARTESIA REFINERY X Refinery 980 1,227 1,227
NM 138 Oil/Gas PAN ENE RGY/BUR TON FLATS G

AS PLT Duke Energy Burton Plant X 246 164 164
NM 0285 Oil/Gas PAN ENE RGY/DAGG ER DRAW GAS PLT DUKE ENERGY/DAGGER DRAW X 247 218 218
NM Cement/ Concrete RIO GRANDE PORTLAND CEMENT X 1,103 1,103 1,103
NM 0008 Oil/Gas SID RICHARDSON GASOLINE /JAL#3 X 0 1,206 1,206
NM 55 Oil/Gas TEXACO/BUCKEYE GASOLINE P LANT DYNERGY 673 0
NM 0052 Oil/Gas TEXACO/EUNICE NORTH GAS PLANT X 5,476 0
NM 0051 Oil/Gas TEXACO/EUNICE SOUTH GAS PLANT X 231 0
NM 0003 Oil/Gas TRANSWESTERN PIPE DUKE ENERGY/HUBER GAS X 270 163 163
NM 0001 Oil/Gas WARREN PETROLEUM/BLUITT GAS PLANT X 1,226 0
NM 0060 Oil/Gas WARREN PETROLEUM/EUNICE GAS PLANT Duke Energy EUNICE GAS PLANT 2,756 2,250 2,250
NM 0061 Oil/Gas WARREN PETROLEUM/MONUMENT PLANT Dynergy MONUMENT PLANT X 1,387 675 675
NM 0063 Oil/Gas WARREN PETROLEUM/SAUNDERS PLANT Dynergy SAUNDERS PLANT 0 163 163
NM 0064 Oil/Gas WARREN PETROLEUM/VADA GAS PLANT 3,138 0
NM 0247 Oil/Gas WESTERN GAS PROCESSORS/SAN JUAN RVR Western Gas Resourc es X 3,127 3,127
NM 0128 Oil/Gas CITATION/ANTELOPE RDG GAS PLANT X 0
NM 0118 Oil/Gas CONOCO/B ELL LAKE 2 WELL #6 X 0
NM 0125 Oil/Gas FEAGAN E NERGY/W DAGGE R DRAW GAS P LT Duke Energy Dagger Draw X 0
NM 0050 Oil/Gas YATES PETROLEUM/PATHFINDER AM INE X 0 0 0
NM 0001 Copper PHELPS DODGE/CHINO MINES X 11,420 14,000 14,000
NM 0003 Copper PHELPS DODGE/HIDALGO SMELTER X 0 20,000 20,000 50,209 OR 0002 Food Amalgam ated Sugar C

ompany, The X 987 0 74 74 OR Wood/Pap er/Pu lp X Not in previous report 0 OR 1849 Wood/Pap er/Pu lp Boise Cascad e Compa ny X 1,834 1,532 411 1,943 OR Oil/Gas X Not in previous report OR 0005 Wood/Pap er/Pu lp Georgia-Pacifi c West, Inc. X 452 258 143 401 OR 0007 Metals/Mining Glenbrook Nickel C ompany 0 0 OR 2125 Metal s/Min ing/M inerals Globe Metallurgi cal Inc. 197 0 OR 0036 Wood/Pap er/Pu lp X 0 0 OR 0004 Wood/Pap er/Pu lp James River II, Inc. Georgia - Pac ific (Wauna

Mill) X 643 1,361 277 1,638 OR 0001 Metal s/Min ing/M inerals Northwest Aluminum Company, Inc. X 397 518 518 OR 1876 Glass Owens-Brockway Glass Container, Inc. X 108 131 131

### Table XIV-2 (continued)

State Facility

ID Sector Des cription Facility N ame (1990) Current Facility Name In Current Report Comments SO 2 Emissions Year 2000 SO 2 NonBoiler Allocation SO 2

Boiler Allocation Total

SO 2 Allocation State

Totals

XIV -5 OR 3501 Wood/Pap er/Pu lp Pope & Talbot Pulp, Inc. X 293 248 107 355 OR 1851 Metal s/Min ing/M inerals Reynolds Me tals Com pany X 1,510 1,558 1,558 OR 6142 Wood/Pap er/Pu lp Smurfit Newsprint C orporation 2 X No longer pulping 519 0 0 OR Wood/Pap er/Pu lp West Linn Paper Co. X Not in previous report 0 211 211 OR 8866 Wood/Pap er/Pu lp Weyerhaeuser Com pany SierraPine, Ltd

. X 0 0 0 0 OR 0471 Wood/Pap er/Pu lp Wil lamette Industries, Inc. X 327 310 310 OR 8850 Wood/Pap er/Pu lp Collins Products LLC Weyerhaeuser Co. X Weyerhaeu ser S pringfie ld 1,721 1,668 362 2,030 OR 5034 Misc. Cascade Steel Rolling Mil ls, Inc. 0 0 OR 2028 Oil/Gas Kinder Morgan Energy Pa rtners, L.P X OR 0041 Chemicals/Plastics Georgia-Pacifi c Resins, Inc. 0 OR 0013 Wood/Pap er/Pu lp J. Peterkor t & Com pany Collins Products LLC 0 OR 5398 Wood/Pap er/Pu lp Ogden Martin Systems of Marion, Inc. Covanta Marion, Inc. X 0 OR 2050 Misc. Oregon Health S ciences Univers ity OHSU X 0 0 OR 0015 Wood/Pap er/Pu lp Weyerhauser - Coos B ay Hog wast e-fired boiler 882 0 9,169 UT 10572 Copper Kennecott U tah Copper C orp. X Smelter 2,534 1,000 700 1,700 UT 10096 CHP Sunnyside Co generation Ass

ociates X 1,054 1,270 1,270 UT 0004 Oil/Gas Amoco Petroleum Products Tesoro X Refining 1,368 1,388 1,388 UT 0004 Misc. Brigham Y oung University X 125 1 1 UT 0001 Metal s/Min ing/M inerals Brush Well man Inc. X 179 23 23 UT 0003 Oil/Gas Chevron Prod ucts Com pany X Refining 1,242 1,240 1,240 UT -9902 Metal s/Min ing/M inerals Continental Lime Inc. Graymont X Lime 331 303 303 UT 0008 Oil/Gas Flying J Incorpora ted X Refining 300 674 674 UT 0027 Metal s/Min ing/M inerals Geneva Stee l X Shutdown coke ovens

and sinter plant 979 17 17 UT 0001 Cement/ Concrete Holnam In corporated Holcim X Cement 288 267 267 UT 0013 Oil/Gas Phillips 66 Com pany X Refining 601 762 762 UT Oil/Gas Silver Eagle Refini ng Inc. X Not in previous report (Refining) 77 77 UT -9901 Oil/Gas Unocal Corporat ion Tom Bro wn-Lisbon P lant X Natural gas pro cessing 1,252 1,593 1,593 UT 10676 Utelite Corporation 133 0 0 9,315
WY 0012 Oil/Gas AMOCO - ELK BAS IN HOWELL PETROLE UM - ELK BASIN X 2,638 1,200 1,200
WY 0012 Oil/Gas AMOCO - WHITNEY CANY ON X 6,889 5,602 5,602
WY 0009 Oil/Gas CHEVRON - CARTER CREEK X 2,096 200 200
WY Cement/ Concrete Centex X Not in previous report 165 165
WY 0013 Oil/Gas EXXON - SHUTE CREEK X 1,383 1,536 1,536
WY Oil/Gas EXXON BLACK C ANYON D EHY & WELLFIE LD 167 0
WY 0010 Metal s/Min ing/M inerals FMC - GRA NGER (TEX

AS GULF) X 212 305 305
WY 48 Metal s/Min ing/M inerals FMC - GREEN RIVER X 4,901 956 956
WY 0001 Metal s/Min ing/M inerals FMC COKING PLANT ASTARIS COKING PLANT X Shutdown April 2001 1,409 0
WY 0001 Oil/Gas FRONTIER OIL & REFINING - CHEYENNE X Refining 1,396 863 863
WY 0002 Metal s/Min ing/M inerals GENERAL CHEMICAL X 5,000 750 750
WY 0001 Food HOLLY SU GAR - TORR INGTON X 178 23 23
WY Oil/Gas INTERENERGY - HILAND WILDHORSE ENERGY - HILAND X 269 281 281

WY Oil/Gas KCS MOUNTAIN RESOURCES - GOLDEN EAGLE X 17 790 790
WY Oil/Gas KCS MO UNTAIN RE SOURCES - AINSWORTH X 0 843 843
WY 1 Oil/Gas KCS Mou ntain Resource s Rushm ore X 118 118 118
WY 0005 Chemicals/Plastics KOCH SULFUR PRODUCTS COMPANY PEAK SULFUR X Sulfuric acid plants 1,245 1,197 1,197

WY Oil/Gas LOUISIANA LAND & EXPLOR - LOST CA BIN b BURLINGTON RESOURCES - LOST CABIN

b X 213 1,867 1,867
WY 0007 Oil/Gas MARATHO N GAS P LANT - ORE GON BAS IN Oregon Basin G as Plant X 358 391 391
WY Oil/Gas MARATHO N OIL - M ILL IRON X 0 247 247

### Table XIV-2 (continued)

State Facility

ID Sector Des cription Facility N ame (1990) Current Facility Name In Current Report Comments SO 2 Emissions Year 2000 SO 2 NonBoiler Allocation SO 2

Boiler Allocation Total

SO 2 Allocation State

Totals

XIV -6 WY 1 Oil/Gas Marthon Oil Pitc h Fork Batte ry X 61 61 61
WY 0003 Metal s/Min ing/M inerals SWEETW ATER RESOURCES P4 PRODU CTION - ROC K SPRIN GS X Rotary coke r 633 631 631
WY 0022 Chemicals/Plastics SF PHOSPHATES, INC X Sulfuric acid plants 1,790 1,638 1,638
WY 0001 Oil/Gas LITTLE AMERICA REFINING COMPANY SINCLAIR - CASPER X Refining 1,458 1,040 1,040
WY 0011 Oil/Gas SINCLAIR @ SINCLA

IR X Refining 3,407 1,066 1,066
WY Oil/Gas SNYDER OIL - RI VERTON DOME DEVON SFS - RIVER TON DOME 492 0
WY Metal s/Min ing/M inerals SOLVAY MINERA LS X 52 294 294
WY 0012 Oil/Gas TEXAS-BYRON PLANT BIG HORN GAS PR OCESSIN G - BYRON X Texaco 257 200 200
WY 0008 Oil/Gas UNION PAC - BRADY RME PETROLEUM - BRADY X 300 0
WY 0005 Misc. UW CENTRAL HEAT PLANT X 193 22 22
WY 0001 Oil/Gas WYOMING REFINING CO WYOMING REFIN ING - NEWCASTLE X Refining 876 449 449
WY 008 Oil/Gas DEVON S FS OPERA TING CO. BEAVER CREEK X 831 0
WY 0003 Metal s/Min ing/M inerals AMERICAN COLLOID - WEST COLONY 0
WY 0002 Oil/Gas AMOCO REFINERY Closed 0 0
WY 0001 Metal s/Min ing/M inerals BENTONITE CORPORA

TION LOVELL 0 0
WY 0014 Oil/Gas COLORADO INTERSTATE GAS - TABLE ROCK 0 0
WY 0013 Oil/Gas MARATHON OIL COMPANY - GARLA ND 0 0
WY Oil/Gas Hallwood Pet roleum-Federa l Packsaddle 1- 24 X Not in previous report 133 133
WY Oil/Gas Hallwood Pet roleum-Federa l Packsaddle 1 X Not in previous report 960 960 23,828 TOTALS 170,226 167,583 167,583

a SO 2 Allocation based on histo rical emissions.

b Plant has j ust added ca pacity and allocat ion is based on current (July 2 002 capacity).Appendix A-8 – SO2 Milestones/Backstop Arizona Regional Haze SIP 

## Appendix A-8b. Western Emission s Backstop (WEB) Emissions & Allowance Tracking Sy sterm (EATS) Analysis

# Western Backstop (WEB)

Emissions and Allowance Tracking System (EATS) Analysis

Prepared by: Perrin Quarles Associates, Inc. 675 Peter Jefferson Parkway, Suite 200 Charlottesville, VA 22911

July 18, 2003

### Table of Contents

Page

I. Introduction

........................................................... 1

II. Overview of the System and Analysis

....................................... 1

III. Functional Areas

...................................................... 3 A. Source Inventory

................................................ 3 B. User Management

............................................... 5 C. Account Management

............................................. 6 D. Allowance Allocations (Initial and Ongoing)

............................ 7 E. Allowance Trading

.............................................. 10 F. Annual Compliance Assessment

.................................... 12 G. Emissions Tracking and Emissions Reporting

........................... 15 H. Program Assessment and Analysis

.................................. 18 I. Public Information Needs and Requirements

............................ 19

IV. Types of Users

...................................................... 19 A. State and Tribal Users

........................................... 20 B. Industry Users

................................................. 21 C. General Account Holders

......................................... 22 D. Tracking System Administrator

..................................... 23 E. Public Users

................................................... 24

V. Technical Architecture

................................................. 24 A. Security

...................................................... 25 B. System Performance

............................................. 27 C. Maintainability

................................................. 28 D. System Outputs

................................................ 28 E. Application of Platform Selection Criteria

............................. 29

VI. Design and Development Approach

....................................... 30 A. Recommended Implementation Methodology

.......................... 30 B. Timing/Schedule

................................................ 32 C. Cost Factors

.................................................. 32

VII. TSA Responsibilities and Performance Criteria

.............................. 33 A. TSA Responsibilities

............................................. 33 B. TSA Performance Criteria

........................................ 36

### List of Figures

Page

Figure 1: Overall WEB EATS Model

......................................... 2 Figure 2: Flow Chart of Allowance Allocation Process

............................ 10 Figure 3: Flow Chart of Annual Compliance Assessment Process

.................... 14 Figure 4: Use Case Diagram: State and Tribal Users

............................. 20 Figure 5: Use Case Diagram: Industry Users

................................... 21 Figure 6: Use Case Diagram: General Account Holders

........................... 22 Figure 7: Use Case Diagram: Tracking System Administrator

...................... 23 Figure 8: Use Case Diagram: Public Users

.................................... 24-1- 

### July 18, 2003



### Western Backstop (WEB) Emissions and Allowance Tracking System (EATS) Analysis

I. Introduction

This section of the State Implementation Plan/Tribal Implementation Plan (SIP/TIP) is an analysis of the information management needs of the Western Backstop Emissions and Allowance Tracking System (WEB EATS) which is a requirement for the program under 40 CFR 51.309. Section 309(d)(h)(4)(v) of the Regional Haze rule requires that "the Implementation Plan must provide for submitting data to a centralized system for the tracking of allowances and emissions." The purpose of this document is to describe the architectural and system requirements necessary to support a State/Regional emissions trading program information system. The document summarizes the overall needs and objectives of an emissions trading system to ensure successful implementation of the program. It is intended to serve as a roadmap to help WRAP implement the program once it has been triggered.

II. Overview of the System and Analysis

Figure 1 contains a graphical depiction of the overall information system, including the basic users, functionality needed for each of these user types, and a high level architecture. Section III

describes each functional area of the application. Section IV describes the primary user groups and how they relate to the functional areas. Section V describes the considerations affecting the choice of technical architecture for the application. Section VI describes recommended design and development approaches, and Section VII addresses the overall responsibilities of the Tracking System Administrator (TSA).

The development and deployment of this application, if needed, would most likely occur after 2013, possibly later. It is assumed that currently available technology would not be used, nor is it possible to project what advancements in technology would be available. For this reason, this report does not address specific technologies, except as a reference point for better understanding or describing capability that would be needed. The focus is on general issues related to technology and the functional requirements for designing and implementing the

program.

The scope of the application and information system needs which are described do not extend to several areas relating to the possible implementation of the Backstop Trading Program envisioned by Section 309. Excluded areas include the baseline emissions inventory for determining whether the program triggers, performing initial allowance allocations, and evaluating and tracking early reduction credits. Also, it has been assumed that it is not necessary to support a significant level of variation in requirements or needs from different States or tribes and that areas in which these requirements may vary, such as enforcement activities beyond the automatic provisions of the program, would be addressed in other systems.WEB EATS AnalysisJuly 18, 2003-2-

Application

Database WEB EATS

Public

EPA Emissions Database Program Emissions Inventory Public Data Industry

General Accounts ü Query Data

ü View Standard Reports ü Manage Application and Users

ü Conduct Compliance Assessment

ü Develop Reports

ü Coordinate Program Implementation ü Complete Registration

ü Transfer Allowances

ü Submit Emissions

ü View Reports

ü Add/Update General Accounts

ü Transfer Allowances

ü View Reports The System Administrator ü Allocate Allowances

ü Approve Sources and Units

ü Approve Monitoring

ü View Reports Tribal Set-aside Allocation System States/Tribes 

### Figure 1

Overall WEB EATS Model

### WEB EATS Analysis July 18, 2003

-3- 

### III. Functional Areas

The system to support the WEB Trading Program must contain functionality to support implementation of the trading program in the following areas: source inventory, user management, account management, allowance allocations, allowance trading, emissions reporting and collection, compliance, and program assessment. At this time, the system functionality does not include consideration of allowance transfer price data. However, there may be a need to include this functional area in the final system design, and the overall system design needs to allow for this possible expansion of the functional areas. Because the core requirements for allowance transfer price tracking remain uncertain, this section does not discuss this functional area in further detail. Each of the other areas of functionality is described below. In addition, core requirements relating to the areas are defined.

A. Source Inventory

1. Description

a. Facilities and Units

The central focus of the system is the list or inventory of sources which are affected by the program. This inventory is initially derived from the baseline emissions inventory developed to support the development and approval of the WEB Trading Program as part of the SIP/TIP approval process. To this initial inventory, it is expected that States and Tribes may add sources, either during the period prior to triggering the program or after the Program Trigger Date. Throughout, it is expected that sources will permanently cease operation or "retire." To support the dynamic inventory, the information system must allow the addition of new sources and track the status, including the regulatory status, of all sources identified as potential program participants beginning with the baseline period.

To support changes in facility operation and ownership in both the pre-trigger and posttrigger period, it will be necessary to track basic changes in facility identity, including facilities which, due to these types of changes, change "identity" or divide into two facilities. This functionality would include tracking facility name changes.

It is assumed that States and Tribes would be responsible for identifying all "new" sources to the database and for making decisions and entering data about the applicability of the program to a new source. Once a source is identified as being subject to the program, the maintenance of these data would be the primary responsibility of the owners and operators of affected sources through the source representative. A single, secure portal for changing these data would be provided to authorized industry representatives.

### WEB EATS Analysis July 18, 2003

-4- 

### b. Source Owners

The owners and operators of each source authorize individual(s) to represent them regarding allowance trading, emissions reporting and all other compliance activities. The identity of the owners and operators should be tracked to ensure that legal responsibility for compliance can be accurately determined at any point in time during which compliance is required. The WEB EATS should track changes in owners and operators for a source.

c. Source Representatives

The designated representatives appointed by the owners and operators of the source are also tracked so that appropriate communication about program activities involving the source and compliance is facilitated. Under the Duty to Register provisions, representatives of a source initially must register and use consistent source identifiers with the source program data first entered by the State or Tribe. The representative is responsible for the accuracy of submissions and certifying source compliance. Program rules should be structured to ensure that at no time during the operational phase of the program is an affected source unrepresented.

d. Source and Unit Detail

Additional information about the facility and units, including fuels, controls, and other operational information would be necessary for program implementation, particularly with respect to emissions monitoring, and for program assessment. During the design phase for WEB EATS development an assessment of these needs and the availability of information from other sources (for example, a shared air program database at EPA or in a State/Tribe) should be performed.

2. Core Data Entities and Attributes

! Facilities . Location, source category or type, permit IDs, size, Federal and State/Tribal cross identifiers with other data systems, program status, operational status (including retirement status), initial on-line date (for new sources).

! Units . Relationship to facilities, type, Federal and State/Tribal cross identifiers with other data systems, operational status (including retirement status), initial on-line date (for new units).

! People . Type and duration of relationship to facilities, type and duration of agent relationship to representatives, address, affiliation, security level, user ID, passwords (or equivalent), phone numbers, email or equivalent.

! Owners/operators . Address, relationship to facilities.

### WEB EATS Analysis July 18, 2003

-5- 

### ! Program applicability

. Exemptions, opt-in or other program status information, including year affected (or non-affected), identification of Category 1 and 2 sources, etc. Could include permitted production capacity or other permit data.

3. Core Functional Requirements

! Populate initial facilities and units. ! Add and update facilities and units. ! Add and update owner/operator information. ! Change owner/operators for facilities. ! Add and update individual information for any person utilizing or identified in the application. ! Change representatives for facilities. ! For on-line changes, provide to users documentation of changes in owners and representatives to meet recordkeeping requirements. This could be email or other electronic format. ! Track changes in facility names and program identifiers and relationship to prior entities. ! Communicate/verify facility and unit inventory changes, particularly where change impacts regulatory status or responsibilities or triggers deadline. ! Add and update program applicability data.

B. User Management

1. Description

User security and authentication are key requirements for the WEB EATS. To support these requirements the application must contain functionality to store user identifying information and associate each user with the appropriate security level. A system administrator, or person designated by the system administrator, must use tools provided in the application to review and approve user accounts, and to access and monitor usage.

For any on-line access and submission by an industry user, the system should require appropriate compliance certifications and contain a record of certifications.

2. Core Data Entities and Attributes

! People . Relationship to facilities or to representatives and their agent, address, affiliation, type, security level, user ID, passwords (or equivalent), phone numbers, email or equivalent.

### WEB EATS Analysis July 18, 2003

-6- 

### ! User Access Requests . User identification (per People), information to facilitate approval, status of request (approval, denial).

! Certification Records . Content of certification, date, user identification.

3. Core Functional Requirements

! Receive requests for user registration. ! Approve/deny requests and establish security groups. ! Provide notification of request status and assigned user ID and passwords (or equivalent). ! Develop and apply user privileges for specific functional areas and categories of data. ! Delete or archive users. ! Revoke or modify user access privileges. ! Display appropriate certification statements for review and agreement.

C. Account Management

1. Description

In the model rule, an Allowance Tracking System account is defined as an account "established for purposes of recording the allocation, and for holding, transferring, or deducting allowances." The WEB EATS should contain at least four types of accounts: general, compliance, retirement and government accounts. It must include a range of functionality to support each type of account.

A compliance account holds allowances which are used for compliance purposes. There is one compliance account for each source subject to emissions trading requirements and the compliance account is assumed to have the identical owners and representatives as its associated source. A compliance account should be automatically created for each new source when a source has met the appropriate registration requirements. For specified periods, compliance accounts or the allowances in those accounts may be subject to restrictions on trading to facilitate annual compliance assessment.

A general account allows anyone to hold allowances separate from the compliance and true-up process. A representative for a facility must move allowances from a general account to a compliance account before the true-up deadline in order to use them for current year compliance. A general account is created upon request of any individual or entity, and like a facility's compliance account, must have a defined owner and an individual person named as an account representative. General accounts are populated through trading functions, described below. The system administrator should have the ability to archive or deactivate a general account if specified criteria are met (such as containing no allowances for a specified period of time). For analysis purposes, the type of general account holder should be identified.

### WEB EATS Analysis July 18, 2003

-7- 

### A retirement account holds allowances which have been used for annual compliance to offset emissions or which have been voluntarily removed from the market by its owners. At least one retirement account will be identified initially; additional accounts may be necessary to meet specific needs, if a detailed analysis of requirements indicates that separating retired allowances would be useful for analysis or other purposes.

A government account holds allowances which are still under the control of a State or Tribe (or, as their agent, the Tracking System Administrator). These accounts will contain serialized allowances to be allocated in the future. The new source set-aside, for example, is a government account.

2. Core Data Entities and Attributes

! Accounts . Identification number, type, restrictions, relationship to source (if any), State/Tribe, or owner/representatives, owner type.

! People . Type and direction of relationship to accounts, address, affiliation, security level, user ID, passwords (or equivalent), phone numbers, email or equivalent.

! Owners/operators . Address, relationship to accounts.

3. Core Functional Requirements

! Add/create general accounts. ! Change owner/operators for general accounts. ! Change representatives for general accounts. ! Add/create retirement, government, and compliance accounts (system admin only). ! Implement freeze on account or specific allowances within account. ! Archive or delete accounts. ! Notification of changes to user and other responsible persons.

D. Allowance Allocations (Initial and Ongoing)

1. Description

The system should support both initial and ongoing allocations of allowances from government accounts into compliance accounts. The initial allocation for the first five year period would be provided by States or Tribes in a format to be defined by the TSA and system designers. It is recommended that the allocation process replicate the transfer of allowances from account to account, thus creating an audit trail of the allowance back to its original issuing State or Tribe. It is recommended that the system design include a standard file format for submission of initial allowance allocations by the State or Tribe.

### WEB EATS Analysis July 18, 2003

-8- 

### All allowances would be serialized according to a numbering system to be determined as part of the system design when they are initially populated in the application. This serial number would be a permanent attribute of each allowance and could not be changed.

Ongoing allocations, which occur every five years for all allowances, would be supported through a process similar to the initial allocation, depending primarily on a standard file format, containing allocations determined by the State or Tribe for the period.

The application should generate a draft and final Regional Allocation Report for each five year allocation period.

The application should support periodic allocations of allowances to compliance accounts for new sources from the new source set-aside. Specialized tracking and reporting would be needed to record the date of all requests and the status of the set-aside account. When this account is depleted, the tracking information would be used to prioritize allocation of future allowances to these sources.

The application must support allocations of allowances for opt-in sources on an annual basis. It is assumed that the State or Tribe would provide data to support opt-in source allocation (including source identification) either on-line or in an electronic format.

The application must support notification of all allocations to registered sources and to the appropriate State or Tribe.

If a source representative elects a monitoring option for a unit under 1.(b) of Section I (Monitoring, Recordkeeping and Reporting) of the model rule, the source representative would submit a request to the State or Tribe about this election, and must provide information about the portion of the facility's allowance allocation attributable to these units. Upon approval of the request by the State or Tribe, the TSA (or the State or Tribe directly) would mark the appropriate number of allowances as "non-tradeable" in the allowance account for the source for all years already allocated. A record of the request and approval would be stored, so that future allocations would also be marked as non-tradeable. If the special monitoring status under Section I1.(b) is revoked or no longer applicable, the "non-tradeable" status of the allowances would be changed by the TSA.

2. Core Data Entities and Attributes

! Accounts . Identification number, type, restrictions, relationship to source, State/Tribe, or owner/representatives, owner type.

! Allowances . Serial number, type, origin, year (if not indicated by serial number), nontradeable indicator.

### WEB EATS Analysis July 18, 2003

-9- 

### ! Transactions . Transaction identifier, date, allowance range, transferor account, transferee account, type of transaction.

! Action Log . Type of submission or request, user, source, status, etc.

3. Core Functional Requirements

! Import of allowance allocations from file provide by State or Tribe. ! Assign serial numbers to new allowances. ! Notification system to automatically inform industry users of allocations and future responsibilities. ! Notification or report system to keep States and Tribes informed re allocation status. ! Tracking capability for new source set-aside requests. ! Allocations to compliance accounts from new-source set aside.

### WEB EATS Analysis July 18, 2003

-10- WEB EATS automatically notifies industry users of allocations and future responsibilities WEB EATS assigns serial numbers to new allowances

WEB EATS automatically notifies States and Tr

ibes regarding allocation
status WEB EATS im

p orts allowance allocations from file provided by State or Tribe

WEB EATS allocates

new

- source set

- aside to new Source compliance accounts 

### Figure 2 Flow Chart of Allowance Allocation Process

E. Allowance Trading

1. Description

The ability to trade allowances supports the underlying principle of an emissions trading program and the functionality to support allowance transfers is critical to the WEB EATS. Security of the data and transparency of the transfer record are critical to the overall program and should be carefully evaluated. The WEB EATS must provide the TSA the ability to maintain information on all current account holdings and an audit trail of all allowance

### WEB EATS Analysis July 18, 2003

-11- 

### transactions, including both market transactions and regulatory transactions. The current standard for emissions trading programs established by EPA is to allow industry users to record allowance transfers on-line in real-time. These applications support both interactive, on-line transfers and batch transfers using specified file formats to transfer larger numbers of allowances. For batch transfers, industry has developed software to monitor allowance ownership and submit large volumes of allowance transfers with a minimum of user intervention. It is assumed that the technical capability for secure system-to-system interactions will continue to improve and that this approach will be more widely used in the future. Current allowance trading systems also support transfers performed by the TSA based on the receipt of paper forms. It is assumed that the reliance on paper forms will continue to diminish. Whether this functionality should be supported in the WEB EATS should be evaluated.

During the true-up period, activity in compliance accounts is frozen to allow the TSA to conduct the necessary compliance evaluation and allowance retirement. The WEB EATS would allow users to submit allowance transfers for allowances involved in an ongoing compliance process, but these transfers would be held and recorded following the completed process. All affected parties would be informed of the status of these transfers both when submitted and when finally recorded or denied.

For on-line transfers performed interactively by the transferor, the WEB EATS should provide access only to those accounts over which the transferor currently exercises control. Account access would be determined by the WEB EATS based on the user's relationships to specific general or compliance accounts. From these accounts, the user would select the accounts and specific allowances for the transfer. The user would then identify the account into which the allowances should be transferred. It is assumed that eligible recipients include general accounts, compliance accounts or a voluntary retirement account. The user would be asked to review and verify the transfer prior to its taking affect.

The process for electronic transfers of batch transfers will be more technology dependent. It would undoubtedly require definition of file transfer formats and security standards to ensure authentication of the submitter and completeness and quality of the data. It is not feasible to predict standards or available technology for this process at this time.

The paper-based process used by the TSA would be similar to the interactive process. Depending on the volume of paper transfers, redundancy of data entry or additional verification should be considered to ensure data quality and accuracy.

For all transfers (interactive, batch or paper), the WEB EATS must support a process of communication to both the transferor and transferee so that transfers recorded are fully disclosed to all parties and errors or other disputes between parties can be quickly identified and resolved.

### WEB EATS Analysis July 18, 2003

-12- 

### The WEB EATS must support a process of either transaction reversal or transaction error correction, or both. This functionality would be restricted to the TSA.

Reports would be available to the TSA and designated State/Tribe users to review specific transactions or overall transaction activity at any time.

2. Core Data Entities and Attributes

! Accounts . Identification number, type, relationship to source, State/Tribe, or owner/representatives.

! Allowances . Serial number, type, origin, year (if not indicated by serial number).

! Transactions . Transaction identifier, date, allowance range, transferor account, transferee account, type of transaction, status.

3. Core Functional Requirements

! Interactive transfer. ! Batch transfer. ! Capability to freeze compliance accounts with regard to allowances involved in ongoing compliance assessment. ! Notification to transferor and transferee. ! Reports and summaries. ! Allowance transaction audit trail.

F. Annual Compliance Assessment

1. Description

Following each control period, the TSA must perform an assessment of annual compliance with the basic program requirement that each affected source hold a number of allowances equal to or exceeding the tons of SO 2 

### emissions for the period. The compliance module of the WEB EATS would support receipt of annual compliance notifications and certifications by the source representative. It is expected that most representatives would provide the certifications and designate allowances to be deducted using an on-line access similar to the allowance transfer capability. Following receipt of the annual compliance forms, the WEB EATS would then compare the allowances held in the compliance account and the level of emissions for the source (taking into account the year of allowances, flow control limitations and prior exceedances) and deduct the appropriate allowances from compliance accounts into retirement accounts. Emissions reported at the unit level would be "rolled" up to the facility level. The process would result in a compliance report or compliance assessment notification to source representatives, States and Tribes.

### WEB EATS Analysis July 18, 2003

-13- 

### In addition, the WEB EATS would assess the need to apply flow control in subsequent years and determine the appropriate flow control factor.

Finally, the WEB EATS would identify any failure to meet allowance limitations. Based on the level of excess emissions the WEB EATS would compute the appropriate penalties, both monetary penalties and deduction of subsequent year allowances.

2. Core Data Entities and Attributes

! Annual compliance certifications . Facilities, submitter name/ID, year, compliance certification statements.

! Tracking . List of facilities for whom an annual compliance certification is required, received, etc.

! Compliance Results . Penalties, deductions, status, year.

3. Core Functional Requirements

! Receive and store annual compliance certifications. ! Perform compliance assessment. ! Calculate exceedances. ! Calculate flow control applicability and ratios. ! Communicate compliance results.

### WEB EATS Analysis July 18, 2003

-14- WEB EATS compares allowances held in compliance accounts and the total leve l of emissions Source Representatives place appropriate amount of allowances to be deducted in compli ance accounts

WEB EATS deducts appropriate allowances in compliance
accounts WEB EATS calculates total emissions per Source including rollup to Facility level

WEB EATS provides compliance assessment notification to Source Representatives, States, and Tribes

WEB EATS assesses need to apply flow control in subsequent years and compute appropriate flow control factor

WEB EATS computes penalties based on exceedances 

### Figure 3 Flow Chart of Annual Compliance Assessment Process

### WEB EATS Analysis July 18, 2003

-15- 

### G. Emissions Tracking and Emissions Reporting

1. Description

Emissions tracking and reporting for compliance purposes following the program trigger will require a wide range of functionality and data tables. There will be a need to evaluate carefully how and whether the functionality of the Emissions Tracking Database used for milestone tracking inventory purposes can be utilized to support the post-trigger emissions reporting. Also, it will be very useful to identify any potential overlap with existing emissions reporting systems used for other national or regional trading programs. For example, EPA plans to put into place the Emissions Collection System (ECS) and Monitoring Plan System (MPS) sometime after 2004. Although the software itself may not be adaptable for use as the emissions reporting module of WEB EATS, the system requirements and design should be consulted as an additional, more detailed, roadmap in the initial stage of system design.

The following general areas of functionality would be required:

Reporting Requirements and Tracking Information. To facilitate program implementation, the WEB EATS would identify monitoring and reporting obligations of each source participating in the program and track the receipt of required information. At least three types of reporters are envisioned:

! Part 75 reporters (submitting SO 2 

### emissions reports directly to EPA);

! Hourly non-Part 75 reporters; and

! Annual reporters (not participating in trading because of monitoring limitations).

For each of these type of reporting there are distinctly different reporting obligations and functionality to support submissions and reported information.

Monitoring and Emissions Information for Part 75 Units. For Part 75 affected sources who are reporting SO 2 

### monitoring and emissions data directly to EPA, the assumption is that redundant submission of these data would not be required. Instead, the WEB EATS would access or receive information from the EPA system about submissions and reported values under Part 75. Although EPA does not share these data directly with other data systems currently, it is anticipated that technological advances and the demand for shared data by other emissions trading programs would make this not only viable, but routine, by the time the program trigger occurs.

Monitoring Information for Non-Part 75 Units. For non-Part 75 units monitoring under Section I of the model rule, the submission requirements are not spelled out in the model rule. We recommend and assume that the program require and support the electronic

### WEB EATS Analysis July 18, 2003

-16- 

### submission of monitoring plans that are needed to establish an identification base for monitoring methodologies, monitoring locations and monitoring systems. These data are needed to support periodic reporting of hourly emissions data and to ensure that the data from monitoring systems are certified and quality assured. Tracking capability would be needed to assist in identifying whether required submissions (electronic and hardcopy) have been received, reviews conducted and approvals issued. This capability would assist States and Tribes, the TSA, and source representatives in the implementation phase of the monitoring program.

Because monitoring plans contain important components which are either graphics or documentation and are not easily stored as data elements, system designers should consider including document management capability to complement the tracking of information and sharing of data between all parties. A robust document manager could provide a submission process and eliminate or greatly reduce submission of hard copy material. This is an area in which technical options and standard practices may improve significantly prior to the program trigger year.

Emissions Data for Non-Part 75 Units. For non-Part 75 sources required to monitor SO 2 

### emissions, the WEB EATS would support submission, processing and storage of hourly emissions data. By current standards, the volume of and processing capability for hourly data could be large. However, it is expected that processing power and data storage capability will continue to expand and costs will decline. It is also expected that the submission process would utilize the next generation of broadband access and communication, in whatever direction technology dictates. Standardization of data reporting protocols would probably facilitate design and implementation of data submission requirements. The shape of the WEB EATS would be dictated to a large degree by available technology, supporting basic functionality of receipt, tracking, checking, analysis, and communication between the regulated sources and program management.

Quality Assurance of Emissions Data. Underlying successful cap and trade programs is the assumption that the emissions recorded and traded are comparable from State to State, Tribe to Tribe and industry to industry. Clear monitoring protocols and quality emissions data are needed to maintain the viability of the program. The monitoring and emissions data collection process should include the appropriate level of checking, analysis to ensure accurate and complete monitoring and reporting. Part 75 is a useful model of standards and checking which has provided the appropriate level of market assurances about the quality of emissions. The designers and developers of the WEB EATS should provide comparable capability, including calculation checks, assessment of monitoring system quality assurance compliance, and the accuracy of missing data routines. Emissions data should be evaluated to check routinely and periodically for anomalies and inconsistencies.

Petition Tracking . To meet SIP approval requirements, petitions for alternative monitoring would require joint approval of the State/Tribe and the U.S. EPA. The WEB EATS should provide a mechanism to track petitions and their approval and disapproval in a centrally

### WEB EATS Analysis July 18, 2003

-17- 

### accessible location for all State, Tribal and EPA program administrators. The WEB EATS should highlight and define electronically any aspect of the petition which results in allowable changes to reporting of monitoring or emissions data.

Annual Emission Statements for Reduced Monitoring Units . For units with reduced monitoring requirements under Model Rule Section I1.(b), the owner or operator would submit an annual emissions statement. The WEB EATS would track receipt of these submissions and record the emissions value reported. Annual production data or other information may also be required on a case-by-case basis as a condition of State or Tribe acceptance of the request under Paragraph b. These data should also be recorded in the data system.

2. Core Data Entities and Attributes

! Tracking . Including projected monitoring and reporting deadlines, submissions, and approvals or other status.

! Emissions Methodology/Reporter Type . Compliance period, Facility/Unit.

! Monitoring Locations . Units, stacks and pipes and attributes.

! Monitoring Systems Detail . Monitoring systems, formulas.

! Certification and Ongoing Quality Assurance Test Data . Test dates, overall results, test detail data.

! Cumulative Quarterly and Annual Emissions

.

! Hourly Emissions Data

.
3. Core Functional Requirements

! Track deadlines, requirements and submissions. ! Communicate with users about upcoming deadlines or deficiencies. ! Receive emissions report, quarterly and annual. ! Receive original and revised monitoring plans. ! Receive monitoring system certification and quality assurance data. ! Receive quality assurance test data and perform quality assurance checks. ! Address data quality problems. ! Provide final emissions data for annual compliance.

### WEB EATS Analysis July 18, 2003

-18- 

### H. Program Assessment and Analysis

1. Description

Ongoing program assessment and evaluation is an explicit responsibility of the TSA and the system design and requirements should reflect the needs for various types of assessment including: environmental benefits, geographic impacts, market function, implementation successes and failures, co-benefits, and SO 2 

### control strategies. In each of these areas, the proposed database design should be evaluated to determine whether anticipated needs will be met. The analytical utility of the data in WEB EATS will be enhanced in some cases by ensuring that accurate and complete links to other databases are supported and maintained. Similarly, geographic analyses will be enhanced by having high quality and complete locational information. These data will facilitate the availability and use of deposition and other modeling data.

It is important to consider the needs of users who want access to basic and repeatable analyses and the needs of users who want access to the data to perform complex analysis or one-time analysis. The basic user may best be served by providing standard reports designed to provide a program overview, summary statistics or status reports on specific types of activity. Combined with basic filtering and sorting options, a well designed report will meet many of the ongoing needs. More flexibility in data analysis could be provided by developing a more robust query tool, perhaps with control over report formats and output file types. For the high end user with more complex analytical needs or requiring use of data volumes beyond the capability of the user interface platform, the ability to request and deliver data in standard formats should be considered. If it is determined that the basic user needs include access to large volumes of data in predictable summary formats or quick access to complex data, the design and development of a data warehouse to facilitate this access should be considered.

2. Core Data Entities and Attributes

! Data warehouse . To provide easier access to aggregated data for analysis purposes.

3. Core Functional Requirements

! Generate standard reports. ! Provide data query tool. ! Provide capability for data export and delivery. ! Provide links to other information systems.

### WEB EATS Analysis July 18, 2003

-19- 

### I. Public Information Needs and Requirements

1. Description

To support market trading, information about market activity must be available to market participants and the general public. This includes, in particular, information about allowance trades and the identity of market participants, including representatives. The specific data content would be evaluated in detail at the time of design and development. It is expected that public access to some data, for example the tribal allocations for set-aside, would be limited.

It should be noted that the timeliness of the data is a critical aspect; but it may be appropriate to provide access to different types of information at different intervals. For example, a daily update cycle for allowance trading and representative changes has been adequate for the Federal trading programs; access to reported emissions data may be provided quarterly or even annually.

The ease of access for the public is also important. The current standard is to publish data though the Web, either in a readable format such as .pdf, in a standard spreadsheet format or through a query tool which retrieves and displays data in .html format through a browser. Although the technology available for public access to information in the next decade is not easily predicted, it would be expected that similar methods of providing access would be selected. The technical architecture and data formats should be selected based on security, speed or performance, overall accessibility to the technology, and flexibility offered in terms of both output and format.

2. Core Data Entities and Attributes

! Data warehouse . To provide easier access to aggregated data for analysis purposes.

3. Core Functional Requirements

! Timely public access to source inventory, account, allowance and representative information. ! Public access to periodic emissions data. ! Data downloading or extraction.

IV. Types of Users

As depicted in Figure 1, there are five basic categories of users for the application: State and Tribal users; industry users; general account holders; the Tracking System Administrator; and public users.

### WEB EATS Analysis July 18, 2003

-20- States and Tribes

View Reports

Allocate Allowances to New Sources

Allocate Allowances to Compliance Accounts Approve Paragraph b Monitoring Add New Sources/Units Approve Petitions Develop Enforceable Procedures for Recording Data 

### A. State and Tribal Users

Staff members of a State or Tribe participating in the Backstop Emissions Trading Program would be key stakeholders and users of the application. These users would have read-only access to almost all data in the application and a variety of reports. They would provide key data to the system using a combination of data upload or on-line capability. These would include facility and unit and program applicability data, general allowance allocations, allocations from new source set asides, and approvals of monitoring submissions. These users would have no day-to-day responsibilities for the operation, management or maintenance of the application or data.

Figure 4

Use Case Diagram: State and Tribal Users

### WEB EATS Analysis July 18, 2003

-21- Industry

Update Compliance Accounts Transfer Allowances Change Source Representatives

Change Source Owners

View Reports Update Source/Unit Characteristics

Certify Compliance Submit Emission Reports Submit Monitoring

Petitions and Monitoring Plans 

### B. Industry Users

Representatives of the regulated community would also be key users of the application. These users would have access to data relating to sources under their control, as defined by their roles and responsibilities as source representatives. In this capacity, they would be able to maintain source and unit information, transfer allowances in compliance or general (that they set up) accounts to and from other accounts, and submit required emissions data and compliance certifications.

Figure 5 Use Case Diagram: Industry Users

### WEB EATS Analysis July 18, 2003

-22- 

### General Account Holders

Add/Update General Accounts Transfer Allowances View Reports Change General Account Representative

Change General Account Owner 

### C. General Account Holders

A representative for a general account would also have access to the application to update general account information, create new accounts, transfer allowances out of their general accounts to other accounts and to view reports. The general account holder would have limited (or no) access to source information, unless the holder is also a compliance account holder or until such information is determined to be public information.

Figure 6 Use Case Diagram: General Account Holders

### WEB EATS Analysis July 18, 2003

-23- 

### Tracking System Administrator

Add/Update/ Delete Facilities and Units

Add/Update/ Delete/Archive Owners/ Operators

Add/Update/ Delete Representatives Add/Update/

Delete Users

Perform Annual Compliance Assessment

Freeze/

Unfreeze Account Trading Populate

Compliance Accounts Generate Reports

Quality Assure Data Track Activities 

### D. Tracking System Administrator

The Tracking System Administrator (TSA) would utilize virtually all functionality contained within the application. In appropriate circumstances the TSA would act on behalf of State/Tribal, industry and general account users. In addition, the TSA would perform all types of system management and maintenance activities to ensure effective operation of the application. The TSA would approve access for all users of the application.

Figure 7 Use Case Diagram: Tracking System Administrator

### WEB EATS Analysis July 18, 2003

-24- 

### Public

Query Data View Standard Reports Extract Data 

### E. Public Users

Public users have read-only access to selected data within the system. This access would be consistent with the security requirements of the application and data.

Figure 8 Use Case Diagram: Public Users

V. Technical Architecture

A key component of system design is the selection of a common architecture. One of the major components of system architecture is the number of levels or layers in a system. An application installed on a user's machine that does not communicate with any other applications or systems is a 1-tier system. A client-server system, where one application sits on a user's computer (client) and another, related application sits on the server is a 2-tier system. Most Web applications are 3-tier systems, where there is a browser and Web server (client), a business logic server and a database server. The system should be built with at least three layers to separate the display (client), business logic, and database, so that each layer could be modified without having to change other parts. The exact architecture would be determined at the time of system design.

The final decisions about system architecture should consider many factors, including security, performance, and maintainability.

### WEB EATS Analysis July 18, 2003

-25- 

### A. Security

Due to the importance of data integrity and accuracy in the WEB EATS, security will be extremely important. The security measures should be based on current best practices and standards. The system's security can be divided into two areas: application and server level security.

1. Application Level Security

The system's application level security consists of the protective measures designed into the application's code. These include the logical measures to determine which users may access which areas of the system, the manner in which session management is handled and the protection of sensitive information, like passwords, at the application level.

! Password Encryption . The system must include a process to authenticate all authorized users to the system. Today's system utilizes encryption to protect the vulnerable data elements, such as user passwords. Implementation of an extremely robust encryption, routine or its equivalent should be incorporated into the system.

! Separate Logins . Each user should maintain a unique username and password, with the password encrypted and stored in a secure database. Each user should be assigned a unique ID.

! Separate User Types . The access rights and restrictions should be controlled at the user group level. Each user group would have a unique set of rights and restrictions within the WEB EATS. Upon user login to the system, the user's specific user group security should be verified and rights and restrictions set for the session. If the user belongs to multiple user groups, they should be assigned the highest rights for a given section or action among their user groups.

! Audit Trail . The system design should include specific requirements to maintain an audit trail of data adds, updates, and deletes for critical data elements. This audit trail should be designed to detect and resolve challenges to the data (for example, allowance ownerships), and as an additional means of restoring data should there be a breach of data integrity.

! Session Management . Strict session management control, in which session tokens are properly protected and validated, is essential. When two applications are run remotely from each other (like a browser and a server), they require session tokens to be able to communicate about the application state. To prevent attackers from hijacking activesessions and assuming the identity of a user, session tokens need to be regularly revalidated.

### WEB EATS Analysis July 18, 2003

-26- 

### 2. Server Security

The system's server level security consists of the protective measures designed to protect the server itself from inappropriate access. These include proper server maintenance and the modifying of default system passwords.

! Server-Side Data Validation and Business Logic . To the extent possible, all business logic and data validation should be checked and handled at the server level and not be coded at the client or browser level. Server-side validation improves performance and reduces the risk of a user bypassing business logic designed to prevent them from submitting invalid data. Server-side validation includes business logic as well as basic data type validation (i.e., length, range, data type, characters sets).

! Server Maintenance . The servers or host platform should be maintained according to security standards. For example, many of today's current servers are patched on a regular basis with the latest security releases as soon as they are available. Because flaws in server software are usually well known in the hacker community, it is important to protect the server from attackers.

! System Passwords . The system passwords to the servers or host platform should be modified from their defaults and changed on regular intervals. Because the default passwords for commercial servers are commonly known, they pose a security threat and should be changed. Also, standard security practices should be followed regarding the regular changing of passwords.

3. Physical Data Security

Physical data security should be provided by the measures to protect the data center, a specialized facility that hosts an application, from dangers. These dangers include theft, natural disasters, manmade catastrophes, and accidental damage (e.g., from electrical surges, extreme temperatures, spilled coffee, etc.). The data center that hosts the WEB EATS should maintain strong security practices and undergo periodic audits.

4. Backup and Recovery

The database should be backed up at least daily and the application files should be backed up regularly. It may be advisable to back-up the allowance transaction data at a more frequent interval, based on the frequency of use and level of recoverability deemed necessary. A copy of the backup files should be stored off-site from the data center to ensure minimum downtime should a catastrophe occur.

### WEB EATS Analysis July 18, 2003

-27- 

### A Catastrophe Recovery Plan (CRP) should be created to enable the application to return to service as soon as possible following a catastrophe. Most CRPs contain the following:

! Threat analysis, ! Risk assessment, ! Mitigation steps, ! Response and recovery plans, ! Damage assessment process, ! Salvage procedures, and ! Rehabilitation plans.

B. System Performance

The system's performance can be greatly improved with the intelligent application of best practices and procedures for performance tuning and system design. These include the following:

1. Database Design and Query Optimization

The database should be designed with performance in mind. All database queries should be optimized to maximize performance. Use of views and indices or similar database functionality should be considered to maximize database performance. By limiting the results to only those that will be utilized immediately, the system will minimize the server and network resource load.

2. Session Variables

System design or programming technologies that overuse session variables can degrade the performance of the system. Therefore, only information that absolutely must be maintained to keep the session active should be stored in session variables. Following a user logout or the expiration of a short time limit, session variables should be explicitly purged from memory.

3. Archiving Data

Data should be archived regularly to conserve database space and enhance performance. A mechanism should be provided for retrieving the archived data for reporting

purposes.

4. Data Volume

The data volume of the WEB EATS will be largely determined by the number of sources and the frequency of data collection. With a planned number of sources of less than a thousand, which may include the periodic submittal of hourly data collection, the database is

### WEB EATS Analysis July 18, 2003

-28- 

### projected to grow approximately 4GB per year. To ensure maximum performance, the database should be regularly re-indexed and monitored for performance. It is recommended that the emissions data collection component sit on a separate server from the business logic server for performance gains.

5. Frequency of Use

The system design should take into account the number of users, the level of access, and the volume of data provided by users for specific processes. The WEB EATS usage is expected to be well within the normal expectation of capability for a small to moderate size application. For emissions data submission, the volume of data may be relatively high (by current standards) and require special design consideration.

C. Maintainability

To achieve a flexible system that evolves with program needs, the system should be developed for maximum maintainability. If the application is based on vendor software, it should be built upon well-known technology and platforms. If it is custom developed, it should be well documented and based upon best programming practices and standards and developed in a common development language. These measures will minimize time and cost to maintain the application following implementation.

In addition, the programming team should be required to adhere to programming standards, including code organization and documentation, to facilitate support and enhancements after deployment.

Post-deployment modifications should be developed by a set protocol including input from users.

D. System Outputs

The system should support various types of outputs, including data transfers, electronic communications, like email, and connections to external systems. During the system design, the needs of the proposed users and the archiving of data should determine exactly which system outputs should be available.

1. Data Transfers

The periodic transfer of emissions and related data should be communicated to the application via a standard information exchange protocol. The exact protocol and procedure will need to be determined based on best practices and volume of data at the time of implementation. Each data record should be error checked to verify its integrity during the submission process.

### WEB EATS Analysis July 18, 2003

-29- 

### 2. Electronic Communications

The application should contain functionality that notifies parties via electronic communication upon the execution of certain actions. These actions would include, for example, allowance transfers, freezing/unfreezing accounts, and system maintenance notices. The exact list of actions, subsequent message media, recipients, and structures should be determined as part of system design.

3. External System Connections

The application would be expected to provide data to external data systems such as the Emissions Inventory System that the WRAP will be using to perform the program trigger evaluations tracking. The system should also support connectivity with the National Environmental Information Exchange Network and Tribal Emissions Implementation Software Solution (TEISS). The exact methods used to connect other systems will be determined at the time of system design.

The application should also be able to communicate and transfer data files to and from other EPA data and allowance tracking systems, such as the system supporting the federal SO 2 

### emissions trading programs.

E. Application of Platform Selection Criteria

During the preliminary phases of the system design, a significant decision will be the selection of the technology platforms or architecture for the system. These platforms include the Web server, business logic server, database server, and client interface. For each of these platforms, consider these issues with the following questions in mind:

! Data volume . Will the volume of data which must be maintained, transferred and analyzed be supported by the database and/or the application? Be sure to calculate the data volumes over the estimated life cycle of the project keeping in mind any applicable program specific or overarching regulatory requirements relating to government recordkeeping.

! Performance . What are the minimum performance requirements for basic application tasks, such as accessing the system, updating source information, transferring allowances? What are the minimum performance requirements for infrequent tasks, such as annual compliance assessments, data quality analyses, or submitting hourly emissions data? What are the performance requirements for reports?

! Relative Costs . What are the overall cost constraints? What is the acceptable ratio of design costs to development costs and initial deployment costs versus maintenance costs? Research these issues for comparable systems and platforms.

### WEB EATS Analysis July 18, 2003

-30- 

### ! Maintainability

. What specific standards and assumptions should be imposed for maintainability?

! Connectivity

. Which connectivity standards should the system support?

! Efficiency

. Are there specific design choices which will impact the efficiency of program implementation? Examine design options and platform options to maximize efficiency benefits of the information system for the overall operation of the program. To what extent should the efficiency benefits to regulated industry, general account holders and the public be taken into account?

! Availability

. What level of system availability is acceptable for each type of user?

VI. Design and Development Approach

The second objective of this document is to serve as a roadmap to help the States and Tribes implement the program once it has been triggered. Outlined below is an implementation methodology that the States and Tribes can follow to design, develop and deploy the system. In addition, this section provides an analysis of cost and scheduling factors that should be considered.

A. Recommended Implementation Methodology

Upon the trigger of the WEB Trading Program, detailed system requirements will need to be assessed. The following section recommends, steps to design, develop and implement an information system for the program. It is recommended that a workgroup be created and assigned responsibility for this task. The workgroup should be comprised of user group representation, program analyst(s), and technical specialist(s).

1. Requirements Verification

The first step following the need to implement the program will be to verify the requirements of the information system. Since many of the procedural elements of the SIP/TIP will be decided in the future, the exact functionality may have changed since the creation of this document. Therefore, detailed requirements should be verified and incorporated into a system analysis document. It is expected that this stage of the process will require significant participation of all stakeholders, particularly the States and Tribes participating in the program.

2. Assessment of Current Standards and Technology

Following the verification of requirements, the workgroup should research and assess the current standards and technologies applicable to this type of information system. Since this application would probably not be designed until many years after this document, it was

### WEB EATS Analysis July 18, 2003

-31- 

### determined that the current standards would have little value and these have not been evaluated or referenced.

3. Technical Architecture Option Evaluation

Just as the standards and technology should be evaluated, so should the possible technical architectures, as discussed above. Most systems at the time of the creation of this document are 3-tier, but that should certainly not limit the architecture of the WEB EATS. Also, the suggested measures for security and maintainability may no longer be applicable, and should thus be re-evaluated.

4. Closeness of Fit

Based upon the system analysis requirements, standards, and architecture assessments, the workgroup should perform a Closeness of Fit study to analyze the available products, technologies, and platforms available. By analyzing the field of products, technologies, and platforms available, the Closeness of Fit study should conclude with a recommended product or set of development technologies and standards.

5. Decision

Based upon the Closeness of Fit study, the workgroup should select a product from a vendor(s), develop a custom system, or a combination of the two.

6. Design/Customization/Development Strategy

Following the decision to either select a Commercial Off-the-Shelf (COS) product, develop a custom application, or customize an existing application, the workgroup should select a developer and/or TSA to design, develop and implement the system.

The development plan should include a careful review of the schedule of program implementation and requirements to ensure that the necessary elements of the application are in place at the appropriate time. A staged process, with design, development, and deployment of specific system modules, is recommended. For example, the initial phase of development would probably focus on the source registration capability and initial allowance allocations. Later development could include allowance transfers capability, annual compliance assessment or overall program assessments.

7. Development

Following agreement upon the system design, the developer or TSA should develop the system utilizing modern development best practices and procedures. It is recommended that the

### WEB EATS Analysis July 18, 2003

-32-

### developer and/or TSA work with the members of the requirements gathering workgroup to reaffirm and adjust requirements as needed.

8. Quality Assurance/Testing

Following the successful development of the system, the developer/TSA should submit the system for rigorous testing. A test environment should be set up and a test database should be populated with data that closely match the quantity and type of data that will be utilized during live transactions. All phases of the system should be rigorously tested by the developer/TSA, States and Tribes, and a select group of end-users.

9. Deployment

Following successful quality assurance of the system, the workgroup and the developer/TSA should agree that the system is ready to be deployed or implemented in a production environment. Prior to production, the database will need to be populated with the necessary baseline information including source inventory data, emissions data, users, etc. The developer/TSA should provide training/instructions to users of the system along with appropriate documentation. It is assumed that participating States and Tribes will work closely with the TSA to define and implement a communication strategy to ensure compliance with all program requirements and full use of the information management system developed to ensure its success.

B. Timing/Schedule

If there is no significant delay after program trigger in the initiation of the information system design and development process and if a staged approach to deployment is adopted, then an implementation schedule in which the necessary system elements are in place is achievable. This objective should be stated at the outset of the project.

It should be noted that the use of COS or the customization of an existing system might reduce the initial development time for the system. To fully design, develop and deploy a custom application by today's standards might extend one to two years. Additional time might be necessary if there were significant issues relating to functionality or process about which State and Tribal participants could not agree. Technology trends indicate that forthcoming design and development methodologies will likely reduce this estimate.

C. Cost Factors

Factors driving the cost of the information system include technical platform, design complexity, data volume, security level, and the level of and approach to integration with other data systems. The availability of and use of COS or another application as the basis for the application would also affect costs.

### WEB EATS Analysis July 18, 2003

-33- 

### 1. Technical Platform

The technical platform includes the server software and business logic systems that are required. There are a wide range of options for the level of solution required and cost. A middle-ground solution is most likely the most suitable for the WEB EATS, one that maximizes flexibility and maintainability.

2. Design Complexity

The level of complexity incorporated into the system design will be a large cost factor. Generally, the more complex systems are, the more they cost. Based on the current system analysis, the system design appears to be moderately complex. As with any application, the requirements phase of the project may result in relatively more or less complex requirements, directly affecting costs.

3. Data Volume

The amount or volume of data will be a key cost driver in selecting the database server. If only one database is utilized for both the allowance and emissions data in WEB EATS , the database will grow quickly and will require a high-end solution to maintain performance levels. It is expected that the relatively high data volume will require database optimization and regular tuning, which will add to the maintenance costs.

4. Security Level

The level of security built into the system will certainly affect the cost. The more robust the security model is, the more time consuming and costly to implement. The security level detailed in Section III(A)(I) dictates a moderate level of security.

VII. TSA Responsibilities and Performance Criteria

A. TSA Responsibilities

The Tracking System Administrator (TSA) will have responsibility for the deployment of the site, ongoing maintenance and the day-to-day program implementation tasks associated with the program. It seems likely that the TSA would also design and develop the information system, but it is not necessary that both development and support should be provided by the same organization. Regardless, the ongoing responsibilities of the TSA would include two types of support: information system and program implementation.

### WEB EATS Analysis July 18, 2003

-34- 

### 1. Information System

This category of support is to ensure that the information system is properly administered, supported and performs all required functionality.

! Data security . The TSA would assume responsibility for ensuring that the security of the site and the data is monitored and protected on an ongoing basis. This would include monitoring access to the site and attempted but failed access (particularly if occurring in significant volume).

! Data integrity

. The TSA would assume responsibility for ensuring that the integrity of the data is monitored and protected on an ongoing basis. This would include ensuring that the referential integrity of the data is maintained, a data backup plan is implemented, and any opportunities for data corruption are identified and addressed.

! Data quality assessment and corrective maintenance . The TSA would develop within the application and be responsible for performing data checks to identify duplicative information, data omissions or other data of poor quality that are not easily prevented by error checks or data standards. The TSA would make corrections to the data, as necessary, and maintain documentation of changes.

! WEB EATS enhancements . The TSA would document and evaluate any proposed enhancements, modifications or additions to the application. Working with the State/Tribe participants in the trading program and within established budget constraints, the TSA would perform, test and deploy the modifications (in coordination with the assigned programming team).

! WEB EATS documentation . The TSA would have responsibility for maintaining all technical documentation for the WEB EATS (including enhancements and for maintaining records relating to its ongoing operation).

! User technical support . The TSA would provide technical support to all users of the application. This would include telephone support and responses to requests or inquiries through other means of communications. The TSA would maintain records of all technical support and the TSA response. Technical support needs could also be addressed through the use of other support tools, comparable to the FAQs or online support systems currently in use.

! Performance monitoring . The TSA would be responsible for monitoring the overall performance and availability of the application for all types of users. This would include identifying the causes of any disruption of service or availability and identifying any persistent problems experienced by the user community.

### WEB EATS Analysis July 18, 2003

-35- 

### ! Database administration . The TSA would monitor data performance and perform all maintenance and optimization tasks affecting the performance of the database. The TSA would maintain records of all database administration activities.

2. Program Implementation

The TSA is also expected to implement the program for the consortium of States and Tribes participating in the program. This is necessary to ensure that the program will be implemented consistently and cost effectively.

! User access administration . This support would include evaluating and responding to user access requests, password changes, and related usage issues.

! Coordination with States and Tribes . The TSA will coordinate, as necessary, with each State or Tribe participating in the program to ensure that the State or Tribe fulfills their responsibilities and is aware of the need for their participation in decisions or issues. This includes aiding the States and Tribes in developing enforceable procedures for recording the necessary data. For example, the TSA would obtain allocation lists, petitions, retirement approvals, information about new sources, and reduced emissions monitoring under Section I1.(6) of the model rule from the State or Tribe.

! Perform allowance allocations . Using the information provided by the State or Tribe, the TSA would perform allowance transfers from government accounts to compliance accounts. The TSA would provide a report (or electronic file) to the State or Tribe of these actions.

! Periodic status reports on system activity and program implementation issues . On a regular basis (monthly, quarterly and annually), the TSA would provide to the participating State and Tribes a summary of program activity. This report would include, for example, a summary of allowance transfer activities, a status report on emissions reports, or the level of public access to the database.

! Annual compliance assessment . The TSA would perform the annual compliance assessment or true-up and would coordinate with industry, States and Tribes regarding the results of this process. Following review or approval by the participating States and Tribes, the TSA would finalize the compliance assessment by retiring the appropriate number of allowances from compliance accounts. An end-of-year compliance report would be made available.

! Communication strategy development/implementation/support . Throughout the life of the program, the TSA would work with the participating States and Tribes to maintain and implement a communication strategy and plan. The purpose of the plan would be to ensure full participation of affected sources in the emissions trading program and to

### WEB EATS Analysis July 18, 2003

-36- 

### maximize understanding of and knowledge about the program among all interestedparties. The content of the plan would include a strategy for general guidance, day-today communications to sources about their actions (transfer confirmations, data receipts, etc.), State/Tribal reports, communications between States and Tribes about ongoing program issues such as monitoring approvals or petitions, participant or public meetings and publications containing program results or environmental assessments.

! Overall program assessment . The TSA would assist the States and Tribes in designing and conducting an assessment of the overall program operation, costs, and environmental benefits on a periodic basis.

! Error correction, followup and documentation . The TSA would be responsible for correcting any data entry errors reported by users that are not within the security limits for the user.

B. TSA Performance Criteria

To ensure adequate support for the program, it will be necessary to establish performance criteria for the TSA.

1. Technology Standards

For the WEB EATS and technology support, the key criteria should be based on technology standards prevalent at the time of deployment and they should be tailored to the technical architecture selected for the WEB EATS. The following criteria would fall into this category and should be defined at the appropriate time. The importance of each of these factors should also be considered during the WEB EATS system design phase and in the selection of a technical architecture.

! System performance (response time, number of concurrent users supported, frequency of WEB EATS or database errors, etc).

! System availability (average downtime).

! Timeliness of public access to data.

### WEB EATS Analysis July 18, 2003

-37- 

### 2. Contract Performance Standards

Other important criteria relating to TSA performance would be the traditional criteria relating to overall performance with respect to basic contract terms. These would include:

! Responsiveness to customer concerns, ! Timeliness and quality of status reports, ! Overall cost, and ! Budget accuracy.

### WEB EATS Analysis July 18, 2003

-38- 

### References

1. Jenkins, George Henry. Information Systems Policies & Procedures Manual. Paramus, NJ: Prentice Hall, 1997.

2. "The Ten Most Critical Web Security Vulnerabilities." The Open Web Security Project

. 13 Jan. 2003. <http://www.owasp.org/>.

3. United States Environmental Protection Agency. Clean Air Market Programs. Emissions & Allowance Tracking System

.

4. United States Environmental Protection Agency. State/EPA Information Management Workgroup. Blueprint for a National Environmental Information Exchange Network

. June 2001.Appendix A-8 – SO2 Milestones/Backstop Arizona Regional Haze SIP 

## Appendix A-8c. Recommendati ons for Making Additional Determinations in the Context of Reasonably Attributable BART

# Recommendations for Making Attribution Determinations in the Context of Reasonably Attributable BART

Prepared by: The WESTAR Council

Prepared for: The Air Managers Commit tee, Western Regional Air Partnership

May 2003

# Recommendations for Making Attribution Determinations in the Context of Reasonably Attributable BART

Prepared by:

The WESTAR Council RA BART Phase II Working Group: Alice Edwards, Alaska Department of Environmental Conservation; Mike Sundbl om, Arizona Department of Environmental Quality; Deb Wolfe, Montana Department of Environmental Quality; Dana Mount, North Dakota Department of Health; Dave DuBois, New Mexico Environment Department; Colleen Delaney, Utah Department of Environment Qua lity; Alan Newman, Washington Department of

Ecology; Lisa Reiner, Quinalt Indian Nation; Bruce Polkowsky and Kr isti Gebhart, National Park Service; and Kristin Ga ston and Bob Lebens, WESTAR.

Prepared for:

The Air Managers Committee of the Western Regional Air Partnership in fulfillment of the Western Gove rnors’ Association contract #30203-13

May 2003

### Acknowledgements

The recommendations regarding the attribut ion process, the applicable technical approaches and the examples in this report are the product of the RA BART Phase II Working Group. The WESTAR Council ackn owledges the generous support of all the Working Group members. Alice Edwards, Alaska Department of Environmental Conservation; Mike Sundblom, Arizona Department of Environmental Qual ity; Deb Wolfe, Mont ana Department of Environmental Quality; Dana Mount, North Dakot a Department of Health; Dave DuBois, New Mexico Environment Department; Colleen Delane y, Utah Department of Environment Quality; Lisa Reiner, Quinalt Indian Nation; Bruce Pol kowsky and Kristi Gebhart, National Park Service; and Kristin Gaston and Bob Lebens, WESTAR.

Authors of the Attribution Techniques (S ection VI) are Mike S undblom (Monitoring); Kristi Gebhart (Receptor Modeling); and Dave Du Bois (Source Modeling), with assistance from Ajith Kaduwela, California Air Resources Board. Bruce Polkowsky and Colleen Delaney drafted the certification s ection and provided liaison betw een the Western Regional Air Partnership Market Trading Forum and th e Working Group. Alan Newman, Washington Department of Ecology drafted the portion of th e report outlining the example process to which Dana Mount also contributed. Kristin Gaston drafted the regulatory c ontext section and along with Bob Lebens, edited the report.

## EXECUTIVE SUMMARY

This report recommends a genera l procedure and applicable te chnical approaches that may be used by states and tribes to assess reasonabl e attribution in response to a Federal land manager (FLM) certification of visibi lity impairment in a Cl ass I area (Certification).

WESTAR formed the Reasonably Attributab le Best Available Retrofit Technology (RA BART) Phase II Working Group with Federal land management agency staff and members of state and tribal air quality agencies knowledg eable about RA BART and associated monitoring and modeling techniques. To provide the nece ssary framework, the report provides background information about both the certification process and the attribution de termination process. However, the recommendations focus on the gene ral principles of the attribution assessment process and the technical criter ia used in the assessment.

The recommendations are summarized below:

General Principles :

The attribution assessment should be:

 A collaborative process that relies on existing data with minimal additional analyses.

 Technically and legally defensible.

 Accomplished at a reasonable cost a nd within a reasonable time frame.

 No more complex than necessary.

 Performed by state or tribal agency staff.

 Adequate to determine whether or not visibi lity impairment is attributable to an existing stationary source potentially subject to BART.

Technical Criteria :

 Emissions from BART-eligible sources must “cause or contribute to” visibility impairment. Visibility-impairing pollutant s of concern must be identified.

 Factors to consider in assessing impa irment include: duration, frequency, geographic extent, magnitude, and time of occurrence.

 Identify distance from source to Class I area to determine appropriate tools for characterization of the impairment.

 Quantitative results are preferable, although qualitative results such as photographs may be adequate.

 Use as many different indicators of impairm ent as practicable rather than relying on a single indicator.



##  Consider level of uncertainty in the assessment.

 Use EPA guideline models whenever practicable.

## Table of Contents

I. Backgr ound....................................................................................................... 1

A. Introduction and Purpose

B. Regulatory Context



## II. Federal Land Manager Cer tification of Impairment ........................................ 7

III. The Attribution Determ ination Process.............................................11

IV. General Principle s and Crite ria ...................................................................... 17

A. General Principl es of the Attribution Process

B. Technical Criteria

C. Examples of the Attribution Process



## V. Techni ques...................................................................................................... 31

A. Monitoring

B. Source Modeling

C. Observational Modeling



## VI. Appendix

RA BART Rule (40 CFR 51.300-306)

## I. BACKGROUND

A. Introduction and Purpose

Reasonably Attributable Best Available Retr ofit Technology (RA BART ) is the portion of EPA’s visibility rule pub lished in 19 80 and codified in 40 CF R 51.302–51.306 that d eals with visibility im pacts from one source or a sm all gr oups of sources. RA BART refers to reasonably attributable visibility im pairm e nt and best av ailable retrofit t echnology for eligible sources and

em ission lim its, and em issions controls as define d by the statute and the rules. Som e confusion exists rega rd ing the app l ication of RA BART, the process of a ssessing sources of visibility im pair m e nt, and the technical t ools available for an RA BART attribution determ ination. RA BART is a statutory requirem ent, although cer tain of the requirem ents m a y no longer be applic able w h en a sourc e com p lies with BART or insta lls BA RT-like con t rols or af ter a sta t e im ple m ents a trading program under 51.308(e)(2) or any trading program under 51.309, and if no

rem a ining visibility im pa cts continue from one source or a small group of sources.

This report, therefore, addresses the RA BART a ttribution process and builds upon case studies W E STAR developed in 2001 to exam in e and document how Reasonably Attributable Visibility Impairm e nt (RAVI) had been addressed in previous assessm ents. 1



### The Federal land m a nagers (FLMs) advocate m a intaining RA BART as a tool because RA BART is effective when new m onitoring indicat es that a previously un-m o nitored area has visibility problem s diffe ring from the regional visi bility im pa irm e nt conditions at other areas. In addition, RA BART is effective when BART-eligible sources in the vicinity of the protected area

are cau sing or contr i buting to iden tif ied vis i bility im pairm e nt. 2



### First, this re port re comm ends attrib ution pr ocess principles and a ssessm ent techniqu es a state or tribe m a y consider in an attribution as sessm e nt to identify if, and to what degree, an existing source or sm all group of sources causes or contributes to visibility im pairm e nt. The report focus e s on RAVI and does not specifically address im pairm e nt due to reg i onal h aze. Although this report includes referen ces to region al haze, such references serve only to place the attribution process in the larger context of the broad regulatory fra m ework that addresses visibility im pairm e nt, including the regional haze regulations.

Second, this report includes no recommendations with regard to establishing a threshold level at which reasonab l y attributable im pair m e nt exists. Instead, the work ing group ou tlin ed a

recomm ended general process and recomm ende d t echnical procedures that m a y be used as guidelines if an attribu tio n assessm ent is nece ssary. Due to th e circum stances unique to each attribution assessm ent and the requirem ent that the assessm ent be conducted on a case-by-case basis, recomm ending one specific an alysis for ev er y situation was not possible. A state or tribe should select from the techniques summarized in Section IV. Secti on IV(C) includes five

exam ples of the attribution assessm ent process, each providing a ra nge of techniques to be used

1 W E STAR C o unci l

, RA B A R T and RA BAR T-like Case St udies , J u ne 2001.
2 Th is do cu m e n t sp ecifically relates to RA B A RT an d do es not a d dres s br o a der i ssues rel a t i ng t o l o ng -t er m

vi si bi l i t y strateg i es. FLMs g e n e rally do n o t i n tend t o issu e Certificat io n s citin g sp ecific sou r ces ex cep t fo r situ atio n s inv o l v i ng BART so urces.



### 1

### based on av ailab l e data. The exam pl es also reco mmend m o r e refined analys es that m a y require additional data.

Third, this report includes specific infor m ati on about the current poli cy of FLM agencies regard ing ce rtif ic ation s o f im pairm e nt (Cer tif ication), but m a kes no recom m e ndations regarding the ce rtif ic ation proces s. This repor t m a ke s no recommendations regarding state process following an attribution determ in ation nor exam ines options f o r perform i ng the Best A v ailable Retrofit Technology (BART) analys is or the incorporation of BART requirem e nts into State Im ple m entation Plans (S IPs).

Tribal Implementation

The recommendation s in this docum ent are in tended to help stat es as sess reasonable attribution following Certification by an FLM. S ubject to the requirem e nts of the Clean Air Act, 42 USC 7601(d) and the Tribal Authority Rule, 40 CFR 49.1– 49.11, a tribe m a y accept responsibility for m a king reasonably attributable determ inations in response to a Certification by an FLM when a BART-elig ible sou r ce iden tif ied by the FLM in the Cer tif ication is on the tribe ’ s land. The regional haze rule also ex p licitly recog n izes the authority of trib es to im plem ent the provisions of that rule on tribal lands. T hose provisions create the following fra m ework:

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

2. Federally recognized tribes m a y apply for a nd receive delegation of federal authority to im ple m ent CAA program s (including visibility regulation), or “rea sonably severable” elem ents of such program s. The m e chan ism f

o r this de lega tion is a Tr iba l Im plem entation Plan (T I P ). A reason ably seve rab l e elem ent is one that is n o t integra lly rela ted to p r ogram elements th at a r e not inc l uded in the p l an s u bm ittal, an d is consiste nt with applicable statutory and regulatory requirem e nts.

3. Where a tribe does not seek delegation th rough a TIP, the Environm ental Protection Agency (EPA), as neces sary and app r opriate , will prom ulgate a Federal Implem entation Plan (FIP) w ithin a reaso n able tim e fr am e to protect air quality on tribal lands.
Accordingly, these recommendations also m a y assist a federally recognized tribe that chooses to adopt a TIP to im ple m ent the RA BA RT provisions. In som e cases, a tribe m a y be able to u t iliz e the r ecomm endations in m u ch the sam e way as states. In m a ny other cases, however, the recomm endations m a y be m odified to m eet the unique situati on of the tribe and the nature of its air program

, incl uding its m a nner of defining “rea sonably severable elem ents” and its m e thod of dividing responsibilities between th e tribe and E P A. Because of these differences, the recommendations that follow do not refer to tribes ev ery tim e states are referenced

.



## B. Regulatory Context

The national goal for visibility is set f o rth in the C l ean Air Act (CAA) at 42 USC 7491: “the prevention of any future, and the remedying of any existing, impairm ent of visibility in

m a ndatory Class I Federal areas which im pairm e nt results from m a nm ad e air pollution.” The requirem e nts apply to 156 designated Class I areas.

2

### As stated previously, Congress required that states provide a rem e dy for visibility im pair m e nt that was “reasonably attributable” to one source or a sm all group of sources. (42 USC 7491). Congress directed EPA to ensure that all SIPs contained m easures necessary to

m a ke reasonable progress toward m e eting th e national goal, including requirem ents for identifying m a jor sources of e m issions causing or contributing to visibility im pairm e nt, and requirem e nts for the application of BART on suc h sources. E P A prom ulgated rules pursuant to Congress’s directive to provide guidelines to the st ates on appropriate te chniques and m e thods for im ple m e n ting the SIP requirem e nts. (40 CFR 51.302( c)). (Note: when this report refers to a “source” within the m eaning of this regulati on, the phrase “or a sm all group of sources” is im plied.)

The require m e nt to install Bes t Availab l e Retr of it Technology controls on existing sources is a key elem ent of the visibili ty protection provisions in the CAA de monstrating the need to f o cus on pollution em itte d f r om a specif i c se t of ex isting sour ces. Sources are potentia lly subject to BART controls if they m eet the f o llowing cr ite ria :

1. A m a jor stationary source from 1 of 26 source c a t egor ies id e n tif ied in the CAA and regulations (see Appendix A); 2. Potential to Em it (PTE) 250 tons per year of any air pollutant; and, 3. Not in operation prior to August 7, 1962 and “in existence” on August 7, 1977.

In the 1980 visibility rule, EPA used the term “existing stati onary facility” to define a facility that m e t the above criteria. However, to avoid any confusion about whether that term

encom p assed a larger group of sources, EPA now uses the term “BART-eligible source.” The
term “BART-elig ible so urce” is used throughou t th is repo rt for sim ilar reasons, but the reader should be aware that som e sections of the visibi lity rule still refer to “existing stationary facilities.” For purposes of th e attribution discussion in th is paper, th ese term s are interchangeable.

In 1999, EPA added two new section s to the v i si b ility ru le to address regional haze (4 0 CFR 51.308 and 51.309). Pollutan ts causing regional haze m a y be transpo r ted hundreds of m iles, and therefore, regional haze must be addressed as a broader regional issue. The 1980 vi sibility rule focused on direct visibility im pacts of an indi vidual source or sm all group of sources. The 1999 revisions are commonly referred to as the reg i ona l haze ru le, although the 1 999 rule incorporates the earlier requirem e nts for BART as we ll as the n e w regional haze prov isions.

To rem e dy RAVI, the regulations o u tlin e a proc ess to id entif y and contro l em issions f r om sources that are directly impac ting visibility at specific Clas s I areas (40 CFR 51.302). Three prim ary step s in this pro cess are:

1. The Federal land m a nager cer tif ies impairm e nt; 2. The state identifies ex isting sources that cause or contribut e to the vis i bility im pairm e nt; and

3

### 3. The state perform s a BART analysis to de term ine what controls , if any, are required on any existing source that m eets the BART criter i a and has b een iden tif ie d as contributing to the im pairm e nt.

Attribution Process

The language of 40 CFR 51.302(c)(4)(i) provides the basic principle upon which the state will r e ly dur ing the a t trib ution pro ces s. That sec t i on states tha t the a t tribution m u st indicate each [ B ART-eligible sourc e ] “ which may reasonably be anticipated to cause or contribute to impairment of visibility .” W h ether or not the impairm e nt is “reason ably attributable ” is determ ined by “visual observation or other t echn i que the state deem s appropriate.” (40 CFR 51.301(s)). Because the state is resp onsible for identifying sources, th is report p r ovides

recomm endations for the state to consider wh en it undertakes an attribution determ ination.

Once visib i lity im pairment is identif i ed, RAVI is addressed on a case-by-case basis. Under the 1980 regulation, a state evaluates BART-eligib le sources only after an FLM certifies the existence of visibility im pairm e nt. However, in the context of the current regional haze rule,
states m u st also address BART requi rem e nts for regional haze (RH BART). 3 

### Several options exist for add r essing RH BART. For exam ple, ra ther than req u ire a sou r ce-specific BART

em ission lim it, a state m a y choose to develop a tr ading program

, either regionally or within its own jurisdiction, that achieves greater reasonable progress th an case-by-case RH BART.

If a state develops a trading program , the tim e pe riod to achieve the em issions reductions

m a y be extended. As a r e sult, v i sib i lity cond ition s at a spe c if ic Class I a r e a initia lly m a y rem a in static or even deteriorate dur ing the early im ple m entation period. During this tim e, FLMs have indicated that the RAVI process m a y be utili zed to provide steady a nd continuing improvem e nt in visib i lity. W ithin the context of the regi onal haze rule, this m a y be an e x am ple of a “geographic enhancem ent.” As noted above, the recomm endations in this report apply only to case-by -cas e application s of BART and are not in tended to ap ply to th e broader region al haze rule such as a m a rket-based trading progr am i m plem ented as part of the 1999 rule.

A state m a y find it difficult to d e termine a source/recep tor link for RAVI difficult when there are o t h e r sources lo cated in the area, includ ing inte rnatio nal sourc e s. However, the regional haze ru le provisions do not alter the requirem e nt to undertake the attribution assessm ent.

State determines what contro ls, if any, are required

After the attribution determ ination, the state is required to perfor m a BART analysis to determ ine what types of contro ls, if any, should b e placed on the source(s) found to be contributing to the im pairm e nt. The following factors affect the BART determ ination:

1. Available technology; 2. Costs of compliance; 3. Energy and non air quality envir onmental im pacts of com p liance;

3 The R H B A R T p r o v i s i o n wa s rem a nded t o EPA by t h e U. S. Court of App eals as a resu l t o f th e ru li n g in Am e r ic an Corn Gr owers Associ ation v. EPA , No . 99 013 48 ( D C Cir

. May 2 4 , 2 002 )



### 4

### 4. Re m a ining useful life of the source; and, 5. Degree of improvem e nt that can be anticipated to result from the use of the controls.

As noted above, this report does not provide gu id ance reg a rding state process followin g an attribution determ ination nor does it exam ine op tions f o r im plem enting th e BART requirem ent.

5

### 6

## II. FEDERAL LAND MANAGER CERT IFICATION OF IMPAIRMENT

The Federal land m a nagers m onitor visibili ty through a nationwid e m onitoring network, known as Interagency Monitoring of PROtected Visual Environm ents (IMPROVE). The IMPROVE network has recen tly been expanded and the FL Ms anticipate reliable trend data for the new IMPROVE sites between the years 2006 and 2008. The FLMs plan to evaluate the current visibility conditions in Class I areas as w e ll as trends occurring over tim e to identify areas where visibility is not im proving.

The FLMs generally will use a screening proces s to identify Class I areas that m a y be affected by RAVI. This screen ing process will b e influenced by the approach the s t ate relies upon to address RH BART in its SIP. There are three approaches that m a y be used.

1. Case-by-Case Review of RH BART under 51.308

No distinction exists between em ission re ductions needed to address RH BART and reductions to address R AVI, therefore, the BART process will address both types of visibility im pair m e nt.

2. Trading Program under 51.308

The FLMs antic ipate tha t the f o llowing screen in g criteria m a y be appropriate, but will not

m a ke a final decision until a 308 trading program has been developed. Th e screening criteria associa t ed w ith th is app r oach m a y be sim ilar to th e screening criteria asso ciated with the trad ing
program option under 51.309. Howe ver, the FL Ms have indicated that the screening criteria ultim ately s e lected for 5 1.308 will d e pend on how the trad in g program is structured, the selected

em issions cap, and other aspect s of the trading program

.

Potential Sc reening Pro c ess Criter ia:

(i) Sulfate, nitrate, organic carbon, other fine particulate, etc., levels in the C l ass I area are not decreasing. 4 

### (ii) One or m o re BART-eligible sources of SO 2 

### , NO x 

### , VOC, PM 10 

### , etc., a r e lo cated within 100 m iles of the m a ndato ry federal Class I area. (iii) The BART-elig ible sou r ces iden tif ie d in (ii) are not already well-con t ro lled for pollutants that contribute to visib i lity im pairm e nt.

3. Milestones and Backstop Trading Program under 51.309

The FLMs plan to sign a Mem o randum of U nderstanding (MOU) with the particip ating states to def i ne the sc ree n ing cr ite ria the FLMs will us e to c e r tif y im pairment.

4 The dec r ease of a pol l u t a nt ( o r seco n d ary s p eci es of t h at p o l l u t a nt ) w o ul d be m easure d f r om t h e be gi n n i ng o f t h e market or em is sions tra d ing program , and s u ch a t r adi n g pr og ram wo ul d t a ke a l o n g t i m e ( 1 0 t o 1 5 y ear s) t o reac h th e lev e l o f redu ctio n th at “m eets” BART . T h e decrease would be teste d over th e f i r s t 5 t o 1 0 year s. A ver y qu ick tim e fram e for red u ctio ns wo u l d ne gate t h e n eed fo r R A BA RT criteria.



### 7

### Screening P r ocess criteria: 5



### (i) Sulfate levels in the Clas s I area are n o t decreasin g. (ii) One or m o re BART-eligible sources of SO 2 

### are located within 100 m iles of the

m a ndatory federa l Class I are a

. (iii) The BART-elig ible sou r ces iden tif ie d in (ii) are not alrea dy well-controlled for SO 2 

### (85% or better SO 2 

### c ontrol for co al-fir ed utility boilers).

Goal: For F L Ms to complete the cer tification process between 2006 and 2008. 6



### These criteria were influenced by the design of the 309 trading program including em ission reduction estim ates, shape of the declining em i ssion cap, inclusion of sources that w e re not BART-eligible, and inclusion of new source growth under the cap.

Although geographic enhancem ents do not need to be addressed under the first approach, they m u st be addressed in the two tradi ng program s described above because em ission reductions m a y occur more gradually in the context of a trading program. The FLMs do not anticipate certifying im pairm e nt under these circum stances but do intend to notify the state as part of the S I P developm ent process if concerns arise regarding “hot spot ” im pacts from sources that m a y directly affect specific Clas s I areas.

Note: BART for regional haze has been addressed for SO 2 

### under this option. Regional haze BART for NO x 

### and PM will be addr essed in S I

P revis i ons th at are due in 2008.

In all three cases discussed above, if the FLM determ ines that a certification of visibility im pair m e nt is neces sary, the FLM will send an official Certification to the state. The Certif ica tion will gene rally inc l ude th e f o llowing inf o rm ation:

1. Class I area(s) im pacted; 2. Basis of certification (photographic docu m e ntation, m onitoring, m odeling, etc.); 3. Type of i m pairm e nt certified: plum e impact, or layered or unifor m haze; 4. Pollutant(s) of interest; and, 5. Prelim inary identification of source( s) believed responsible for im pact.

FLM, State, and EPA r o les in RA BART

FLMs are responsible for certifying impairm ent. The Certification dem onstrates the F L M’s determ ination that there is evidence of visibil ity impairm ent from one source or a sm a ll group of

sources.

5 W i t h i n t h e co nt ext of est a bl i s he d re gi o n al m i l e st ones f o r SO 2 a n d a bac k st op t r adi n g p r og ram , t h e FL M s ha ve sai d it is ap propriate to u s e t h e fo l l o w ing screen in g pro cess i n m a ki ng t h ese r ecom m e ndat i o ns as pa rt of t h e C e rt i f i cat i on. Vol unt a r y Em issi ons R e d u ct i o n Pr o g ram fo r M a j o r I n d u st ri al So urces o f S u l f ur Di o x i d e i n Ni ne West er n St at es an d A Back stop Trad ing Pro g ram. An Ann e x to th e Rep o rt of t h e Grand Can y o n Visi b ility Tran spo r t C o mmissio n

. Su

bm it t e d by t h e West er n R e gi o n al Ai r Pa rt ners hi p t o t h e U.S

. E nvi ro nm ent a l Pr ot ect i o n Age n cy , p. 6 1

, Sept em ber 29, 2000.
6 This goal will not i n a n y way restrict the abi lity of the FLMs to ce rtify im pair m e nt at a later date i f it is necessary
to fu lfill th eir statu t o r y o b lig at io n s

. ib i d

.



### 8

### Following the Certification, states have the following regulatory oblig ations: (1) identify f acilities tha t “em it an air pollu tant w h ich m a y be reasonab l y anticipated to cause or contribute to any visibility im pair m e nt” in that Class I area, and (2) for sources subject to BART, the state must identify the BART level of control techno logy. If the source does not have adequate control in plac e, the state m u st establish a BART lim it in the SIP.

EPA has two m a jor resp onsibilities f o r the RA BA RT requirem e nt. First, in the states that do not have a S I P in place to address the RA BART requirem e nts, but where the program is im ple m ented through a FIP, EPA wi ll conduct th e BART ana l ysis and establish any BART

em ission lim its. Second, for the states with SIP s that includ e RA BART regulations, EPA will provide federal enforcement of stat e- estab lished BART em ission lim its.

9

### 10

## III. THE ATTRIBUTION DETERMINATION PROCESS

This section recomm ends a process fo r the s t ate to f o llow in or der to com p lete an a t trib ution determ ination after receipt of a Certification from an FLM under 40 CFR 51.302(c)(1).

The Certif ic ation f o cuse s on the ex is tence of vis i bility im pair m e nt. W h ile the FLM may identify sources or ev en sources areas that contr i bute to the Certif ica tion

, the f o rm al identification of sources is a state responsibility.

The state should m a ke a detailed review of th e data supporting the Cert ification to determ ine which sources or source areas requi re further evaluation. If the data are insufficient to identify specific sou r ces or sou r ce areas, the s t ate m a y req u est th at th e FLM perform m o re detailed analyses to further substantiate the imp airm ent set forth in the Certification.

If

the sta t e d e term ines su f f i cient inf o r

m ation exists to proceed, the state should begin the process by: (1) evaluating which sources are BA RT-eligible, and (2) reviewing the im pairm e nt inform ation provided by the FLM in support of the Certification.

1. Evaluate which sources are BART

- e l i g i b l

e

Congress and EPA established criteria to dete rm ine which sources are subject to BART. The catego r ies o f sources su bject to BART are lis ted in 40 CFR 51.301, the definition of “exis ting stationary facility,” and also are in cluded in Appendix A of this report.

The state must confirm that th e potential source or group of sources is subject to the RA BART proc ess by examining the potential sour ce em issions and the dates of operation.

The criteria for determ ining if a source is BA RT-eligible m a y be com p licated if a source has multiple un its tha t were construc ted at dif f e rent tim e s and a state m a y be unable to d e term ine if a specific source would qualify as BART-eligible. EPA published guidelines in 1980 to aid states in im ple m enting the 1980 rule. 7 

### In addition to the 1980 guidelines for determ ining BARTeligibility, E P A also has proposed gu idelines that include criteria for determ ining if a source is BART-eligible. 8 

### These guidelines are expected to be re-proposed in 2004, prom ulgated in 2005 and codified at 40 CFR Part 51 as A ppendix Y. Th e state sh ould refer to both sets of guidelines to dete rm ine if a source is BART-eligible, a lt hough the proposed guidelines are not binding until final prom ulgation occurs.

When using the applicability criteria in Appendix Y, the st ate should look for infor m ation readily ava i lable f r om existing sta t e d a ta such as p e rm itting his t ory, em ission invento r y , or other sim ilar databases.

7 U.S. Env i ro nmen tal Pro t ectio n Ag en cy, Guid elin es fo r Determin ing Best Ava ilab l e Retro fit Techn o l ogy fo r C o a l

fired Po wer p l a n s and Oth e r Existin g S t a tion a r y Fa cilities, EPA-4 5 0 / 3-8 0 -009 (b ), Office of Ai r Qu ality Plann i ng and Standa rds

, Research Tria ngle Pa rk, N. D., N ovem b er 1 9 8 0 ( 1 98 0 B A R T G u i d el i n es ).
8 66 FR 381 08 Proposed Guidelines for Best Av ailable Retrofit Technol ogy (BART) (Ju l y 20

, 20 01). EPA will repr o pose t h ese gui del i n es as a resul t of t h e re m a nd i n A m erican Cor n Gr owers v. E P

A

.



### 11

### 1. If a database of Potential To Em it (PTE) is not available, state em ission inventories can be a useful screening tool to determ ine whether a source m eets the size criteria (for exam ple, identify all sources with em issions greater than 100 tons/year of visibility im pairing pollutants). Operati ng perm it applications m a y also contain inform ation about the PT E of a source, or individual units within a source. 2. State business records may be useful to determ ine when the f acility was co nstruc ted or when it comm enced operation. Newspaper arti cle searches or a detailed historical review of each source m a y also provide useful infor m ation. 3. The state should require the source to provide inform ati on regarding the construction dates of individual em ission units. 4. Institutional m e mory within the air ag ency can b e invalu able if records of construction dates of m a jor em ission units are not available, although m e mories will not withstand legal challenges like hard docum entary data. 5. New Source Review per m itting reco rds m a y be usef ul to ide n tif y new units th at wer e constructed after 1977, determ ine the P TE of the source, or determ ine if reconstruction has occurred. (Note: the dr aft guidelines in Appendix Y state that modifications at a source do not affect a pplicability unless the change qualifies as reconstruction of the source).

If the source or group of sources identified in the Certification is not BART-eligible, the state should inform the FLM of its finding. The stat e should look in the vicini ty of all the sources suspected of causing or contributing to the im pa irm e nt identified in th e Certification. If no BART-eligible sourc e s exist, an at tribution assessm ent is unnecessary.

2. Review Support Information in the FLM Certification

Initially, the state should acquire all the supporting inform ation the FLM used in the Certif ica tion and indepen d ently ev alu a te th e da ta. This initia l r e view will h e lp the sta t e determ ine if the inform ation is sufficient to support a reasonable attr ibution determ ination.

The state should consider the t ype of im pair m e nt in the Cer tif ication : (a ) plum e im pact visibility im pairm e nt, (b ) unif o rm haze vis i bil ity im pairm e nt, or (c) laye re d haze vis i bility im pairm e nt:

(a) Plum e i m pa ct is the im pairm e nt addre ssed by the original visibility protection
program under which the state m u st m a ke a reasonable attribution determ inatio n before pro ceeding to the BART analysis (40 CFR 51.301- 51.307). (b) In som e instances, unifo rm haze m a y be thought to be source-specific haze from a BART-elig ible so urce. If a s t ate can su ccessfully demonstrate th ere is a

source em itting any air pollutant that m a y reasonably be anticipated to cause or contribute to any im pairm e nt of visibilit y, the state should c onsider that portion of the uniform haze to be im pact from the identified source(s) and, therefore, consider the source to be subject to B A RT. (c) The v i sib ility im pairm e nt m a y al so be define d as laye red haze, a cond ition that results when aerosols are “trapp ed” u nder stagn a n t air m a ss conditions.

12

### Once the FLM has issued a Certification, the responsibility f o r the attribution assessm e nt shifts to the state. If a state doe s attribute im pairm e nt to a source, the state m u st be able to defend its finding that one or m o re BART-eligible so urces did cause or c ontribute to visibility im pair m e nt in the Class I area. However, the Ni nth Circuit Court of Ap peals es tab l ished a low thresho l d for unaccep tab l e vis i bility impairm ent. 9



### 3. Evaluate Existing Data not include d in the Cer tif ication

When analyzing supporting data, the state should determ ine if additional infor m ation exists that was no t available to the FLM. Exam ples in clude special projec t cam era stud ies o r am bient monitoring data collected by the state or local air pollution control agency, th e potential or actual PSD perm it applic ant, 10 

### or the university. In certain situ ations, another ag ency m a y have previously collected inform ation that could be used in an attribution determ ination. 11 

### These data should be reviewed to determ ine whet her they support the FLM Certification.

To conclude this portion of the attrib ution pro ces s, the state m a y wish to prepare a report th at summarizes its initial evaluation of the Certification. The purpose of the report is to carefully docum ent the state’s findings and c o nc l u s i ons a b out i t s de c i s i ons

. The report would address two questions:

First, the report would assess whether any BA RT-elig ible sou r ce(s) exis t th at poten tia lly contributed to visibility impairm ent as described in the Certifi cation. The report would contain a prelim inary determ ination of whether the source s are BART-eligible and, if possible, analyze each source’s relativ e co ntribu tion to the im pa irment (bas ed o n available s ource/recep tor inform ation).

Second, the report would assess the im pair m e nt data. This assessm ent would include the state’s ev alu a tion of the supporting d a ta in the Ce rtification and an anal ys is of any addition a l data used in the attribution assessm ent. The data gaps found in this review would be identified along with any recomm e ndations for strategies to obtain the missing inform ation. The state m a y use these recomm endations to determine the n e xt steps in the at tribution process.

If the state believes the Certification is s upported by sufficient data, proceeds with an attribution assessm ent and m a kes a determ ination that the data does or does not indicate a source subjec t to B A RT, the attribution pro cess is com p lete. Howev e r, if the s t ate dete rm ines the data is insufficient to com p lete an attribution assessm en t, the evaluation process ends, and the state m a y proceed to the next s t ep —identification of data g a ps and the studies n ecessary to ob tain this inform ation.

9 See Cen t ra l Ariz. Wa ter Conserva tion Dist v. EPA

, 99 0 F. 2d 1 5 3 1 ( 9 t h C i r. 19 9 3 ); See a l so di scussi on i n RA BAR T and RA BA RT-like Case St udies

. 10 For ex am p l e, a PSD p e rm it a p p lican t m a y be req u i red t o ob tain p r e-app l i catio n am b i en t air q u a lity in fo rm atio n , and t h at i n f o r

m at i on m a y not have bee n av ai l a bl e t o or k n o w n t o t h e FL M

. 11 I n Washi ngt o n st at e, t h e pl u m e of a de fu nc t cop p e r sm el t e r has been t r ac ed by i t s arse ni c de po si t i on. I f t h i s were

an activ e facility, th is groun d tracin g of the plu m e co u l d b e u s ed to supp ort a so urce/recepto r con n ection in an attrib u tion d e term in atio n

.



### 13

### 4. Identify data gaps and necessary studies to fill the gaps

As part of the data review, th e state should note gaps or incons istencies in the available data. Exam ples of data gaps and inconsistencies m a y include:

1. Missing photos in a sequence of photos, 2. Poor resolution of the plum e or its source in the photos, 3. Back trajectory analyses done with a very large grid resolutio n or poor techniques, 4. IMPROVE monitor data m i ssing at critical periods, 5. Lack of association betw een the sou r ce’s em issions and m oni tored data at the receptor, 6. Special studies perform e d dur ing a tim e when a source th at potentially contributed to the im pairment was not operating, 7. Contem pora n eous studies with contradi ctory results that cannot be explained, 8. Am bient studies that use naturally occurri ng tracers and, when th e suspected source(s) are tested, the tracers do not exist or exist at levels fa r below (or above) the level indicated by the am bient study results, 9. Tracer studies where th e tracer was n o t found at the anticipated recep tors, 10. No explicit exploration of whether wildfire or other natu ral events signif i cantly caused or contributed to one or more of the im pair m e nt episodes, 11. Other differences or inconsis tencies in the available data.

Once any data gaps have been identified, the state should decide which studies are necessary to obta i n the m i ssing inf o rm ation suf f i cient to co mplete an a t tribu tion a s s e ssm ent. The sta t e should design potential studies a nd determ ine the resource needs of those studies. The am ount of work necess a ry will dep e nd on the availab i lity o f the information and ho w critical th e inf o rm ation is to th e attr ibution ass e s s m e nt. S ection IV provides technica l criteria and exam ples of the technical pro cess the state m a y c onsider at this point in the process.

5. Consultatio n Process

The W E STAR review of previous RAVI a ssessm e nts de m o nstrated the im portance of including all stakeholders in the design of a ny data collection plans or m odeling protocols. Com p eting studies can be very inefficient, expensive, and ti m e -consum i ng, and ultim ately m a y not help the state m a ke a final decision.

If stakeholders are involved in the design of any data collection efforts or m odeling protocols, disagreem ents m a y be resolved be fore the state or s ource con tin ues with any additional studies. The state should consider invo lving th e f o llowing stakeholders in the consultation process:

1. Affected so urces 2. Neighboring states and tribes 3. Environm ental Protection Agency 4. Federal land m a nagers 5. Local environm ental groups 6. Local perm itting agencies

14

### 7. Local governm e nt representatives

6. Completion and Review of Addition a l Visib ility Studies

When the addition a l visibility stud ies, if any, are com p lete, the state sho u ld evalu a te the resulting data. The techn i cal st af f m a y wish to f i naliz e the re port and m a ke recomm endations based on the scien tif ic aspects of the data.

7. Final Determination of Reasonably Attributab le Visibility I m

pairment

The state m a y reach any one of the following con c lusions :

1. The im pairm e nt certif ie d by the FLM is re asona bly attribu t a b le to the id entified BARTelig ible sou r ce(s) f o r sp e c if ic polluta nts; 2. The im pairm e nt certified by the FLM is re asonably attributable to the source(s) identified by the FLM and additional sour ces no t identified by the FLM for specific pollutants; 3. There is inadequate data to support a dete rm ination that the impairm ent is due to the source(s) identified by the FLM; 4. The im pairm e nt is reas onably attrib utable to oth e r adjacent BART-eligible sources for specific po llutants ; or 5. The im pairm e nt certified by the FLM is not rea s onably a ttr ibutable to a BART-eligible

source.

15

### 16

## IV. GENERAL PRINCIPLES AND CRI TERIA

This section provides general prin cip l es and tech nical criteria fo r the sta t e to consid er af ter receipt of an FLM Certification. After receipt of such a Certifi cation, the state m u st determ ine whether BART-eligib le sources “ e mit any a i r po llutan t which m a y reason ably be an tic ipated to cause or contribute to any visibi lity impairm ent in any” Class I area. W h ile these p r inciples and technical criteria should generally be useful and applicable, each state m u s t decide what is required to support its individual determ ination.

Part A contains general princi ples to guide the developm ent of a conceptu al fram ewor k for the attribution assessm ent process. Part B contai ns evaluatio n criteria to guide the decisions regarding a technical fram e w ork for the attribution assessm ent proces s.

Conceptually, the statutory fram ework for an attribution determ ination (“m a y reasonably be anticipated to cause or contribu te to visibility im pairm e nt”) should be the general principle guiding the attribution process. EP A m a intains, a nd the Ninth Circui t agreed, that an affir m ative attribution decision is possible ev en with consid e r able un cer tainty and a low triggering threshold. However, each state sho u ld decid e individually wh at is requ ired to supp ort its determ ination.

A. General Principles o f

th e Attribu tio n P r o c e s s

Attribu tion process c r ite r ia add r ess f actors lik ely to influence the perform a nce of the state attribution assessm ent. These crite ria provide param e ters to define and im plem ent the a ttr ibution

assessm ent process given resource constraint s, legal considerations, adm i nistrative decisionm aking requirem ents, and other relevant factors. The general principles include the following:

1. Whenever possible, an attribution assessm ent should be a collaborative process that relies on existing data with a m i ni m u m of additional analysis ( see se ction III). If supplem ental data are needed, field studies should be designed in a collaborative process between affected states and trib es, identified sources, Federal land m a nagers, EPA, and the general public. Past experi en ce has shown that com p eting technical studies often result in an unnecessarily expensive and unduly com p licated process.

2. Attribution assessm ents should be technically and legally defensible.

3. Attribution assessm ents should be accom p lished at a reasonable cost and within a reasonab l e tim e fram e.

4. Attribution assessm ents shoul d be no m o re com p l e x than necessary, recognizing that the circum stances surrou nding a Certification m a y vary greatly. State or tribal agency staff should be capable of perfor m i ng the attribution assessm ent and m a king the final determ ination, although contractors m a y be used for certain types of m o deling or monitoring.

5. Reasonably attributable visibility im pairm e nt can only be identifie d if a source/receptor

17

### links a potentially BART-eligi ble source or sm all group of sources to a Class I area.

B. Technical C r iter i a

The technical criteria ad dress th e appropriateness of availabl e analy tical techniques from a scien tif ic pe rspective. T h e rule d e f i nes visib i l ity im pair m e nt to m ean “any hum a nly perceptible change in visibility (light ex tinction, visual range, c ontrast, coloration) from that which would have existed under natural conditions.”

The technic a l cr ite ria in clude th e f o llowing:

1. The BART s ource m u st em it an air pollutant that m a y reasonably be anticipated to cause or contribute to any of the im pairm e nt. The visibi lity-impairing pollutants of

concern m u st be identified.

2. The attribution assessm ent should address th e unique visibility im pair m e nt in the FLM Certif ica tion f

o r the Clas s I are a

. Som e factors to consider include:

a. Duration: source’s length of effect on visibility per episode; 12



### b. Frequency: how often episodes of impairm ent occur;

c. Geographic extent: how much of the Cl ass I area is affected b y the im pairm e nt;

d. Magnitude: how m u ch visibility im pairm e nt is due to the source’s em issions; and

e. Tim e of occurrence: in cl uding tim e of day and tim e of year.

These factors need to be considered togeth er, b e cause they affect each oth e r. An infrequent o ccurrence of a larg e m a gnitude ep iso d e m a y m e et the criteria. A frequent occurrence of a sm all magnitude episode m a y also m eet the criteria. The FLM m a y provide inform ation about thes e criteria in the Ce rtification, and the state should review this inf o rm ation as a sta r ting poin t f o r its assessment. The state m a y consider other factors and data, as appropriate.

3. The attribution assessm ent should identify th e distance from the source to the Class I area. This distance will affect the cho i ce of tools appropriate fo r characterizing the specific source’s im pact on visibility im pair m e nt.

4. To the extent possible, the attribution a ssessm ent should be quantitative. Under certain circum stances, qualitative inform ation, such as photographs or tim e-lapse video of distinct plum es or source-specif ic haze events, may be adequate.

5. The state should use as m a ny approaches or indicators of im pair m e nt as practicab le

12 B a sed o n pre v i ous cases, m o st im pai r m e nt epi s o d es a r e relativ ely sh ort—lastin g on e t o sev e ral ho urs—wh ich m a y affect m oni t o ri ng an d ot he r as sessm ent techniques

.



### 18

### rather than relying on a single m e thod. The assessm e nt m a y r e ly on air monitoring and modeling techniques and other supporting scie ntific data. Consistency between source and observational techniques strengthens the analysis. 13



### 6. The state should consider the leve l of uncertainty in the a ssess m e nt.

7. EPA guideline m odels should be used when ever practicable. When other models are used, additional technical discussi ons with EPA may be necessary.

C. Examples o f

the Attr ibu tion Process

The state should consult this se ction after evaluation of the FL M Certification. At this point, the state will already have decided w h at gaps n e e d to be f illed to com p lete the attr ibution

assessm ent.

The recommendation s in this report recognize th at each attribution de term ination will be unique. Because an attribution determ ination is a fact-specific and individual determ ination, it is not possible to recomm e nded a sing le techn i cal approach for a stat e to follow. A combination of monitoring and m odeling techniques is usually appropriate, but inst ead of attem p ting to cover all possible combinations of technique s, this report provides five se lected s c enarios. Th e general principles and technical criteria iden tified in sections A and B are in corporated in to these scenarios. T h e goal is to provide the state with references for use when it is creating its own individualized tech n i cal procedure.

In addition to the scenarios, this report provides deta iled tables and narrative descriptions of techniques that m a y be consider ed and/or substitute d for the techniques in the scenarios (see Section V).

Scenario 1 : Limited data/one source

Data input: Sm all am ount of existing data (i.e ., one IMPROVE site with data for 2-3 years) Evidence of “local” im pact. Lim ited m e teorological data.

Where it is likely that on e m a jor source cont ributes to im pairm e nt, a combination of the following techniques is suggested:

1. Exam ine IMPROVE data, in cluding quality assurance 2. Look at extinction budget to identi fy visibility-impairing pollutants 3. Perform som e analysis of when the episodes are occurring 4. Perform a si mple back trajectory an alysis using a m e thod such as HYSPLIT 5. Look at relationships be tween particulate species 6. Exam ine source em issio n s data for co rrelations with am bient m onitoring 7. Perform dis p ersion m odel based on data a nd capabilities such as VISCREEN or CALPUFF Lite

13 W E STAR C o unci l

, RA B A R T and RA BAR T-like Case St udies , J u ne 2001.



### 19

### 8. Exam ine other data such as source owne r data, deposition data, or photographic evidence

The results of this initial analysis m a y not alwa ys be conclusive. This level of review m a y be adequate if a source/receptor relationship can be identified. H o wever, if the results are inconclusive, m o re data and/or m o re refined an alyses m a y be necessary and m a y help the state reach an attribution d e term ination. The state sho u ld consid er how the availab l e data and choice of techniques m i ght affe ct its abil ity to asses s the effectivenes s of the controls in rem e dying the im pair m e nt.

It m a y be efficient to loo k ahead to the da ta and analytical need s of a potential BART analys is. For exam ple, the state m a y wish to use a m o re refined m odel that would be useful for both attribution and rem e dy assessm ent.

Assum i ng there is a two-year tim e period 14 

### to collect data and analyze additional information, the followin g techniqu es also can b e considered:

1. Better source characterization, including m easurem ent of e m i ssions of trace elem ents (source profiles) for use in CMB m o deling 2. Met m onitoring or m odeling 3. Ca m e ra site, possibly with tim e-lapse video 4. Additional aerosol m onitori ng, episodic or saturation 5. In plum e trajectory by aircraft, if available 6. Fine tim e-resolved optical m onitoring, such as ne phelom e ter, transm issometer, aethelom e ter com b ined with pollutant m onitoring (e.g., SO 2 

### , NOx, real tim e PM) for monitoring of episodes 7. More refined chem ical visibility m o del, such as C A LPUFF 8. Repeat initial techniques with new data

The technic a l cr ite ria ar e lis ted be lo w, f o llowed by t echniques that m a y be used to obtain results about the criteria.

1. The im pairm e nt m u st be related to em i ssions fromspecific sources. The visibilityim pairing pollutants of concern should be identified.

Techniques : Back trajectory, species relations hips, relationship between source

em issions and am bient monitoring, dispersi on model refined by cam era, aerosol, in plum e, optical m onitoring, a nd refined dispersion models.

2. The attribution assessm ent m u st address the unique visibility im pair m e nt certified by

14 The 1999 re gional haze rule revise d the re quirem ents for general plan re quirem ents for visibility protection. As a result, plan re visions a r e requi r ed once e v ery five y ear s, rath er tha n t h e L o n g Te rm Strategy revie w re q u ir em ent of
every t h ree y e a r s. If an FLM c e rt i f i e s R A VI at l east 6 m ont hs pri o r t o a pl an revi si o n , se ct i on 51 .3 0 2 re qui res t h at the State Pla n revision a d dress suc h Ce rtifications . Gi ve n thi s 5-year cycle, we have pres um ed f o r t h is re po rt that a n attrib u tion an alysis sh ou l d take abo u t t

w o years to co m p lete in o r d e r to all o w ti m e fo r th e BART eng i n e ering analysis, if nee d ed.



### 20

### the FLM for the Class I area. Som e factors to con s ider includ e:

a. Duration : so urce’s leng th of effect per episode Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

b. Frequency: how often the im pairm e nt occurs Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

c. Geographic extent: how much of the Class I a r ea is im paired Techniques : Monitoring, dispersion model, addi tional data on deposition and other studies

d. Magnitude: how m u ch impair m e nt is due to the source Techniques : Dispersion model, receptor m odel

e. Tim e of occurrence Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

3. Uncertainty of results : Each analy t ical m e thod will have its own level o f uncertain ty

. These individual uncertainties should be kept in m i nd as outputs ar e compared within the over a ll a ssessm ent. If the results of different technique s are the sam e or sim ilar (within the u n certainties of the techniques), th en the overall level of uncertainty is likely to decrease.

Scenario 2: Moderate d a ta/multip l e sources

Data input: Moderate amount of existing data (i .e., one IMP R OVE site with data for six or
more years ) Evidence of an increasin g trend in su lfate Meteorological data likely from several stations

Assum i ng the Certification identi fies m u ltiple B A RT sources of different types within a 100-

m ile radius, a com b ination of the following techniques is suggested:

1. Exam ine IMPROVE data, in cluding quality assurance 2. Look at extinction budget to identi fy visibility-impairing pollutants 3. Perform som e analysis of when the episodes are occurring 4. Perform multiple back trajectory anal yses us ing a m e thod such as HYSPLIT 5. Look at relationships be tween particulate species 6. Exam ine source em issio n s data for co rrelations with am bient m onitoring 7. Perform dis p ersion m odel based on data a nd capabilities such as CALMET/CALPUFF 8. Exam ine other data such as source owne r data, deposition data, or photographic evidence 9. W i nd fields/Synoptic analyses 10. Com p arison of different episodes 11. UNMIX, PMF and/or CMB

21

### 12. Analysis of any regional m odeli ng already conducted, such as CMAQ 13. Long term visual m onitoring, such as cam era data or transm issom e ter data, com p ared to

m e t data to identify quadrants of concern

The results of this initial analysis m a y not be conclusive. This level of review m a y be adequate if a source/receptor re lationship can be identified.

However, if the resu lts ar e in conclusive, m o re data and/or m o re refined analyses m a y be necessary and m a y help the state reach an attribution determ ina tion. The state should consider how the available d a ta m i ght affect th e ability to a ssess th e ef f ectiv eness o f the contro ls in

rem e dying the im pairm e nt. It m a y be efficient to l ook ahead to the data and analytical needs of a potential B A RT analysis. For example, the stat e m a y wish to use a m o re refined m o del that would be useful for both attribution and rem e dy assessm ent.

Assum i ng there is a two-year tim e period to coll ect data and analyze additional information, the following techniques also can be considered:

1. Em issions inventory 2. Analysis of a nested dom a in within the reg i onal model 3. Source profiles (natural tracers) 4. Additional source m easurem en ts, such as stack testing 5. Met m onitoring or m odeling 6. Ca m e ra 7. Additional aerosol m onitori ng, episodic or saturation 8. Monitor i ng to m easure a ddition a l pa r a m e ters, suc h as precu rs ors, amm onia and oxidants 9. In plum e trajectory by aircraft, if ava ilab l e, to ch aracterize p l um e chem istry 10. Fine tim e-resolved optical m onitoring, such as nephelom e ter, transm issometer, aethelom e ter com b ined with pollutant m onitoring (e.g., SO 2 

### , NOx, real tim e PM) for monitoring episodes. 11. Repeat initial techniques with new data

The technic a l cr ite ria ar e lis ted be lo w, f o llowed by t echniques that m a y be used to obtain results about the criteria.

1. The im pairm e nt m u st be related to em i ssions fromspecific sources. The visibilityim pairing pollutants of concern should be identified.

Techniques : Back trajectory, species relations hips, relationship between source

em issions and am bient monitoring, dispersi on model refined by cam era, aerosol, in plum e, optical m onitoring, a nd refined dispersion models.

2. The attribution assessm ent m u st address th e unique visibility im pair m e nt certified by the FLM for the Class I area. Som e factors to con s ider includ e:

a. Duration : each source’s length of effe ct per episode

22

### Technique s: Monitoring, dispersion mode l, back trajectory, cam e ra

b. Frequency: how often the im pairm e nt occurs by source Techniques : Monitoring, dispersion model, back trajectory, receptor m o del, cam e ra

c. Geographic extent: how much of the Class I a r ea is im paired Techniques : Monitoring, dispersion model, a dditional data on deposition and other studies

d. Magnitude: how m u ch impairm e nt is due to each individual source Techniques : Dispersion model, receptor m odel

e. Tim e of occurrence Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

Scenario 3 : No IMPROVE data, Certifica t ion by modelin g evidence

Data input: Detailed m o deling of a source a nd specific visibility im pairment using a CALPUFF r un, or detailed (neste d) run of regional m odel. Detailed emissions data and m e teorologi cal data were input to the m odel. No IMPROVE data available for this specific Class I area (m onitoring may be at a “representative site”) Som e optical data, photographic data, and lim ited aerosol data from other networks

Assum i ng the Certification points to a specific so urce, a com b ination of the following techniqu es is suggested:

1. Exam ine IMPROVE data for any nearby Class I areas (especially those included in the modeling dom a in) to better understand the re gional conditions and com p a r e with m odel outputs of the unique effect 2. Review the model’s outputs on “high im pact” days and com p are with actual

m e teorological data of the area (to confirm transport, inversi ons, or other aspects of the model which m a y create the unique impact) 3. Review source em issions data used in the m odel 4. Review other m onitoring data (optical m easurem e n ts, deposition data, ozone data, etc.) to collaborate m odel predictions 5. Exam ine any photographic evidence

The results of this initial analysis m a y not alwa ys be conclusive. This level of review m a y be adequate if a source/receptor relationship can be identified. B ecause no visibi lity -spec i f i c par tic le monitoring is available in this case, the key to attribution is to dete rm ine that the source

em issions are indeed reaching the Class I area on days when impairm ent exists. If the r e sults are inconclusive, m o re data and/or m o re refined an alyses m a y be necessary and m a y help the state reach an attribution d e term ination. The state sho u ld consid er if the avai lable data and modeling inf o rm ation supplied with this Cer tif ication could be used to d e term ine the ef f ectivenes s of the

23

### controls in rem e dying the im pairm e nt. It m a y be e fficient to look ahead to the data and analytical needs of a potential BART analysis if additio n a l or dif f e rent modeling will be ne cessa ry.

Additiona l d a ta co llec tio n and analys es that m i ght be considered:

1. Better source profiles or newer em issions inform ation 2. Met m onitoring or m odeling 3. Ca m e ra 4. New aerosol m onitoring (e pisod i c or satura tion ) 5. In plum e trajectory by aircraft, if available 6. Repeat in itial analy tical techniques w ith new data

The technic a l cr ite ria ar e lis ted be lo w, f o llowed by t echniques that m a y be used to obtain results about the criteria.

1. The im pairm e nt m u st be related to em i ssions fromspecific sources. The visibilityim pairing pollutants of concern should be identified.

Techniques : Confir m model inputs, co m p are with any new particle m onitoring at Class I area. Exam ine perform a nce of the mode l, and perform uncertainty analyses.

2. The attribution assessm ent m u st address the un ique visibility im pair m e nt certified by the FLM for the Class I area. Som e factors to consider include:

a. Duration : so urce’s leng th of effect per episode Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

b. Frequency: how often the im pairm e nt occurs Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

c. Geographic extent: how much of the Class I a r ea is im paired Techniques : New m onitoring and exam inati on of dispersion model outputs, additional data on deposition and other studies

d. Magnitude: how m u ch impair m e nt is due to the source Techniques : Dispersion model

e. Tim e of occurrence Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

Scenario 4 : Direct Photographic Evidence

Data input: The FLM certif ied im pairm e nt in a wilderness area based on photographic evidence. Photographs taken over a period of two years show ed a distinct haze in a valley located in the wildernes s area when th e wind is fro m the east. A series of photographs during two epis odes showed a distinct plum e that

24

### originates at an existing stationary source constructe d in 1965 and located ten

m iles east of the wilderness area. The photographic series showed that the plum e traveled into the wildernes s area. Aerial photos during one episode also s how a distinct plum e that travels into the wilderness area. Th e wildernes s ar ea does not have an IMP R OVE site. A Class I area located 50 m iles to the nor th has an IMPROVE site that was
repres entative for the area. This m o nitoring site does not show decreased visibility on the days wh en haze was photographed in the wild erness valley.

Assum i ng the Certification identifies one BART source, the following steps are suggested:

1. Review the photographic evidence and dete rm ine whether the photogr aphs show a clear connection between the source and the h aze docum ented in the wildern e s s area.

In this example, the pho tographic eviden ce showed a clear co nnection b e tween the source and the haze in th e wildern e ss ar ea. Qualitative information, su ch as photograph i c evidence that establish e s a source/recepto r link, is allowed u nder EPA regulations that define reas onable attribution as determ in ed by “visual observation or other technique the State deem s appropriate.” (40 CFR 51.301(s)).

The results of this initial analysis m a y not always be conclusive. If the photographic evidence is not com p elling, the state m a y reach a different co nclusion. Th e state m a y determ ine that the im pairm e nt, as docum ented by the FLM, was not reasonably attributable to the source identified in the Certification. The FL M would th en need to gather additional inform ation to support a Certification. Alte rnatively, if the state determ ines that the source m a y be causing the haze but the qualitative evidence is n o t quite suffi cient to determ ine attrib ution, th e state cou l d initiate a da ta collection ef f o rt to pro v ide better infor m ation regarding vi sibility im pairm e nt at the Class I area. Such techniques m a y include:

1. Better source characterization, including m easurem ent of e m i ssions of trace elem ents (source profiles) for use in CMB m o deling 2. Met m onitoring or m odeling 3. Additional aerosol m onitori ng (episodic or saturation) 4. In plum e trajectory by aircraft, if available 5. Fine tim e-resolved optical m onitoring, su ch as nephelom e ter, transm issometer, or aethelom e ter com b ined with pollutant m onitoring (e.g., SO 2 

### , NOx, real tim e PM) for monitoring of episodes. 6. More refined chem ical visibility m o del, such as C A LPUFF

The technic a l cr ite ria ar e lis ted be lo w, f o llowed by t echniques that m a y be used to obtain results about the criteria.

1. The im pairm e nt m u st be related to em i ssions fromspecific sources. The visibilityim pairing pollutants of concern should be identified. Techniques : Back trajectory, species relations hips, relationship between source

em issions and am bient monitoring, dispersi on model refined by cam era, aerosol, in

25

### plum e, optical m onitoring, a nd refined dispersion models.

2. The attribution assessm ent m u st address the unique visibility im pair m e nt certified by the FLM for the Class I area. Som e factors to con s ider includ e:

a. Duration : so urce’s leng th of effect per episode Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

b. Frequency: how often the im pairm e nt occurs Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

c. Geographic extent: how much of the Class I a r ea is im paired Techniques : Monitoring, dispersion model, addi tional data on deposition and other studies

d. Magnitude: how m u ch impair m e nt is due to the source Techniques : Dispersion model, receptor m odel

e. Tim e of occurrence Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

3. Uncertainty of results : Each analy t ical m e thod will have its own level o f uncertain ty

. These individual uncertainties should be kept in m i nd as outputs ar e compared within the over a ll a ssessm ent. If the results of different technique s are the sam e or sim ilar (within the u n certainties of the techniques), th en the overall level of uncertainty is likely to decrease.

The final step in the attribution process scen ario would be to veri fy that the source w a s operating on the days when the haze was observed in the area. The state should also determ ine if the source was experiencing unusual upset cond itions during the tim es identified. In this

exam ple, the source was determ ined to have been operating norm ally. The state would then issue a dete rm ination tha t the visibility im pairm e nt at the Class I area was reaso n ably attribu t able to the existing stationary facility.

Scenario 5 : Data Rich

Data input: A large special visib ility study recently was conducted. Four m onths of data spanning two seasons was collected including:

1. At one “rec e p tor” s ite in a Class I a r e a ther e were m u ltiple m e teoro l ogica l, optica l , and particulate sam p lers including extensive m eas urem ents of par ticle com positions, size distributions, scattering, abso rption, light extinction, ions, oxidants, relative hum idity,
tem p erature, vertical wind profiles, S O 2 

### , photographs, and concentr ations of four unique tracers released from four di fferent sources of interest. Th ere were co-loc ated sam p lers

m easuring several param e ters in more than on e way. There are at least som e one, six, and twelve-hour partic le m easurem e n ts in addition to twenty-four hour sam p les.

26

### 2. This receptor site has been an IMPROVE s ite f o r severa l yea r s a nd these data are also available. 3. At thir ty-f iv e other s i tes in the region, called “satellit e” sites there was an IMPROVE Module-A sam p ler taking daily twenty-four hour sam p les which were analyzed for fine

m a ss, S, soil elem ents, trace m e tals, and elem ental H from which organ i cs can be estim ated. The unique tracers were also m easured at m a ny of these s ites. 4. Aircraft sampling of plum es from source(s) of interest was conducted. 5. An extensiv e current em i ssions inventory was created. 6. W i nd profilers were dep l oyed at two to th ree sites in addition to the recep tor site. 7. Measurem ents of the ch em ical compositi on of resuspended local dust, smoke from burning local fuels, and em issions from local point and area sources of interest were collected in order to creat e “source profiles” to be us ed in receptor m odeling.

Assum i ng the cer tif ica tio n identif i es a BART source with in 1 00 m iles of the Class I a r ea from which a unique tracer was released, a co m b ination of the following techniques is suggested:

1. Exam ine fine particle data, including quali ty assu rance. Use the collo cated data to assess accuracy and precision. The one, six, a nd twelve-hour data should average up to

m a tch the twenty-four hour data and if reasonable, be us ed to exam ine the diurnal cycles in the fine particle concentrations. 2. Look at the extinction b udget to identify vi sib i lity-im pairing pollutants. Because size distributions were m easured, the extinction budget can be estim a ted from Mie scattering calculations as well as by using sim p le techniques that assume bulk scattering and absorption efficiencies. Check to see if m easured scattering p l us absorption add up to the m easured and reconstructed extinction. 3. Com p are the special study data to histor ical IMP R OVE and a r chived m e teorological data to determ ine the representativeness of the study period. 4. Perform som e analysis of when the episode s are occurring. EOF analysis can be helpful
to summ arize the m a ssive data s e t. U s e the pho to graphs to create a tim e-lapse visualization of the scen e at the recep tor site. 5. Perform bac k trajectory analyses usi ng HYSPLI T , CAPITA Monte Carlo or ATAD. Exam ine whether the trajector ies change substantially when the study’s w i nd-profiler data a r e inc l uded. Deter m ine whether tr aje c tor i e s are cons istent with trac er concentrations. 6. Look at relationships between particulate species (f actor analysis) to s ee if they identify source types. 7. Look at the spatial and tem poral patterns of trace elem ents and the m a jor constituents of the fine m a ss. This m a y suggest dominan t source areas and transport patterns for different source types. Use EOF analysis to de te r m ine the patterns th at explain m o st of the covarian ce in th e data. Check to see how well thes e are reconciled with the back trajectory modeling and the determ inistic m ode ling. Check to see if the sam e dom i nant sources were indicated. 8. Exam ine source em issio n s data for co rrelations with am bient m onitoring. 9. Perform dis p ersion m odel such as C A LMET/CALPUFF.

27

### 10. Analyze wind fields, synoptic conditions, a nd satellite photos. Check to see if they w e re consistent w ith m o re sophisticated meteorological m odeling. Look for unusual conditions such as wild fires, hurricanes, stagnation episodes, etc. Look to see if modeled and observed cloud patterns were com p arable. 11. Com p are the m e teorological and chem ical characteristics of different episodes 12. UNMIX, PMF and CMB can help determ ine m a jor source types and when they were im portant.

If, at this point, sim ilar s ource/recep tor relati onsh i ps have been identified using several different techniques, this level of rev i ew is adequ a te. If the resu lts are inconclusiv e , and there are differing points of view about the frequency, dura tion, or significance of the attribution to the BART-eligible source, more analyses m a y be necessary. Often in a large study, m easurem ents

are m a de, but not imm e diately analyzed in the lab due to cost. If this is the case, m o re sam p les could be analyzed. It is unlikely that any additional field m onitoring would be required.

The technic a l cr ite ria ar e lis ted be lo w, f o llowed by techniques that m a y be used to obtain results abou t the criteria.

1. The im pairm e nt m u st be related to em i ssions fromspecific sources. The visibilityim pairing pollutants of concern should be identified.

Techniques : Reconstructed particle m a ss and light extinction including exam ination of the reconstructions in different size ranges a nd at different sites in the region, analysis of responses of light scattering to rela tive hum idity, back trajectory analyses,

exam ination of inter-species relationships com p ared to m easured source profiles, dispersion modeling with sophisticated m ode ls such as REMSAD and CMAQ, analysis of wind fields and dispersion by co mparis on to m easured tracer con centrations,

com puter anim ation of spatial patterns of species of interes t , use of receptor m odels such as TMBR, DMB, a nd TAGIT that ut ilize unique tracer inform ation, or other
recep tor m o dels such as CMB, UNMIX, and PMF that do not require tracer inform ation, but can use it. W h en so m a ny different m odels can be used, model reconciliation is usually a pa rt of a data-rich scenario.

2. The attribution assessm ent m u st address th e unique visibility im pair m e nt certified by the FLM for the Class I area. Som e factors to con s ider includ e:

a. Duration : each source’s length of effe ct per episode Technique s: Monitoring, dispersion mode l, back trajectory, cam e ra

b. Frequency: how often the im pairm e nt occurs by source Techniques : Monitoring, dispersion model, back trajectory, receptor m o del, cam e ra

c. Geographic extent: how much of the Class I a r ea is im paired Techniques : Monitoring, dispersion m odel, analys is of spatial patterns using data f r om the satellite s ite s.

28

### d. Magnitude: how m u ch impairm e nt is due to each individual source Techniques : Dispersion model, receptor m odel

e. Tim e of occurrence Techniques : Monitoring, dispersion mode l, back trajectory, cam e ra

3. Uncerta inty of results : I n this c a se, the abil ity of a m odel to predic t the o b served trac er concentratio ns is an ind i cator of the model’s uncertainty.

29

### 30

## V. TECHNI QUES

A. Monitoring

Introductio n

This section describes a variety of ambient air monitoring methods that, if appropriate,

m i ght be used to support an attribution analys is. T h e m e thods described include those most commonly used in pollution studies or am bi ent monitoring program s and should not be considered an exhaustive list of poten tial m e thods. Methods in clude, IMPR OVE, filter based aerosol, continuous aerosol (incl udes optical m e thods such as the nephelom e ter), continuous gas and canister sam p ling, transm issom e ter, scene (i ncludes film , video, digital), and tracer or aircraft m e thods.

Several of the m e thods described ar e currently in use as a part of national, st ate, local, tribal, or private ambient m oni toring networks. These si tes are generally located in urban areas, but those near the area of study could be used in th e a ttr i bution analysis thereby reducing the cost of monitoring.

The IMPROVE network is designed to assess v i sibility in Cla ss I ar eas an d routin ely

m easure visibility im pair ing pollu tants. These site s of f e r value to the a t trib ution ana l ys is if they are located in the area of study.

The RA BART case stu d ies show addition a l ex am ples of the m e thods used during s ource attribution studies. The case studies also show that m e thods, other than ambient m onitoring, m a y be used to support the analysis . Existing program s su ch as CASTNET ( d ry deposition network), surface water deposition studies, o r s now deposition studies m a y provide additional d a ta for the attribution analysis.

Although not specifically listed as a monitoring technique, m e teorological m onitoring is an im portant elem ent the attribu tion an a l ysis. Coll ection of m e teorological data can range from sim p le wind, tem p erature, and relative hum idity m easure m ent to an array of acoustic wind profilers. The com p lexity of the m e t e orological monitoring program depends on data needs and the availability of existing da ta. As with am bient monitori ng, m e teorological data m a y be available at sites located near th e stu dy area and offers reduced m onitoring cost.

1. IMPROVE

Overview : T h e Interagency Monitoring of PROtect ed Visual Environm ents (IMPROVE)
program is a cooperative m easurem e n t effort governed by a s t eering comm ittee com p osed of representatives from Federa l and regional-state organiza tions. The IMP R OVE moni toring
program wa s established in 1985 to aid the crea tion of Federal and State implem e ntation plans for the protection of visibility in Class I areas (1 56 national parks and wilderness areas) as stipulated in the 1977 am endments to the Clean Air Act. The objectives of IMPROVE are to: (1) establish current visibility and aerosol conditi ons in m a ndatory class I areas; (2) identify chem ical species and em ission sources respon sibl e f o r exis ting m a n-m a de visib i lity impairm ent;

31

### (3) docum ent long-term trends for assessing progre ss towards the national vi sibility goal; and (4) with the en actm ent of the region al h aze ru le, pro v ide reg i onal haze m onitoring rep r es enting all visibility-protected federal class I areas where practical.

Magnitud e : Possible when used in conjunction with appropriate analytical techniques.

Frequency : Possible when used in conj unction with appropriate anal ytical techniques; Lim ited by twenty-four hour sample integration, and one-in-three day sam p ling frequency.

Duration : Possible when used in conjunction with a ppropriate analytical techniques; Lim ited by 24 hour sample integration, and one -in-three day sam p ling frequency.

Principle : T w enty-four hour integrated filter-based am bient monitor; Gravim etric analysis for PM 2. 5 

### (Module D) and P M 10 

### ); S from Particle Induced X-ray Em ission (PIXE); NO 3 

### from ion chrom a tography (denuded nylon filter from Modu le C); Organic and elemental carbon from Therm a l Optical Reflectance (TOR); H fr om Prot on Elastic S cattering (P ESA).

Uncerta inty : All elem ental S if f

r om sulf ate; All s u lf ate is ammonium sulfate; NO 3 

### (D enuder efficiency is close to 100 %. All ni trate is from a mmonium nitrate); Average organic m o lecule is 70% carbon; Carbon (organic and elem ental) is defined by the analytical method; Fin e soil bas e d o n elem ental com position; Course m a ss (PM 10 

### – P M 2. 5 

### ) consists only of insoluble soil particles.

Strengths : R e gulatory indicator for regional haze rule ; Long term data record in or near m a ny f e deral Clas s I are a s; Ex tensiv e netw ork currently in place.

Lim itations : Integrated twenty-four hour sam p le; one -in-three day sam p li ng interval; Nitrate losses due to volatilizatio n f r om f

ilter ; Not capab le of distingu ishing be twe e n prim ary particula t e and atm o spherically transfor m e d particulate.

Level of Expertise Required : Standard operating procedures av ailable for routine operation and

m a intenance; Chem ical analysis m u st be conducted by appropriate laboratory.

Regulatory Context : Regional Haze rule; Included in SIP Vis i bility Plan

2. FILTE R-BASE D AE ROSOL

Overview : F ilter-b ased aerosol m onitoring is u s ed to iden tify c h em ical species and ob tain concentratio n m easurements of atm o spheric cons titu ents that contr i bute to visibility im pairm e nt. Prim ary tec hniques in clude f ilte r-ba s ed aeroso l s a m p lers that colle ct sam p les on var i ous substrates in various size ranges such as PM 2. 5 

### or PM 10 

### . Aerosol m onitoring can provide fine

m a ss concentration, course m a ss concentration, optical absorption, m a jor and trace elem ents, organic and elem ental carbon, and su lfate, nitrate, and chloride ions. A variety of m e thods are available to conduct filter ba sed aerosol m onitoring. Many methods are approved as an EPA reference m e thod, while som e are not, but m a y of fer variability that the ref e rence m e thod does
not.

32

### Magnitud e : Possible when used in conjunction with appropriate analytical techniques.

Frequency : Possible when used in conj unction with appropriate anal ytical techniques; Lim ited by 24-hour sam p le integration and sampling fre quency (daily sam p ling is possible depending on instrum e nt s e lec t ed).

Duration : Possible when used in conjunction with a ppropriate analytical techniques; Lim ited by 24-hour sam p le integration and sam p ling freque ncy (daily sampling is possible depending on instrum e nt s e lec t ed).

Principle : T h e m e thods used for analyses of thes e filter m e dia includ e gravim etry (electro

m i crobalance) for m a ss; X-ray fluorescence (XRF) and particle induced X-ray em ission (PIXE) for trace elem ents; Ion chrom a tography (IC) for anions and selected cation s ; Controlledcom bustion for carbon; Gas chrom a tography/m a ss spectroscopy (GC/MS) for sem i -volatile organic p a rticles ; Special m easurem ent needs m a y include determ ining particle size and morphology through optical a nd/or electron m i croscopy.

Strengths : L a rge network of urban m onitoring available; Filter ba sed sampling allows for a variety of chem ical/elem e ntal analysis.

Lim itations : Integrated twenty-four hour sam p le; Ge nerally operated on one -in-three or one-insix day sam p ling interval (daily sam p ling is po ssible depending on instrum e nt selected); Not capable of distinguishing between prim ary particulate and atmospherically transformed particulate.

Level of Expertise Required : Standard operating procedures av ailable for routine operation and

m a intenance; Chem ical analysis m u st be conducted by appropriate laboratory.

Regulatory Context : Commonly used in NAAQS/SIP com p l i ance m onitoring networks.

3. CONTINUOUS AE ROSOL

Overview : Aerosols can be m easured continuously using several different m e thods. Optical

m easure m ent of aerosols can be m easured usi ng an instrum e nt such as a nephelom e ter to

m easure light scattering (bscat) or a aethelom e ter to m easure light absorption (babs) by aerosols (black carbon). Continuous instrum e nts such as TEOM or BETA can provide PM 10 

### or PM 2. 5 

### aerosol concentration.

Magnitud e : Possible when used in conjunction with appropriate analytical techniques.

Frequency : Possible when used in conj unction with appropriate anal ytical techniques; Lim ited by twenty-four hour sample integration and sa mpling frequency (daily sampling is possible depending on instrum e nt selected).

33

### Duration : Possible when used in conjunction with a ppropriate analytical techniques; Lim ited by twenty-four hour sam p le integration and sam p ling frequency (daily sam p ling is possible depending on instrum e nt selected).

Strengths : C ontinuous m easurem ent with at least hour ly tim e resolution; Nephelom e ters and Aethelom eters are commonly used to support Cla ss I area m o nitoring program s and an existing data record m a y be available in som e areas.

Lim itations : Continuous aerosol m easurem ent with m e thods such as TEOM and BETA are generally made in urban areas to suppor t NAAQS co m p liance networks; Not capable of distinguishing between prim ary particulate a nd atm o spherically transform e d particulate.

Level of Expertise Required : Standard operating procedures av ailable for routine operation and

m a intenance.

Regulatory Context : Commonly used in Class I area m onitoring networks or urban N AAQS

com p liance networks.

4. CONTINUOUS GAS E OUS

Overview : A variety of gaseous pollu tants, such as Ozone (O 3 

### ), Carbon Monoxide (CO), Nitrogen Dioxide (NOx), nitr ic oxide (NO), ammonia (NH 3 

### ), hydrogen peroxide (H 2 

### O 2 

### ), sulfur dioxide (SO 2) 

### , Organics, and HAPS/ TOXICS, ca n be m easured continuously. Gaseous monitoring is generally conducte d with instrum e nts that continuously draw sa m p le air and periodically (as frequently as once per second) analy ze the sample. Canister system s c o llect an

am bient air sam p le over a specific p e riod of tim e in clean evacuated canis t ers. The canisters are then subject to subsequent analysis at a labora tory using a m e thod such as GC/FID. This m e thod is able to provide tim e -integrated samples fr om several hours to twen ty-four hours or m o re. Regular checks of the flow rate, stability, re producibility, precision, and accuracy of these instrum e nts must be conducted on a regular schedule in order to ensure data quality.

Magnitud e : Possible when used in conjunction with appropriate analytical techniques.

Frequency : Possible when used in conjunction with appropriate analytical techniques.

Duration : Possible when used in conjunction with appropriate analytical techniques.

Strengths : C ontinuous m easurem ent with hourly tim e reso lution; Monitors available to identify variety of pollutants.

Weaknesses/Lim itations : Generally require conditioned envi ronm ent and frequent perfor m ance checks.

Practical Co nsideration s : Data m a y be available f r om established urban area m onitoring networks and som e Class I area m o nitoring netw orks; Additional cost ($/year) for new sites.

34

### Level of Expertise Required : Standard operating procedures av ailable for routine operation and

m a intenance.

Regulatory Context : Commonly used in urban N AAQ S compliance and HAPS/TOXICS networks.

5. TRANS M ISSOMETER

Overview : T r ansm issometers m easure the am ount of light transm itted through the atmosphere over a known distance (generally between 0.5 km and 10.0 km ) betw een a light source of known intensity and a receiver. The transm ission m easur em ents are electronically converted to hourly averaged lig ht extinction (b ext 

### ).

Magnitud e : Possible when used in conjunction with appropriate analytical techniques.

Frequency : Possible when used in conjunction with appropriate analytical techniques.

Duration : Possible when used in conjunction with appropriate analytical techniques.

Uncerta intie s : A transm issom e ter m u st be ins t a lle d in stab le location s with a clea r and unobstructed path to avoid in terference with the signal.

Strengths : C ontinuous m easurem ent of b ext 

### in m a ny Class I areas and some urban areas.

Lim itations : Not capable of identifying pollutants c ontributing to visibility im pair m e nt.

Level of Expertise Required : Standard operating procedures av ailable for routine operation and

m a intenance; Data processing/quality assu rance requires high level of expertise.

Regulatory Context : Commonly used in Class I area m on itoring networks and in some urban

areas.

6. SCENE

Overview : S cene m onitoring refers to the use of still and/or tim e-lapse photography (including digital im agery) to provide a qualitative repres entation of visual air quality. Scene m o nitoring data qua lity objective r e commendations are to d o cum e nt the appearan ce of scenes of inte rest under a variety of air qu ality and illu m i nation cond itions at d i fferent tim es of day and different seasons. Scene m onitoring docum ents the visual condition observed at a monitoring site. The data co llec t ion schedule can be ta ilo r e d to cap tur e the pe riods when visibility im pairment is m o st likely to occur at specific sites. Tim e -lapse m ovies (generally tim e-lapse video or super 8 mm film ) can be used at m onitoring sites and during special studies to docum ent the visual dynam i cs of a scene or source.

Magnitud e : Cannot provide a quantita tive m easurem ent of vis i bility im pairm e nt but can qualitatively illus t r a te va rious le vels of visibility im pairm e nt.

35

### Frequency : Possible depending on the m e thod used. Tim e -lapse video m a y be able to dem onstrate the frequency of the impairm e nt . The use of still photography to docum e n t im pair m e nt frequency depends upon the num ber of i m ages acquired over tim e

.

Duration : Possible depending on the m e thod used. Tim e -l apse video m a y be able to dem onstrate the im pairment frequency. The use of still pho tog r aphy to docum ent im pairm e nt frequency depends upon the num be r of im ages acquired over tim e

.

Uncerta intie s : n/a

Strengths : P r ovides im a g e/video record

Lim itations : Not capable of identifying pollutants c ontributing to visibility im pair m e nt.

Level of Expertise Required : Standard operating procedures av ailable for routine operation and

m a intenance.

Regulatory Context : Commonly used in Class I area m on itoring networks and in some urban

areas.

7. TRACER METHODS, LIDAR SYSTEM S , AIRCRAF T BAS E D MEASURE M ENTS

Overview : T h e m e thods described in this section are m o re specialized m e thods generally reserved for special studies as opposed to the pr eviously described m e thods that are used m o re routin ely. Tracer m e thods, lidar system s and airc raft based m e asurem ents will be described individually.

Tracer Meth ods : A tracer elem ent or compound is a s ubstance with unique characteristics that allows p o sitiv e identificatio n at very lo w concentrations. Th e tracer com pound of choice will vary b y source type and composition of the plum e being tracked. In general, the tracer must have very low natural background concentrations and ideally would have the sam e chem ical for m a nd properties as the com pound being tracked. In am bien t applications where use of the ideal tracer is not poss i b l e due to po tential enviro nm ental risk , a near-subs titu te com pound m a y be used. When used to determ ine potential source im p acts, the chosen com pound i s released from a source stack and downwind m onitors are used to detect the presence of the com pound.

Lidar Methods : A lidar trans m its short p u lses of lase r ligh t in to the atm o sphere. The la ser beam loses light to scattering as it travels. At each range, som e of th e light is backscattered in to a detecto r . Because the light takes longer to return from the m o re di stant ranges, the tim e dela y of the return pulses can be converted to the corres ponding distance between the atm o spheric scatterer and the lidar. The end res u lt is a profile of atm o spheric s catteri ng versus distance. Analysis of this signal can yield information about the distri bution of aerosols in the atm o s phere. The am ount of backscatter indicates the density of the scatters. This can be used to m easure cloud base height or track

36

### plum es of pollution. Other properties of the atm o sphe re can also be deduced from the lidar return signals. A frequency shif t in th e ligh t because of the Doppler effect perm i t s m easurement of wind speeds. By detecting the am ount of depolar ization, one can discrim i nate between liquid droplets and nonspherical ice partic les. Differential Absorption Li dar (DIAL) uses absorption, as evidenced b y reduced backscatter fro m greater d i stances, to m easure the concentratio n of
atm o spheric gases. A Ram a n lidar detects partic u l ar atm o spheric com ponents (su c h as water vapor) by measuring the wavelength-shifted return fro m selected m o lecules (NOAA).

Aircraft Based Measurem ents : Aircraft bas e d m easurem ent systems utilize specia lly equipped aircraft to m a ke pollutant and

m e teorological m easurem ents at various elevat ions throughout the study dom a in. The aircraft can be equip p ed with a multitude of gaseous, ae rosol, optica l and m e teorologica l equ i pm ent. This m easurem ent m e thod provides the advantage of vertical profiles of various param e ters, the ability to track point source plum es, and the ab ility to establish boundary conditions for future analytical and m odeling exercises.

References :

NOAA, At mospheric L i ght Division, Environmental Technology Laboratory, http://www2.etl.noaa.gov/DIAL_lidar.htm l

U.S. Environm ental Protection Agency, Visibi lity Monitoring Guidance (EPA-454/R-99-003), June 1999.

National Research Council, Pr o t ec tin g Visibility in Nationa l P a rks and W ilderness Areas, National Academ y Press, W a shington D.C., 1993, pp. 315-357.

37

### 38Table 1. Monitoring TechniquesCriteriaMonitoring MethodIMPROVEFilterBasedAerosolContinuous AerosolGaseous;Continuousmethods, canistersampling, etc.TransmissometerScene35mmfilm/8mmvideo, digitalTracer Methods, Lidarsystems, Aircraft basedmeasurementsPollutantPM10YesYesYesNoNoNoAll PossiblePM2.5YesYesYesYesNoNoNOx(Site specific)NoNoYesNoNoSO2(Site specific)NoNoYesNoNoSulfateYesYesNoNoNoNoNitrateYesYesNoNoNoNoCarbonYesYesNoNoNoNoOrganicsYesYesNoYesNoNoOtherReconstructedextinctionNephelometer -BscatAethelometer - BabsHAPS, TOXICSTotalExtinctionVisualParametersVisibility/Concentration ChangesMagnitudeYesYesAll PossibleAll PossibleAll PossibleNoAll PossibleFrequencyYesYesYesAll PossibleDurationYesYesYesTimeofDayNoNoAll PossibleAll PossibleAll PossibleYesLikely Part ofFLMCertification?PossibleNo39Monitoring Techniques (continued)PrincipalQualitative/QuantitativeQuantitativeQualitativeQualitative/QuantitativeStrengthsReconstructedextinctioncalculation,historicalrecordvarious chemicalanalysis, largenetworknationwideContinuousmeasurement,nephelometercommonly located inor near Class I areasContinuousmeasurement,variety of possiblepollutantsContinuousmeasurement,provides lightextinctionvalue,historicalrecordRelativelyinexpensive,uncomplicatedoperationalrequirementsLidar and airplane basedsystems can providedtemporal and spatialresults, tracer methodscan provide sourcereceptor dataWeaknesses/LimitationsFixed locationinornearClassI areas, alsolocated inseveral urbanareasIntegrated 24 hoursample generallycollected on onein-three schedule,commonly inurban areasTEOM, BETA, etc,commonly located inurban areasGenerally requireconditionedenvironment forproper operation,commonly locatedin urban areasFixed locationinornearClassI areasNumber of stillimages limited,video requiresstorage androutine reviewComplex and relativelyexpensive to operate,requires specializedtraining and knowledgeto operate and analyzeresultsDistinguishBART Sources?Possible withother analysisPossiblewithotheranalysisNoPossiblewithotheranalysisNoPossible withother analysisPossible with otheranalysisPractical ConsiderationsCostModerate; varies depending on the number of instrumentsLowHigh40

## B. Source Modeling

Introductio n Given the complex natural environment, the st ate m u st choose the conf iguration of modeling techniques that will provide the m o st inform ation on the contributing source or sources of im pairm e nt within th e lim ited resour ces of cu rrent technology, data, budgets, tim e and staff availability.

1. Physical Models Physical m odels are thos e that sim u late the m e teo r ology and air quality ov er an area. Modeling relies on a num e rical or analytical m odel to estim ate particu l ate concentrations in space and tim e . Because of its natu re and sources

, particulate m a tter is dif f icult to m odel over all spatial scales. Many air quality m o dels th at a r e c u rrently ava i labl e were designed to be applied over the regional scale w ith grid sizes from four t o forty kilo m e ters. Modeling requires detailed

m e teorological fields and em issi ons inventory over the entire dom a in. The com p ilation of data required to run these m odels can require m u ch effort and expertise. Efforts are underway by
governm e nt agencies in the U.S. to generate and archive both em issions and estim ated activity levels of m a ny source types in ge ographical inform ation system s.

Num e rical s ource-o r ien t ed m odels are desi gned to sim u late atmospheric diffusion or dispers i on and estim ate concentratio ns at defi ned recep tors. Num e rical s ource m odels can be grouped as kinem a tic, first-order closure, or second-order closure m odels (Bowne and Lundergan, 1983). Kinem a tic m odels are the sim p le st both mathem atically and conceptually. These m ode ls sim p lify the non-linear equations of turbulent motion, thereby perm itting a closed analytical approxim a tion to describe pollutant concentration (Green et a l

. , 1980). First-order closure m odels are based on the assumption of an isotropic pollutant concentration field. Consequently, turbulent eddy fluxes are estim ated as being proportional to the local spatial gradient of the transport quantities. T h e Eulerian grid m odels, Lagrangian particle m odels, and trajectory puff/plum e m o dels are included in this category. Second- order closure m odels involve a series of algorithm transfor m a ti ons of the equations of state, m a ss continuity, m o m e ntum , and energy by us ing the Bous sinesque ap proxim a ti on and Reynold’s decom p osition theo ry (Holton, 1992; Stull, 1988).

2. Spatial Scales

The m odel’s applic able s p atia l sca l es play a large role m eeting the analysis ' objectives and its ab ility to accurately a ssess spatial variab ility. PM 10 

### and P M 2. 5 

### concentrations m o deled or

m easured at any recep tor result from the com p lex interaction of m e teorology, chem ical transform a tions and em issions from nearby and di stan t sour c e s. For exa m ple, a m o nitor loca ted
near an ope r a ting con s tr uction s ite w ill b e im pacted m o re by the daily con s truc tion a c tivity than the surrounding area. That site m a y be classified as representing an area of a few tens of m e ters
to no m o re than one kilo m e ter depending on the size of the c onstruc tion area and f u g itiv e dust control m e a s ures.

The dim e nsions given below are nominal rather th an exact and are presented as defined in 40 CFR part 58.

41

### a. Micro-Scale (10 to 100 m ) : This scale does not apply to scenarios releva nt to the attribution problem . Modeling at the m i croscale is usually d one by sim p le Gaussian plum e m ode ls such as ISCST3. Measurem ents in urban areas can show cons iderab le varia tions at this sc ale w h ile those in pris tin e ar eas would n o t. Varia tion s of ten occu r when m onitors a r e lo ca ted clo s e to a low-lev e l

em issions source, such as a busy roadway, constr uction site, within a co mmunity that uses wood stoves, or a short industrial stack. Fortunately, compliance mon itoring site exposure criteria avoids m i croscale influences even fo r source-oriented m onitoring sites.

b. Middle Scale (100 to 500 m ) : Middle-scale m onitors show significant differences between locations that are ~0.1 to 0.5 km apart. These di fferences m a y occur near large industrial areas with m a ny different operations or near large cons truction sites. Monitors with m i ddle-scale zones of

represen tation a r e of ten source -or i ented, u s ed to dete rm ine the contribu tions f r om em itting activ ities with m u ltiple, individu al s ources to n e arby comm unity exposu r e m onitors.

c. Neighborhood Scale (500 m to 4 km): Nei ghborhood-scale monitors do not show significant differences in particulate concentrations with spacing of a few kilom e ters. This dim e nsion is often the size of e m issions and m ode ling grid s used in large urban areas for PM source

assessm ent, so this zone of representation of a monitor is the only one th at should be used to evaluate such m odels. Sources affecting nei ghborhood-scale sites typically consist of sm all individu al em itters, such as clean, paved, curbed roads, uncon gested traffic flow without a significant fraction of heavy-dut y vehicles, or neighborhood use of residential heating devices such as firep l aces and wood stoves.

d. Urban Scale (4 to 100 km ): Urban-scale m onitors show consistency am ong m easurements with m onitor separations of tens of kilom e ters. These m onitors repres ent a m i xture of particle s from m a ny s ources within the urban com p lex, including those from the sm aller scales. PM

m easure m ents at urban-scale locations are not dom i nated by any pa rticular neighborhood, however. Urban-scale s i tes are often located at h i gher elevations and away from highly traveled roads, industries, and residential heating.

e. Regional-Scale Background (100 to 1,000 km ): Regional-scale background m onitors show consistency am ong measurem ents for m onitor separations of a few hundred kilom e ters. Background concentrations are often m o re consis tent for specific chem ical com pounds, such as sulfate or n i trate, than th ey are for P M m a ss co ncentrations. Regional-scal e PM is a com b ination of naturally-occurring aerosol from windblown dust and m a rine aerosol as well as particles generated in urban and industrial areas that m a y be m o re than 1,000 km distant. Regional-scale sites are b e st located in rural areas away from local sources, a nd at higher elevations. National parks, national wilderness areas, and m a ny stat e and county parks and re serves are appropriate areas for regional-scale sites. Many of the IM PROVE sites characterize PM regional scale background in different regi ons of the United States.

f. Continental-Scale Background (1,000 to 10,000 km ): Continental-scale background monitors sh ow little variation ev en when they are separated b y m o re than 1,000 km . They are hundreds of kilom e ters from the nearest sign ificant em itters. Though thes e sites m e asure a

m i xture of natural and diluted m a nmade source contributions, the m a nm a d e com pone nt is at its

m i ni m u m expected concentration. T h e Jarbidge W ilderness IMPROVE si te in northern Nevada is a good exam ple of a c ontinental- scale background site for particulate m a tter in North Am erica.

42

### e. Global-Scale Background (>10,000 km ): Global- scale background m onitors are intended to quantif y con centr ation s transpor ted b e tween dif f e rent con tine n ts as well a s natura lly -e m itted particles and precursors from sea spray, vol canoes, and windblown dust. Yellow sand from China has b een detected at the Maun a Loa, HI, laboratory (Darzi and W i nchester, 1982; Braaten and Cahill, 1986), as well as on the North Am erican con tinent. Red dust from Africa’s Sahara desert h a s b een detected at Mt . Yunque, Puerto R i co and over the southeastern United States. Other global-scale sites include McMurdo, Palm er , and Ahmundson-Scott stations in Antarctica (Lowenthal et al. , 1996 ), Pt. Barrow, Alaska, and Mace Head, Ireland.

3. Chemical Composition

This sec tion illus t r a tes h o w the chemical com position of aeros ols is an im portan t consideration in the choice of particulate m a tte r models. The knowledge of how the aerosol' s

com position varies over an area will play a key role in the attr ibution study design.

The relative abundance of che m ical com ponent s in the atm o sphere closely reflect the characteristics of e m ission sources. Major ch emical com ponents of PM 2. 5 

### and PM 10 

### m a ss in urban and rural areas consist of nitrate, sulfat e, ammonium , c a rbon, geological m a terial, sodium chloride, and liquid water.

Che m ical compositions can vary spatially in all scales of the atmosphere and depend on sources surrounding the monitoring s ite. For example, on the continen tal scale, the eastern U.S. fine particulate chem ical com positions are differe nt than those of the western states. In the eastern portion of the U.S., nonurban PM 2. 5 

### is dom i nated by secondary sulfate, organics and elem ental carbon (EPA, 1996). The data to supp ort this conclusion are based on the IMPROVE and CASTNET networks. These networks provide a background fine-fraction aerosol database because the monitoring s ites are p r imarily loca ted in national parks and wildernes s areas. Analysis of this network shows that the western U.S. nonurban PM 2. 5 

### aerosol is predom inantly carbon in nature. Nitrate also contributes si gnificantly to the f i ne particle m a ss budget particularly in central and coas tal California. W ithin these ge neralizations, obvious departures will be f oun d especially near sour ces such as nea r the oc ean a nd urban ar e a s where th e aerosol will be p r imarily inf l uen ced by sea s a lt and combustion pa rticles, r e spec tively.

The typical PM 2. 5 

### chem ical com positions vary by season (Chow et al., 1993a; 1996a, Watson et al., 1997), and consist of the following m a jor com p onents:

a. Organic Carbon: Organic carbon is com posed of gases and particles containing

com b inations of carbon and hydrogen atom s. Or ganic com pounds found in am bient air m a y also be associated with other elem ents and co m pounds, particularly oxygen, nitrogen, sulfur, halogens, and m e tals. Particulat e organic carbon consists of hundreds, possibly thousands, of separate compounds (Rogge et al ., 1993a). The m a ss concentration of organic carbon can be accurately m easured, as can carbon ate carbon (C how et al., 1993b), but only about ten percen t o f the specific organic compounds th at it contains have been m eas ured. Vehicle exhaust (Rogge et al., 1993b), residential and agricu ltural burning (Rogge et al., 1998) , m eat cooking (R ogge et al., 1991), fuel com bustion (Rogge et al., 1997), ro ad dust (Rogge et al., 1993c), and particle for m ation from heavy hydrocarbon gases (Pandis et al., 1992), are the m a jor sources of organic carbon in P M 2. 5


### .

43

### b. Elem ental Carbon: Elemental carbon is bl ack, often called “soot.” Elem ental carbon contains pure, graphitic carbon, but it also contai ns high m o lecular weight, dark-colored, nonvolatile organic m a terials such as tar, biological m a terial (e.g., coffee), and coke. Elem ental carbon usually accom p anies organ i c carbon in co mbustion em issions, with diesel exh a ust (W atson et al., 1994a, 1998) bei ng the largest contributor.

c. Sulfate: Ammonium sulfate ((NH 4 

### SO 4 

### ), ammonium bisulfate (NH 4 

### HSO 4 

### ), and sulfuric acid (H 2 

### SO 4 

### ), are the m o st common sulfate com pounds in PM 2. 5 

### . T h ese com p ounds are water-soluble and resid e almost exclus ively in the P M 2. 5 

### size fraction. Sodium sulfate (Na 2 

### SO 4 

### ) has been found in coas tal areas where su lfuric acid h a s been ne utralized by sodium chloride (NaCl) in sea salt. Although gypsum (Ca 2 

### SO 4 

### ) and some other geological com p ounds contain sulfate, these are not easily dissolved in water for chem ical analysis an d are m o re abundant in the coarse fraction than in PM 2. 5 

### ; they are usually class i fied in the geologi cal fraction.

d. Nitrate: Ammonium nitrate (NH 4 

### NO 3 

### ) is the m o st abundant nitrate com pound, a large fraction of PM 2. 5 

### occurs during winter, and a m o derate fr action occurs during fall. Sodium nitrate (NaNO 3 

### ) is found in the PM 2. 5 

### and coarse fractio ns near th e o ceans and s a lt playas. S m all quantities of sodium nitrate have been found in summ ertim e particulate m a tter inland owing to transpo r t fro m the ocean (Chow et al.

, 1996b).

e. Ammonium : Ammonium sulfate (NH 4 

### SO 4 

### ) and ammonium nitrate (NH 4 

### NO 3 

### ) are the m o st common compounds contain i ng ammonium from reactio n s between sulf uric acid, nitric acid, and ammonia gases. W h ile most of the sulfur dioxi de and oxides of nitrogen originate from fuel

com bustion in stationary and m obile sources, m o st of the ammonia derives from living things, especially anim al husbandry prac tic ed in dairie s and f eedlots

.

f. Geological Material: Su spended dus t consis ts m a inly of oxid e s of alum inum , silicon, calcium , titanium , iron, and other m e tal oxides. In areas su rrou nded by substantial terrain (i. e ., mountains), eons of runoff produce m i neral co mposition s in soils that can be fairly hom ogeneous, with the exception of places where dr y lak e b e ds exis t that have accu mulated salt deposits. Ind u strial p r ocesses su ch as steel m a king, sm elting, and m i ning have dis tinct geological

com positions. For instance, cem ent production an d distribution facilities m a y use alcareous, siliceous, argillaceous, and ferriferous m i nerals that m a y not be natural to the region, w ith lim estone (CaCO 3 

### ) being the m o st abundant (G reer et al ., 1992). Suspended geological m a terial resides m o stly in th e coarse particle f r action (Hou ck et al, 198 9,1990), and typically co nstitu tes ~50% of PM 10 

### while only contributing 5 to 15% of PM 2. 5 

### (Watson et al., 1994b).

g. Sodium Chloride: Salt is found in suspended particles near oceans, open playas, and after de-icing m a terials are applied. Bulk s ea water con t ains 57 ± 7% chloride, 32 ± 4% sodium , 8 ± 1% sulfate, 1.1 ± 0.1% soluble potassium , and 1.2 ± 0.2% calcium (Pytkowicz and Kester, 1971). As noted above, sodium chloride is of ten neutralized by nitric or sulfur ic acid in urban air where it is encountered as sodium nitrate or sodium sulfate.

h. Liquid W a ter: Soluble nitrates , sulfates, amm onium, sodium , ot her inorganic ions, and som e organic m a terial (Saxena and Hildem ann, 1997) absorb water vapor from the atm o sphere, especially w h en relativ e hum i dity ex ceeds 70% (Tang and Munkelwitz, 1 993). Sulfuric acid absorbs som e water or deliquesces at all hum id ities. Particles containing these com p ounds grow

44

### into th e drop let m ode as they ta ke on liquid water. Som e of this water is re tained when particle s

are sam p led and weighed for m a ss concentration. The precise am ount of water quantified in a PM 2. 5 

### depen d s on its ion i c com position and the e qu ilib ration rela tive hum idity applied prior to laboratory w e ighing.

Am bient m a ss concentrations contain both pr im ary and secondary particles. Prim ary particles are directly em itted by sources and usually undergo few changes between source and
recep tor. Atmospheric concentration s of prim ar y particles are, on average, proportional to th e quantities th at ar e em itte d.

Secondary particles are those th at form in the atm o sphere from gases that are directly

em itted by sources. Sulf ur dioxid e , a mmonia, and oxides of nitrog en are the pre c urso rs f o r sulfuric acid, ammonium bisulfat e, ammonium s u lfate, and ammoni um nitrate particles. “Heavy” volatile organic com pounds or HVO C (those containing m o re than eight carbon atom s) m a y also change in to particle s. The m a jority o f these tr ans f orm a tions r e sult f r om intense pho toc h em ical reactions that also create high ozone levels. Secondary particle s usually form over several hours or days and attain aerod ynam i c diam eter s in th e accum u lation m ode between 0.1 and 1 μ m. Several of these particles, notab ly those containing ammonium n itrate, are volatile an d transfer

m a ss between the gas and particle phase to m a inta in a chem ical equilib riu m . This vola tility ha s im plications for a m bient concentration m eas urem ents as we ll as for gas and particle concentrations in the atmosphere.

Am bient concentrations of secondary aerosols are not necessarily pr oportional to quantities of e m issions since the rate at which they for m m a y be lim ited by factors other than the concentration of the precursor gases. Secondary particulate a mmonium nitrate concentrations depend on gaseous ammonia and nitric acid concen tra tions as well as temperatu r e and rela tive hum i dity. A nearby source of ammonia m a y cause a localized increase in PM 2. 5 

### concentrations by shifting the equilibrium from the gas to th e particulate am m onium nitrate phase (Watson et al., 1994c). Ammonium sulfate m a y for m rapidly fr om sulfur dioxide and ammonia gases in the presence of clouds and fogs, or slow ly in dry ai r. Because fin e particle deposition v e locities are slower than those of th e gaseous precursors, PM 2. 5 

### m a y travel m u ch farther than the p r ecurso r s, and secondary particles precursors are often f ound far from their em issions sources and m a y extend over scales exceeding 1,000 km.

4. Particle Formation

Ammonium nitrate and ammoni um sulfate aeros o ls are th e most prevalent second ary particles found at urban and non-urban sites throughout the U.S. during the winter. These particles can for m when gas m o lecules are attr acted to and adhere to exis ting par tic les

. Sulfur dioxide gas changes to particulat e sulfate through gas- and aqueous-phase transform a tion pathways. In the gas-phase path w a y, ultraviolet sunlight induces photochem i cal

reac tions c r e a ting ox idiz ing species that re act w ith a wide var i ety of atm o spheric cons titu ents. The gas-phase transformation rate ap pears to b e controlled more by the p r esence o r ab sence of the hydroxyl radical and its com p eting reactions of other gases than by the sulfur dioxide concentratio ns.

45

### In the presence of fogs or cl ouds, sulfur dioxide dissolves in droplets where it experiences aqueous reactions that are m u ch faster than gas-phase reac tions. W h en ozone and hydrogen peroxide are dissolved in the dr oplet, the sulfur dioxide is qu ickly oxidized to sulfuric acid. W h en ammonia is d i sso lved in the d r ople t , the s u lf uric acid is neutralized to amm onium sulfate. If the fog or cloud evaporates and relative hum idity decreases below 100 percent, the sulfate particle exists as a sm all droplet that includes a portion of liquid water. As the relative hum i dity further decreases below 70 percent, the droplet ev aporates an d a sm all, solid sulf a t e p a rticle

rem a ins. The reac tions within th e fog droplet are very fast, a nd the rate is controlled by the solubility of the precursor gases. Aqueous transform a tion rates of sulfur dioxide to sulfate are 10 to 100 tim es as fast as gas-phase rates. These ch em ical reactions are crit ical to und erstanding PM concentrations in areas and downwind of areas that em its large am ounts of SO 2 

### . The location and SO 2 

### e m issions output of large point sources such as coal and oil fired power plants need to be

m a pped and com p ared with transport patterns in order to determ ine the impact of ammonium sulfate particles on am bien t surface concentration s

. Fogs serve as an environm ent for creating part icles and as vehicles for particle rem o val. During heavy fogs, particles and precursor gases ar e scavenged as fog droplets grow to sizes that settle rapidly to the su rface. The extent and in te nsity of these fogs is so poorly characterized, however, that it is not yet possible to determ in e where and when particle for m ation overtakes particle deposition, thereby adding to the PM 2. 5 

### concentration loading.

Nitrogen oxide converts to nitrogen dioxide, prim a r ily by reaction with ozone. Nitrogen dioxide can: 1) change back to nitrogen oxide in the presen ce of ultravio le t radiation; 2) change to short-lived species which take place in other ch em ical reactions; 3) form organic nitrates; or 4) oxidize to form nitric acid. The m a jor pathway to nitric acid is a reaction with hydroxyl radicals that transform s nitrogen dioxide to nitric acid. Nitric acid deposits from the atm o sphere fairly rapidly but, in the presence of ammo nia, it is neutralized to partic ulate ammonium nitrate. This is an im portant process in secondary partic le production because m a ny agricultural areas surrounding populated urban areas contain larg e ammonia sources. Chow and Egam i (1997) show that San Joaquin Valley a mmonia concentrations are large during w i nter. Conversion rates for nitrogen dioxide to nitric aci d, ranging from le ss than one per cent per hour to ninety percent per hour. These rates are typically five to ten tim es the conversion rates for sulfate form ation. Though they vary throughout a twenty-four hour period, these rates are significant during both daytim e and nighttim e hours, in contrast to the g a s-phase sulfate chem istry that is m o st active during day l ight hours. T h e im portant nitric acid -ammonia reaction has imp lications to network design by the need to locate and m a p possible sources of ammonia. Significant sources of ammonia are associated with anim al husbandr y a nd f e rtilize r applic ation s

. Locating an d estim ating a mmonia em issions will b e a dif f i cult ta sk bec a use it is no t trad ition a lly tab u lated in

em ission inventories and requires further resear ch to refine the m e thodology to m easure the

em issions.

While ammonium sulfate is a fairly stab le com p ound, ammonium nitrate is not. Its equilibrium with gaseous ammonia and nitric ac id is strongly influenced by tem p erature and rela tive hum idity. Atm o spheric p a rtic le nitra t e ca n occur in atmospheric a e rosol pa rtic les as so lid ammonium nitrate o r as ionized ammonium nitrate in aerosol par ticles containing water. In both

46

### the solid and ionized form s, a mmoni um nitrate is in equilibrium with ga s-phase nitric acid and ammonia.

For fixed relative hum idity, increasing tem p erat ure decreases the particle n itrate frac tio n. This is a consequence of the direct relation be tween the equilibrium constants and tem p erature. As tem p erature increas es, the equ ilibrium cons tants increase, which m e ans higher gas-phase pressures can be supported, thereby reducing the particle nitrate fract ion. For fixed hum idity, decreasing tem p erature increases the particle nitr ate fraction. As tem p eratur es approach 0°C, the
curves app r oach lim itin g values. Pa rticle f r ac tio ns of one are used f o r io n ratios gre a ter than or equal to one, and particle fractions are determ ined by the amount of available amm o nia for ion ratios less than one. For the higher temperatur e s , incre a sing r e lative hum idity in crea se s the particle nitrate fraction. This is a consequence of liquid wate r present for the 60% and 80% relative hum idity cases. When there is sufficient ammonia present with 30% relative hum i dity, more than 9 0 % of the nitra t e is in th e particle ph ase for tem p eratu r es less than 20°C. More than half of the particle nitrate is gone at tem p er atures above 30°C, and all of it disappears at
tem p eratures above 40°C.

At m o spheric water is another im portant com ponent of suspended pa rticu l ate m a tte r. The sharp rise in liquid water cont ent at r e lative hum idities betw een 55% and 75% is known as deliquescence. A precise hum idity at which solubl e particles take on liquid water depends on the chem ical m i xture and temperature. P a rticles c ontaining these com pounds gr ow into the droplet mode as they take on liquid water, so the sam e concentration of sulfate or nitrate m a kes a m u ch larger contribution to light extinc tion when hum i dities are high (> 70 percent) than when they are low (<30 percent). Excess liquid water is also m easured as part of the PM 2. 5 

### m a ss whe n sam p led by light scattering continuous m onitors or when fi lters have not been eq uilibrated at relative hum i dities less than 30 % prio r to w e ighing.

Som e of the organic carbon in suspended particles is also of secondary origin. Secondary organic compounds in particulate m a tter include aliphatic acids, alcohols, arom atic acids, nitroarom atics, carbonyls, esters, phenols, and alip hatic nitrates (G rosjean and Seinfeld, 1989; Grosjean, 1992, Pandis et al., 1992, 1993; Sein feld and Pandis, 1998). Norm ally, prim a r y organic carbon particles are m o re prevalent than secondary orga nics with exceptions such as those found in Los Angeles where co nditions of clear sk ies an d high photo c hem i cal smog are frequent. Although secondary organi c aerosol was thought to be m i ni m a l during winter in central California, recent an alyses (Strader et al., 1998 ) d e m onstrate that it could be as m u ch as 20% of twenty-four hour organic carbon in som e sam p le s. This occu rs because low wintertim e tem p eratures lower the saturation vapor pressure for sem i -volatile organic com pounds. This is probably m i nor during winter and f a ll when photochem i cal reactions are not dom inant.

The exact precursors of secondary organics ar e not well understood, but they are believed to consist of heavy hydrocarbons with more than seven carbon atom s. Odum (1997) identifies

arom atics as the m a jor group of commonly m easur ed reactive organic ga ses that affect both ozone and secondary aerosol form ation.

47

### 5. Source Modeling Tech niques

Before selecting a m odeling technique, it is wise to estab lish a conceptua l model. A conceptual model describes the re levant physical and chem ical pr ocesses that affect em issions, transpo r t, an d transf orm a tion spe c if ic to the regi o n of interes t

. It is the starting point for any source apportionm ent process. Conceptual m odels take advantage of the large body of scientific knowledge already acquired. They id entify the sources that are likel y to be present and elim inate those that are not. They exam ine m e teorological conditions that a ffect concentrations and focus further m o deling on the conditions c onducive to the high concentrations.

Modeling te chniques r e levant to attribution a r e s p lit into s e v e ral catego ries dependin g

com p lexity, physical attributes, purpose and cost to execute. The following tables on pages 55 to 62 provide a m a trix of detailed inform ation on specific m o dels grouped in these categories.

a. Puff Modeling Techniques

These m odels are b a sed on a Lagran gian fram ew ork where air parcels are track ed spatially and tem porally. They can include ch em ical m echan ism s as well as deposition effects. The m o st commonly used puff m o del is the C A LMET/CALPUFF (Scire et al., 2000).

b. Grid Modeling Techniques

For estim ating PM 2. 5 

### levels, Eulerian m odels that in clude aerosol m odules sim u lating the physical and chem ical processes governing particulat e concentrations in th e atm o sphere are m o re suitable than Lagrangian models such as plum e trajectory m o dels. Eulerian three-dim e nsional models m a y use either a sim p lifie d treatm e nt of atm o spheric chem istry (usually used to address long-term particulate concentrations at urban sites) or include a m o re detailed atm o spheric chem istry tr eatm e nt (us u ally us ed to sim u la te only a few days of episodes due to their

com positional cost).

Commonly used long-term Eulerian models w ith sim p lified atm o spheric processes include (Seigneur et al., 1997):

• Urban Airshed Model V e rsion V (U AM-V).

• Urban Airshed Model with version V with Linea r Chem istry ( UAM-LC)

• Regulatory Modeling S y stem for Aerosol and D e position (R EMSAD).

Short-term Eulerian m o dels with co mplex atm o spheric processes include:

• Urban Airshed Model V e rsion V with Aerosols (UAM-AER O),

• Urban Airshed Model with Aeroso l Inorganic Module (UAM-AIM).

• SARMAP Air Quality Model w ith A e rosols (SAQM-AERO).

• Community Multi-sc a le Air Quality Model (CM AQ)

48

### • Com p rehensive Air Quality Mode l with ex tensio ns (CAMx)

All of the above m e ntioned Eulerian models ha ve been developed by va rio u s scien tis ts f r om univers ities, f e deral and s t ate agencie s , and th e pr ivate secto r . These par tic ulate air qu a lity models provide a three-dim e nsional treatm e nt to sim u late the fate and transport of atm o spheric
contam inants. All of thes e Euler i an models in clud e gas phase chem istr y and aerosol dynam i cs and sim u late atm o spheric inorganics (such as sulf ate, nitrate, and ammonium ), but som e of these models do not include the treatm ent of organics (i.e., REMSAD and UAM-LC).

c. Lagrangian Trajectory Model Tech niques

The advantages of using Lagrangian models ar e the ease of u s e, the ab ility to perform m a ny trajecto r ies and perform back trajectories. Commonly used Lagrangian models include HYSPLIT ( D raxler and Hess, 1997) and FLEXPART (Stohl and Siebert, 2001).

d. Meteoro log i cal Modeling Techniques

Meteorological m odels describe transport, disp ersion, vertical m i xing, a nd moisture in tim e and space. Meteoro l ogical m odels consist of strai ght line, in terpolation (term e d diagnostic), and first principle (term e d prognostic) form ulations, with increasing levels of com p lexity and requirem e nts for com put ational and data resources.

The straight line m odel is applied to hourly wind directions from a si ngle monitor, assum i ng an air m a ss travels a distance equal to the wind velo city in the m easured di rection, regardless of the dis t ance f r om the m o nitor i ng site. This m odel is applicable for a few hour s of transport in flat terrain, typically for evaluating a single em issions source.

Interpo l a tio n m odels integrate wind speed and directions f r o m m u ltiple m easurem ent locations, including upper air m easurem ents provi de by rem o te sensors or balloon launches. The more advan ced of these models allo w barriers, s u ch as m ountains, to be p l aced between monitors. Wind fields, therefore, show different directions and ve locitie s at dif f e rent horizon tal and vertica l position s . In terpo l ation wind m odels are app lic a b le to dom ains with a lar g e num ber of well-placed m onitors and for estim a ting the move m e nt of air m a sses from m a ny s ources over transpo r t tim e s of m o re than ha lf a day. The number and placem ent of monitors, es pecially upp er air m onitors, is especially im portant in m ountai nous terrain and in coastal areas where winds are unusual.

First principle m odels (Stauffer and Seam an, 1994; Seam an et al., 1995; Koracin and Enger, 1994) em body scientists’ best knowledge of atmospheric physics and therm odyna m i cs,

em ploying basic equations for conservation and transfer of energy and m o m e ntum . Also known as “prognostic m odels,” first principle m odels pur port to need no data other than values from a sparse upper air network for interpolation. They are com putationally intensive, often requiring
supercom puters but have becom e m o re practical and cost-effectiv e as workstation and desktop

com puters becom e m o re powerful. Modern versions use “four-dim ensional data assim ilation” or FDDA that com p are m o del-calculated wind, humidity, and temperature fields with

m easure m ents and “nudge” m odel outputs toward observations.

49

### A m o re complex m e teorologica l m o del is no t ne cessar ily a b e tte r m odel for a spec if ic application. One of the most widely used fi rst principle m o del is the Fifth-Generation NCAR/Penn State Mesoscale Model or MM5 m o del (Grell et al., 1995). T h e MM5

m e teorological m odel has been adopted as the plat form for central California air quality studies (Seam an et. al., 1995). MM5 input data consist of wind speed, wind direction, tem p e r ature,
atm o spheric pressure, and relative hum i dity at ground level, within th e boundary layer, and above the boundary layer. In m a ny cases in valle y situations ten-m e ter vertical resolution is needed within the surfac e layer, 30-50 m resolution is needed in the valley wide layer, and 100 m resolution is needed above the valleywide layer up to ~2000 m agl (W atson et al., 1998). Tim e resolu tion is at le ast hou rly f o r thes e m easur em ents. Measu r em ents are needed where large differences are expected, although th is is largely unknown for winter.

References :

Bowne, N.E.; and Londergan, R.J. (1983). Overview , results and conclusions for the EPRI plum e model validation and developm ent project: Plains site. Report No. EA-3074 PROJECT 1616. Prepar ed by Electric Power and Res earch In stitu te, Pa lo Alto, CA.

Braaten, D.A.; and Cahill, T.A. (1986). Size and com position of Asian dust transported to Hawaii. Atmos. Environ., 20 : 1105-1109.

Chow, J.C.; Watson, J.G.; Lowenthal, D.H.; So lomon, P.A.; Magliano, K.L.; Zim a n, S.D.; and Richards, L.W. (1993a). PM 10 

### and P M 2. 5 

### com pos itions in California' s San Joaquin Valley. Aerosol Sci. Technol., 18 : 105-128.

Chow, J.C.; Watson, J.G.; Pritchett, L.C.; Pier son, W

. R.; Frazier, C.A.; and Purcell, R.G. (1993b). The DRI Therm a l/Optical Reflectan ce Carbon Analysis System: Description, Evaluation and Applications in U.S. air quality studies. Atmos. Environ., 27A : 1185-1201.

Chow, J.C.; Watson, J.G.; Lu, Z.; Lowenthal, D. H.; Frazier, C.A.; Solomon, P.A.; Thuillier, R.H.; and Magliano, K.L

. (1996a). D e scriptive analysis of PM 2. 5 

### and PM 10 

### at regionally representative locations during SJVAQS/AUSP E X. Atmos. Environ., 30 : 2079-2112.

Chow, J.C.; Watson, J.G.; Lowenthal, D.H.; and Countess, R.J. (1996b). S ources and chem istry of PM 10 

### aerosol in Santa Barbara C ounty, CA. Atmos. Environ., 30 : 1489-1499.

Chow, J.C.; and Egam i, R.T. (1997). San Jo aquin Valley Integrated Monitoring Study: Docum e ntation, evaluation, and descriptive analysis of PM 10 

### and PM 2. 5 

### , and precursor
gas m easurem ents - Technical Support Studies No. 4 and No. 8 - Fi nal report. Prepared for California Regional P a rticulate Air Qual ity Study, California Air Resources Board, Sacram ento, CA, by Des e rt Research Institute, Reno, NV.

Darzi, M.; and W i nchester, J.W

. (1982). Aero sol characteristics at Mauna Loa Observatory, Hawaii, af te r east As ian dust sto r m episodes. J. Geophys. Res., 87 : 1251-1258.

Draxler, R. R.; and Hess, G.D. (1997). Descrip tio n of the Hysplit_4 m odeling system . Report No. NOAA Tech Mem o ERL ARL-224, Decem ber 1997. Prepared by Air Resources Laboratory, NOAA, Silver Spring, MD.

50

### Green, A.E.; Singhal, R.P.; and Venkateswar, R. (1980). Analytic extensions of the Gaussian plum e m ode l. JAPCA, 30 : 773-776.

Greer, W

. L.; Johnson, M.D.; Morton, E.L.; Raught, E.C.; Steuch, H.E.; and Trusty, C.B. (1992). Portland cem e nt. In Air Pollution Engineering Manual, Buonicore, A.J. and Davis, W.T., Eds. Van Nostrand Reinhold, New York, NY, pp. 746-766.

Grell, G.A.; Dudhia, J.; and Stauffer, D.R. ( 1995). A description of the fifth-generation Penn State/NCAR Mesoscale Mode l (MM5). Report N o. NCAR Te chnical Note, NCAR/TN398+STR, June 1995. Prepared by N a tional Center for Atm o s pheric Research, Boulder, CO.

Grosjean, D.; and Seinfeld, J.H. (1989). Param e teri zation of the for m ation potential of secondary organic aerosols. Atmos. Environ., 23 : 1733-1747.

Grosjean, D. (1992). In -s itu organic aerosol form ation during a sm og episode: estim ated production and chem ical functionality. Atmos. Environ., 26A : 953-963.

Holton, J.R. (1982). An Introduction to Dynamic Meteorology. Academ ic Press, New York, NY.

Houck, J.E.; Chow, J.C.; and Ahuja, M.S. (1989) . The chem ical and size characterization of particulate m a terial originating from geological sources in California. In Transactions, Receptor Models in A i r Resources Management, W a tson, J.G., Ed. Air & W a ste Managem e nt Associatio n, Pittsbu rgh

, PA, pp. 322-333.

Houck, J.E.; Goulet, J.M.; Chow, J.C.; W a tson, J.G.; and Pritchett, L.C. (1990). Chem i cal characterization of em iss i on sources contributing to light extinction. In Transactions, Visibility and Fine Particles, Mathai, C.V., Ed. Air and W a s t e Management Association, Pittsbu rgh, PA, pp. 437-446.

Koracin, D.; and Enger, L. ( 1994). A num e rical study of boundary-l ayer dynam i cs in a m ountain valley. Part 2: Observed and sim u lated charac ter i s itcs of atm o spheric s t ab ility and local flows. Boundary Layer Meteorology, 69 : 249-283.

Lowenthal, D.H.; Chow, J.C.; W a tson, J.G.; Dipple, W

. A.; and Mazzera, D.M. (1996). PM 10 

### source apportionm ent at McMurdo S t ation, Antarctica. EM, 28-30.

Odum , J.R.; Jungkam p, T.P.W

. ; Griffin, R.J.; Forstn er, H.J.L.; Flagan, R.C.; and Seinfeld, J.H. (1997). Arom atics, reformulated gasoline, and atmospheric organic aerosol form ation. Environ. Sci. Technol., 31 : 1890-1897.

Pandis, S.N.; Harley, R.A.; Cass, G.R.; and Se infeld, J.H. (1992). Secondary organic aerosol for m ation and transport. Atmos. Environ., 26A : 2269-2282.

Pandis, S.N.; W e xler, A.S.; and Seinfeld, J.H. (1993). Secondary organic aerosol form ation and transport - II. Predicting the am bient sec ondary organic aerosol size distribution. Atm o s. Environ., 27A : 2403-2416.

51

### Pytkowicz, R.M.; and Kester, D.R. (1971) . The physical chem istry of sea water. Oceanogr. Mar. Biol., 9 : 11-60.

Rogge, W

. F.; Hildem ann, L.M.; Mazurek, M.A.; and Cass, G.R. (1991). Sources of fine organic aerosol. 1. C h arbroilers a nd m eat cooking operations. Environ. Sci. Technol., 25 : 1112- 1125.

Rogge,W .F.; Mazurek, M.A.; Hildem ann, L.M.; Cass, G.R.; and Sim oneit, B.R.T. (1993a). Quantification of urban organi c aerosols at a m o lecular le vel: identification, abundance and seasonal variation. A t mos. Environ., 27A : 1309-1330.

Rogge, W

. F.; Hildem ann, L.M.; Mazurek, M.A.; Cass, G.R.; and Sim oneit, B.R.T. (1993b). Sources of fine organic aerosol. 2. N oncat alyst and catalyst-equipped autom obiles and heavy-duty diesel trucks. Environ. Sci. Technol., 27 : 636-651.

Rogge, W

. F.; Hildem ann, L.M.; Mazurek, M.A.; Cass, G.R.; and Sim oneit, B.R.T. (1993c). Sources of f

i ne organic a e rosol. 3. Ro ad dust, tire debris, and organom etallic b r ake lining dust: Roads as sources and sinks. Environ. Sci. Technol., 27 : 1892-1904.

Rogge, W

. F.; Hildem ann, L.M.; Mazurek, M.A.; Cass, G.R.; and Sim oneit, B.R.T. (1997). Sources of fine organic aerosol. 8. Boile rs burning No. 2 distillate fuel oil. Environ. Sci. Technol., 31 : 2731-2737.

Rogge, W

. F.; Hildem ann, L.M.; Mazurek, M.A.; Cass, G.R.; and Sim oneit, B.R.T. (1998). Sources of fine organic aerosol. 9. Pine, oa k, and synthetic log com bustion in residential fireplaces. E n viron. Sci. Technol., 13-22.

Scire, J.S.; S t rim a itis, D. G.; and Yam a rtino, R.J. (2000). A user' s guide for the CALPUFF dispersion model (version 5). Prepared by Earth Tech, Inc., Concord, MA.

Seam an, N.L.; Stauffer, D.R.; and Lario-Gibb s, A.M. (1995). A m u ltiscale four-dim ensional d a ta assim ilation system applied in the San Joa quin Valley during SARMAP. Part I: Modeling design and basic performance characteristics. Appl. Meteorol., 34 : 1739-1761.

Seigneur, C.; Pai, P.; Lourensz, R.S.; Hopke, P.K.; and Grosjean, D. (1997). Review of air quality m o dels for particulat e m a tter. Report No. CP015-97-1a. Prepared for Am erican Petroleum I n stitu te, W a shington, D. C., by At m o spheric & E nvironm ental Research, Inc., San Ra m on, CA.

Seinfeld, J.H.; and Pandis, S.N. (1998). Atmospheric Chemistry and Physics. John Wiley & Sons, New York.

Stauffer, D.R.; and Seam an, N.L. ( 1994). Mu ltiscale four-dim ensional data assim ilation. J. Appl. Meteorol., 33 : 416-434.

Stohl, A.; and Seibert, P. (2001). The FLEXPART particle dispersion m odel version 4.0 user guide. June 4, 2001.

52

### Strader, R.; Pandis, S.N.; and Lurm ann, F.W

. (1 998). Evaluation of sec ondary organic aerosol for m ation in winter. Prepared for Califor nia Air Resources B o ard, Sacram ento, CA, by Carnegie Mellon University, Pittsburgh, PA.

Stull, R.B. (1988). An Introduction to Boundary Layer Meteorology. Kluwer Academic Publishers, Dordrecht.

Tang, I.N.; and Munkelwitz, H.R. (19 93). Com p osition and temperature d e pendence o f the deliquescence properties of hygrosopic aerosols. Atmos. Environ., 27A : 467-473.

Watson, J.G.; Chow J.C.; Lowenthal, D.H.; Pritc hett, L.C.; Frazier, C.A.; Neuroth, G.R.; and Robbins,R. (1994a). Differences in th e carbon co mposition of source profiles for dies eland gasoline-powered vehicles. Atmos. Environ., 28 : 2493-2505.

Watson, J.G.; Chow, J.C.; Lu, Z.; Fujita, E.M.; Lowenthal, D.H.; and Lawson, D.R. ( 1994b). Che m ical mass balance source apportionm ent of PM 10 

### during the Southern California Air Quality Stud y. Aerosol Sci. Technol., 21 : 1-36.

Watson, J.G.; Chow, J.C.; Lurm ann, F.W

. ; and Musa rra, S. (1994c). Ammonium nitrate, nitric acid, and am monia equilibrium in wintertim e Phoenix, Arizona. JAWMA, 44 : 405-412.

Watson, J.G.; Chow ,J.C.; Rogers, C.F.; Dubois, D.; and Cahill, C.F. (1997). Analysis of historical P M 10 

### and PM 2. 5 

### m easurem ents in Central California. Prepared for California Air Resourc e s Board, Sa cram ento, CA, by Desert Research In stitu te, Reno , NV.

Watson, J.G.; Fujita, E.M.; Chow, J.C.; Zielin ska, B.; Richards, L.W

. ; Neff, W.D.; and Dietrich,D. (1998). Northern Front R a nge Ai r Quality Study. Final report. Prepared for Colorado State University, Fort Collins, CO, by Desert Research Institute, Reno, NV.

Watson, J.G.; DuBois, D.W

. ; DeMandel, R.; Kadu wela, A.; Magliano, K.; McDade, C.; Mueller, P.K.; Ranzieri, A.; Roth, P.M.; and Tanrikul u, S. (1998). Aerom e tric m onitoring program plan for the California R e gional PM2.5/ PM10 Air Quality Study. Report No. DRI docum ent No. 9801.1D5. Prepared by Division of At m o spheric Sciences, Desert Research In stitu te, Reno , NV.

53Source Modeling and Back Trajectory Attribution TechniquesTable 2. Puff, Visibility and Trajectory Modeling Attribution TechniquesAir Quality ModelsVisibilityModelsLagrangian Trajectory ModelsEvaluation CriteriaCALPUFFVISCREENPLUVUEIIHYSPLITRAPTADFLEXPARTChemical MechanismsDoes the modelsimulateaqueous phase chemistry?(Ifit does whatchemistrymechanismisused anddoesitinclude fog/cloud chemistry)Yes; reactions forSO4and NO3NONONONONODoes the modelsimulate gasphase chemistry?(ifit does,what chemicalmechanismisimplemented)YesNONONONONOSimulate secondaryorganicaerosols4 species modelNONONONONOInorganic PM (i.e.ions, SO4,NO3, etc)SO4, NO3NONONONONOSizedistributions (sectional ormodal)CoarseandfinemodesNONOOnlyfor depositionNOApplicable spatial scalesMicro- toregionalscaleNeighbor-hood tourban scaleNeighborhood toglobal scaleNeighborhood toglobalscaleNeighborhood toglobal scaleApplicable temporalscales(episodic orlongtermapplications)Episodic orLongtermN/AN/AEpisodicorLongtermEpisodic orLongtermEpisodic orLongtermDoes the modelhavethecapabilitytodistinguishBART sources?YESYESYESYESYESYESDoes the modelhavethecapabilitytoingestfieldmeasurements(PM,HNO3,H2O2, NH3, etc)NO; onlyasbackground valuesNONONONONO55AirQualityModels (continued)VisibilityModelsLagrangian Trajectory ModelsEvaluation CriteriaCALPUFFVISCREENPLUVUEIIHYSPLITRAPTADFLEXPARTVisibility ModelingDoes the modelsimulatebackground regional hazeNONONONONONOPoint sourcetreatment (plumerise, plume ingrid)YESYESYESYESYESYESDoes the modelhavethecapabilitytocalculate wetanddrydeposition?YESNONOYESNOYESVisibility treatment:(extinction,deciview, visualrange)Extinction(totaland forSO4, NO3,EC,OC, fine,coarse),Deciviews**NONONOInput RequirementsMeteorological datarequired(single site, gridded, numberof levels,etc)Gridded; abletorun with singlesite**Gridded(FNL,EDAS,MM5)Gridded(UseHOTMAC’sprediction)Gridded(ECMWF, MM5)Emission data required (singlestack,multiplepoint sources,gridded, etc)Multiplepoint,area, volume**Multiplepointsources, griddedinventorySingle stack ormultiplepoint sources*Allow for initialand boundaryconditions(is it requiredornot applicable)YESNONONONONOHasthe model beencomparedagainst field program data?Hasthe model been peerreviewed?YESYESYESYESYESNODoes enough data exist nowto runthe model (Does dataexistin a formatreadyfor themodel?Are currentdatabasesadequate for themodel?)Use CALMETwith existingstations orMMdataYESYESGridded met dataavailable on NOAAARL ftp site (FNL,EDAS); adaptableto readin MM5Use HOTMAC to obtainwind andturbulence data*56AirQualityModels (continued)VisibilityModelsLagrangian Trajectory ModelsEvaluation CriteriaCALPUFFVISCREENPLUVUEIIHYSPLITRAPTADFLEXPARTPracticalConsiderationsCoststo run (hardwareplatforms,filestorage,operating system)Inexpensive; PC,Windows, up to20GB (withCALMET)Inexpensive; PC,DOS,1MBInexpensive;PC, DOS,1MBInexpensive; PC,Windows, 20MBInexpensive: LinuxPC,RedhatInexpensive;Linux PC, Redhat; can becompiled onPCHave protocolsor proceduresbeen developedto run andinterpret themodel?FLAG for ClassIAQRVsFLAG for ClassIAQRVsFLAG forClass IAQRVsNONONOIsthe sourcecodeavailable?YESYESYESNOYESYESAre beginning user trainingclassesavailable?YES; byEarthTech, BEELineEPA; APTIEPA; APTINOYESNOAre user support groupsavailable?YES; onelist-serveYES; throughEPASCRAMYES; throughEPA SCRAMNOYESNOLevel ofexpertise requiredtorun andinterpret results(Level ofLinux, UNIX, PCskills required)Moderate; abletorun PC DOSprograms;knowledge ofatmosphericchemistry &physicsSimple; ableto run onPC DOS and windowsSimple; ableto run onPCDOS andWindowsSimple; ableto runon PC runningWindowsSimple torun:GUIallowsthe usertoeasilyrun the programKnowledge isneededtointerpret resultsModerate; mustcompile sourcecode forPC, Linuxor UNIX; knowledge of metinput formatsOutput visualization requiredto interpret output numbersYESNONOYES; has built invisualizationYES; has built invisualizationYESOther strengths****Applicable from buildingscaletoterrainscale.*AvailabilityEarthTechwww.src.comEPAEPANOAAAirResourceLaboratory;www.arl.noaa.gov/ss/models/hysplit.htmlYamadaScience &Art;http://www.ysasoft.comhttp://www.forst.unimuenchen.de/EXT/LST/METEO/stohl/flexpart.html*No information available atthistime57Source Modeling and Back Trajectory Attribution TechniquesTable 3. Eulerian Grid Based Modeling Attribution TechniquesAir Quality ModelsGrid ModelsEvaluation CriteriaCMAQREMSADCAMxUAM-AEROUAM-VPMURMCalGridChemical MechanismsDoes the modelsimulateaqueous phasechemistry?(If itdoes,whatchemistrymechanismisused anddoesitincludefog/cloudchemistry)35 equilibriaand99reactionsforSO4andNO31 reactionforSO41 reactionforSO435 equilibriaand99reactionsforSO4andNO3*2 reactionsfor sulfateNODoes the modelsimulate gas phasechemistry?(ifitdoes,whatchemicalmechanismisimplemented)CBM-IV (93reactions) orRADM2(158 reactions)CBM-IV(93 reactions) orRADM2 (158reactions)CB-IV with enhancedisoprene orSAPRC97SAPRC97(185 reactions)CBLCCYES (both CBM-IVand SAPRC)(about 100reactions)Simulate secondary organicaerosolsPrimaryfromemissions; secondaryfrom organicsPrimaryfromemissionsPrimaryfromemissions; secondaryfrom gas phasereactions oforganicprecursors usingyieldsSecondaryfrom gasphase reactionsoforganic precursorsusing yieldsPrimaryfromemissionsPrimaryfromemissions; secondaryfrom gas phasereactions oforganicprecursors usingproductionfractionsNOInorganic PM (i.e.ions, SO4, NO3, etc)SO4, NO3and othermaterialSO4, NO3, NH4, andother materialSO4, NO3, NH4, Cl,other ionsandmaterialsSO4, NO3, NH4, Cl,other ionsandmaterialsSO4, NO3, NH4, andother materialsSO4, NO3, NH4, Cl,other ionsandmaterialsNOSize distributions(sectional or modal)Lognormal;threemodes: Aitken,AccumulationandcoasePM2.5fraction,coarsemodeDiscrete bins, userspecified upto 10Discrete bins, userspecified upto 10Lognormal bins; userspecifiedDiscrete bins; userspecifiedNOApplicable spatial scalesMesoscaleMesoscaleMesoscaleUrban scaleUrban scaleMesoscaleUrban to RegionalApplicabletemporal scales (episodic orlongtermapplications)EpisodicLongtermEpisodicEpisodicEpisodicEpisodicEpisodicDoesthe modelhavethecapabilitytodistinguish BARTsources?YES; using plume ingridNOYESNONONONO58Air Quality Models (continued)Grid ModelsEvaluation CriteriaCMAQREMSADCAMxUAM-AEROUAM-VPMURMCalGridChemical Mechanisms(continued)Does the modelhavethe capabilitytoingestfieldmeasurements(PM,HNO3,H2O2,NH3,etc)YES; as initialandboundaryconditionsUses default profilesYES; as initialandboundaryconditionsYES; as initialandboundaryconditionsYES; as initialandboundaryconditionsYES; as initialandboundaryconditionsYES; as initialandboundaryconditionsVisibility ModelingDoes the modelsimulate background regionalhazeYESYESYESYES(withprocessing)YESYESNOPoint sourcetreatment (plumerise, plume ingrid)Plume in gridNOPlume in gridNONONONODoesthe modelhavethecapabilitytocalculate wet and drydeposition?YESYESYESYESYESYESYESVisibility treatment:(extinction,deciview,visual range)Extinction(totalandfor SO4, NO3, EC,OC, fine,coarse),DeciviewsExtinction(totalandfor SO4, NO3, EC,OC, fine,coarse),DeciviewsNOYES (withprocessing)**NOInput RequirementsMeteorological datarequired (singlesite,gridded, numberof levels,etc)GriddedGriddedGriddedGriddedGriddedGriddedGriddedCALMETdateEmission datarequired (singlestack,multiplepoint sources, gridded, etc)GriddedGriddedGriddedGriddedGriddedGriddedGriddedAllow for initialand boundaryconditions (isit requiredornot applicable)YESYESYESYESYESYESYESHasthe model beencomparedagainst fieldprogram data?Has the model been peerreviewed?YESYESYESYESYESYESYESDoes enough data exist nowto run the model(Does data existin a format readyfor themodel?Arecurrent databasesadequateforthe model?)Extensive need fordetailedemissionsand meteorologicalfieldsExtensive need fordetailedemissionsand meteorologicalfieldsExtensive need fordetailedemissionsand meteorologicalfieldsExtensive need fordetailedemissionsand meteorologicalfieldsExtensive need fordetailedemissionsand meteorologicalfields*Extensive needfordetailedemissionsand meteorologicalfields59AirQualityModels (continued)Grid ModelsEvaluation CriteriaCMAQREMSADCAMxUAM-AEROUAM-VPMURMCalGridPracticalConsiderationsCoststo run (hardware platforms,filestorage,operating system)Can be runinexpensively;LinuxPC, up to1TB(annual runs)Can be runinexpensive; LinuxPCCan be runinexpensively;LinuxPCCan be runinexpensively;LinuxPCCan be runinexpensively;LinuxPCCan be runinexpensively;LinuxPCCan be runinexpensively;LinuxPCHas a protocol orprocedures been developedto runthe model?NO; but RPOs haveregional hazeprotocolsNO; but RPOs haveregional hazeprotocolsNONONONONOIsthe sourcecodeavailable?YES*YESYESYESYESYESAre beginning user trainingclasses available?YES; throughEPAand RPOsNOYES; through SAIand RPOsNONONONOAre user support groups available?YES; throughEPAand RPOsNONONONONONOLevel ofexpertise requiredtorunandinterpret results(LevelofLinux,UNIX, PCskills required)Considerableexpertise inUNIX orLinux; knowledge ofatmosphericchemistry &physics*Moderate toextensiveModeratetoextensive**ModerateOutput visualization requiredtointerpretoutput numbersYES; use PAVEYES; usePAVEYESYESYESYESYESAvailabilityEPA; Sharon LeDuc919-541-1335SAI; Sharon Douglas415-507-7108ENVIRON; RalphMorris 415-899-0700SAI; Sharon Douglas415-507-7108SAI; Sharon Douglas415-507-7108Georgia Tech; TedRussel, Talat OdmanCalifornia AirResourcesBoard*No information available atthistime60Table 4. Meteorological Modeling Attribution TechniquesDiagnostic ModelsMesoscale Prognostic ModelsEvaluation CriteriaCALMETDiagnostic WindModelRAMSMM5Eta*ARPSHOTMACApplicable spatial scalesUrban toregionalscaleUrban toregionalscaleUrban to globalscaleUrban to globalscaleUrban to globalscaleUrban to globalscaleUrban tomesoscaleApplicable temporalscalesHourlytoannualHourlytoannualHourlytoannualHourlytoannualHourlyto annualHourlytoannualHourlytoannualDoes enough data exist inorganizationnow to runthe model?Aretheexistingmonitoringnetworks adequate withinthe domain?Depends onareaDepends onareaDependsonareaDepends onareaDepends onareaDependsonareaDependsonareaFor the prognosticmodels: Capable ofFDDA?N/AN/AYesYesYesYesYesFor the prognosticmodels: Are filesavailable (archived) fromreal-time?N/AN/ANOAA is runningthe model fortheeast coastSeveral federalagenciesandregionalconsortiums arerunning MM5NOAA is runningthe Etamodel andfieldsavailablethrough NCEP ftpsiteIt can beinitializedusingNCEPanalysesfilesaswellasindividualobservationsNoData storage/archivalrequirements forsimulation ofepisodicand annualeventsDepends onmodeling domain,grid size, number ofspeciesand lengthof simulationDepends onmodeling domain,grid size, numberof speciesandlengthofsimulationDepends onmodeling domain,grid size, numberof speciesandlengthofsimulationDepends onmodeling domain,grid size, numberof speciesandlengthofsimulationDepends onmodeling domain,grid size, numberof speciesandlengthofsimulationDepends onmodeling domain,grid size, numberof speciesandlengthofsimulationDepends onmodeling domain,grid size, numberof speciesandlengthofsimulationSimulateclouds/precipitationfields?Atwhattimeintervals?NoNoYes – minutestodaysYes – minutestodaysYes – minutestodaysYes – minutestodaysYes – minutestodaysHasthe model beencompared againstfieldprogramdata?Hasthemodel beenpeerreviewed?YesYesYesYesYesYesYes61Meteorological Modeling Attribution Techniques (continued)Diagnostic ModelsMesoscale Prognostic ModelsEvaluation CriteriaCALMETDiagnostic WindModelRAMSMM5Eta*ARPSHOTMACToolsavailable tovisualize outputfields?What operatingsystems?Yes – Unix, Linux,WindowsYes – Unix,Linux, WindowsYes – Unix, LinuxYes – Unix, LinuxYes – Unix, LinuxYes – Unix, LinuxYes – Built-inGUI; Unix,Linux,WindowsAre user groups,listservers availablewhenproblems arise?YesYesYesYesNoYesYesCostto run(hardware,software)PC Windows, PCLinux; Free sourcecodePC Linux, UNIX;FreePC Linux; licensedsource codePC Linux, UNIX;Free sourcecodePC Linux, UNIX;Free sourcecodePC Linux, UNIX;Free sourcecodePC Linux; licensedsource codeLevel ofexpertiserequiredtorunandinterpret results(LevelofLinux, UNIX, PC skillsrequired)ModerateModerateHighHighHighHighHighAvailability ofusertrainingYesYesYesYesNoYesYesIsthe sourcecodeavailable?YesYesYesYesNoYesYesHas a protocol orproceduresbeendeveloped torunthemodel?YesYesYesYesYesYesYesStrengthsRelativelyeasytouse; little observeddata neededRelativelyeasytouse; little observeddata neededDetailed 3-D,complex flowintimeDetailed 3-D,complex flowintimeDetailed 3-D,complex flowintimeDetailed 3-D,complex flowintimeDetailed 3-D,complex flowintimeWeaknesses/LimitationsParameterizationdepended;maynotcapturevariousflowsParameterizationdepended;maynotcapturevariousflowsLargecomputertime; timeconsuming todebugLargecomputertime; timeconsuming todebugLargecomputertime; timeconsuming todebugLargecomputertime; timeconsuming todebugNo realtimedatainitialization* WhiletheEtaisnot considereda mesoscale model,ithasbeenused to simulatemeteorology downto 10kmgridscales.The workstationEtaisavailable fromNOAA and used experimentallybysome NWS offices.* No information availableatthistime62

## C. Observational Modeling Techniques

Introductio n

Observation a l or recep to r m odeling refers to a g r oup of analysis techniqu es in which monitoring data co llected at or in the region of a recep tor are analyzed in various way s in orde r to infer inform ation about the pollutants and th e sources of the polluta nts causing visibility im pair m e nt.

These types of m odels often are used as the fi rst technique for source apportionm ent in order to get an initial understanding of the source-receptor relationships in a region. They are also used to verify or reconcile determ inistic m odels, a nd to aid in planning intensive m onitoring studies.

Results of observationa l m odels can eithe r be qu antitative or qualitative. Quantita tive results

are es tim ates of the fractions of a m e asured species that can b e attribu t ed to a single so urce or attributed among several sources or source areas

. Qualitative results in clu d e such inform ation as the wind directions and other m e teorologica l conditions m o st associated with high concentrations, or inferences about probable source types based on the relationships between trace elem ents at a single s ite, or inform ation about source areas based on the spatial and
tem poral patterns in the concentrations of a single species. Often seve ral observational m odels are used together to form hypotheses about the important source areas a nd source types affecting the concen trations at a receptor.

Advantages of receptor models are that they are generally qu ick and in ex pensive to run and requir e re latively little in put data. Disadvantages include the necessity of employing simplifying

assum p tions such as linear relationships and ofte n the results are lim ited to averages over long periods of tim e or large spatial areas. Subjective user judgm ent is required to choose appropriate input data and/or in terp ret th e resu lts of m a ny receptor m odels. As an example, suppose the UNMIX m o del data located a source associated w ith high concentrations of Br, K, elem ental carbon, and organic carbon, and anothe r source associated with high Se and S. It is the judgm ent of the m odel e r regarding the re lationship of the individual spec ies to a spe c if ic sour ce that determ ines that first source is “sm oke” a nd the second is “coal-fired power plants.”

Receptor m odels cou l d potentially b e grouped in several different ways, based on their different attributes. Here they are somewhat ar bitrarily put into four categ ories, with each catego r y req u iring increm entally m o re particu l at e data at the recep tor: 1 ) back-trajectory analyses ; 2) analyses of interspe cies relationships; 3) analys es of spatial an d tem poral patterns; and 4) analyses that require a un ique trac er. Som e m odels that f a ll into eac h catego ry a r e listed below:

Category 1. Back-Trajectory Analyses

a. Residence T i m e Analyses including re sidence tim e, source contribution function, conditional probability, and so forth. These give qualitative info r m ation about source areas and transport patterns.

63

### b. Trajectory Mass Balance – Regression of reside nce tim e of back trajec tories in se le cted

source areas agains t con centration s yi elding quantitative so urce attributions.

Category 2. Analyses of Interspecies Relationships

a. Chem ical M a ss Balance (CMB) - Quantitati ve source attributions are ob tained by a weighted regression of known s ource profiles against m easured concentrations of several species. b. UNMIX – By looking for “edges” in th e relationships between species, U N MIX estim ates bo th the sou r ce profiles and th e quantitative sou r ce contribu tions from each

source.

c. Positive Matrix Fac t oriza tion (PMF) – PMF, like UNMIX, uses the r e la tio nships betw een species to es tim ate the n u m b er and com position of the sources and the quantitative source contributions. d. Enrichm e nt Factors (EF) – The “enrichm e nt” of certain ratio s of trace elem ents is used to qualitatively infer source types im pacting a recep tor.

Category 3. Analyses of Spati al and Temporal Patterns

a. Em pirical O r thogonal Function Analysis (E OF) – Analysis of spatial and tem poral patte rns lead ing to qua litative inf o rmation about locations of dom i nant source areas, frequency and tim ing of source im pacts and m e teorological conditions associated with them

. b. Receptor M odel Applie d to Patterns in Space (R MAPS) – W ith add ition a l assum p tions applied to E O Fs, quantitative s ource attributions are es tim ated.

Category 4. Tracer Analyses

a. Tracer Mass Balance Regression (T MBR) – Tracer concentrations, pos sibly weighted by other facto r s , are regress e d agains t concentra tion s of the spec ies of inte res t to giv e a quantitative estim ate of the contribution from the source th at e m itted the tracer. b. Differential Mass Balan ce (DMB) - The differen tia l ra tios of trac er to po llutant be twee n source and recepto r are adjusted b a sed on sim p le chem istry and m e teorology to give an estim ate of the contribution of th e tracer source to the recepto r.

c. Tracer-Aero s ol Gradien t Interp retive Technique (TAGIT) – By com p aring the ratios of tracer to concentration of in terest at “background” sites to the ratios at tracer-affected sites, a quan titativ e attr ibution of the trac er sou r c e to the r eceptor is estimated.

Following are brief des c rip tions of each of thes e m odels and a few references giv i ng further details and exam ples of t h eir use.

1a. Qualitative Back Trajector y Residence Time Analyses

There are several m e thods of statistically analyzing the re lationships between where air

m a sses arrived from and the concentrations m eas ured at a receptor. Th ese include, but are not lim ited to: 1 ) where was air m o st like l y to a rriv e f r om when concentr ation s are high ; 2 ) if air arriv e d f r om a given a r ea , what is th e probability that the conc entra tion a t the recep t or was high when the air m a ss arriv e d there; 3) w h at is the m ean (or m e dian or m a xi m u m or distribution) of

64

### concentratio ns at th e receptor when air m a sses arrived from a given area. Selected References: Ashbaugh et al. (1985), Gebhart et al. (2001), Poirot and W i s h inski (1986).

Data Needed : A tim e series of concentrations of the species of interest. One or m o re back trajectories of three to five da ys duration corresponding to each c oncentration. Back trajectories can be calcu l ated by any of several m e thods including ATAD, Hysplit, the CAPITA Monte Carlo Model, as well as others. Standard National W eather Service upper air data can be used as input, though m o re detailed m e te orological data can be input if available. Dispersion can be included in som e of these m odels.

Model Assumptions : Errors in trajectory placem ent ar e random and uncorrelated. Variations in deposition, chem istry, em issions, and so forth, have less influence on m easured concentration s on average than variatio ns in tr anspo r t direc tions.

Biggest Potential Problem s: Results of these types of anal yses are qualitative rath er th an quantitative. Results are more st atistically robust when averaged over long tim e periods, usually

a m i ni m u m of one season and preferably several y ears. Nearby sources cannot be resolved. User judgm ent is required to choose trajectories of an appropriate type, height, and length and also to choose appropriate defin itions of “h igh” con centrations. Some concentrations that vary seasonally m a y have all “high” concentra tions in a single season, necessitating som e

com p ensation in the an alysis. Model results are probably m o re appropriate for species such as particulate s u lfate that are rela tively uniform ove r large spatial sc ales, rather than, for exam ple, particulate nitrate, which is m o re volatile and s e e m s to be m o re re lated to local source s than long-range transport.

1b. TrMB (Trajectory Mass Balance)

This is a m u ltip le linear regres sion o f the fre quency of occurrence of trajectory endpo ints in each of several sou r ce areas against the correspo ndi ng concentrations at the recep tor. The result is the average attribu tion of a single species am ong up to about 25 source areas over a long tim e, for exam ple, one season or year, or several year s. Selected ref e rences: Gebhart and Malm (1989), Stohl (1998).

Data Needed : Tim e series of concentra tions of the pollutant of in teres t at a single site. One

or m o re back trajecto r ies associated with each co ncentration. Input data for these are u pper air winds, tem p eratu r es, and m o isture ov er a large ar ea. Often data are obtained from the standard National W eather Service observa tions, but other data such as higher resolution wind fields, wind profiler data specif i c to a given study, can also be used if available. Em ission data can be used if available, but m u st vary in tim e to be useful. Si m p le chem istry and/or deposition can be used if data are availab l e. The user d e fines the size and locations of the source areas to be considered.

Model Assumptions : Average contributions of each sour c e area can b e written as a linear

com b ination of the contributions from severa l source areas. Average chem istry and deposition are adequ a te to explain average sou r ce contributio ns. Errors in back traj ectories are ran d om and

norm a lly distributed.

65

### Biggest Potential Problem s: No attribution to single sources—only to source areas. Attribu tions must be aver ag ed over long tim e periods. Nearby sources cannot be m ode led accurately. Subjectivity in choosi ng source areas. Violation o f a ssum p tions of linear chem istry.

2a. Chemical Mass Balance (CMB)

CMB is a multip le linea r regres sion o f m easured concentr ation s agains t kn own source profiles. It is used for the attribution of all m easured chem ical species am ong several sources for each concen tration m easurem ent period for a sing le m onitorin g site. Reg r essions a r e weighted by the uncertainties in both the source profiles and the concentrations. Selected References: W a tson et al. (1984 and 2001).

Data Needed : Concentrations and measurem ent uncertain ties of both the chem ical species of interest and of as m a ny trace elem ents as possib l e are necessa ry for each tim e period and location for which attributions are desi red. IMPROVE data can be used. A source profile is needed for each source. These are the relativ e amounts of each em itted chem ical species and th e uncertainties in thes e values.

Model Assumptions : Compositions of source em issions ar e constant over the period of

am bient and source sam p ling. Chemical species do not react with each o t her, for example, they add linearly. All sources with a poten tial for significantly con t ribut ing to the recep tor have been identif i ed an d have had their em issio n s chara c te rized. The sou r ces’ com p osition s ar e linearly independen t of each oth e r. The number of sources or source catego r ies is less th an or equal to the

num b er of chem ical species. Measurem ent un certainties are random , unc orrelated and norm a lly distributed.

Biggest Potential Problem s: The m o del cannot directly appor tion secondary species such as sulfates, nitrates, and secondary organics. There are som e workar ounds for this. The usual tactic is to apportion these species between the known prim ary sources and a source designated as “secondary particles.” It is also possible to use “fract ionated” or “aged” source profiles where an
attem p t is made to pr e-d e term ine the chem ical processes that occurr ed between source and
recep tor and then adju st the source p r ofile acco rd ingly. Obtaining all n ecessary sou r ce profiles can be difficult. In som e studies, other rece ptor m odels have estim ated sou r ce profiles.

2b. UNMIX

For a selection of m easured species, UNMIX uses singular value decom position with additional non-negativity constrai nts to estim a te the num ber of sources, the source compositions, and the source contributions to each sam p le at a single m onitoring site. U N MIX attempts to find the “edge s” in the rela tio nshi ps betw een species and relates these to sou r ces. Selected References: Henry (1997a, 1999), Lewis et al. (1998).

Data Needed : A tim e series of concentrations of se veral species m easured at a s i ngle site. IMPROVE data can be used.

66

### Model Assumptions : Concentrations are linear com b inations of an unknown num b er of sources of u nknown composition. Contribution s fr om sources are pos itive. Source com positions
are app r oxim a tely constant in tim e. For each sou r ce th ere a r e som e sam p l e s that contain little or no contribution from tha t source.

Biggest Potential Problem s : A maximum of seven sources ca n be identified. There is som e subjectivity in choosing fitting sp ecies, num ber of sources, h o w to deal with m i ssing or below detection lim it values, and which tim e periods a nd species should be analyzed together. Sources of secondary species will prob ably v i olate the as sum p tion of constan t sou r ce com position. This

can cause m u ltip le sou r ces to be iden tified for a s i ngle phys ical source that im pacts the recep t or under differing conditions. Supplem e n tal analysis m a y be required to deconvolute these.

2c

. Positive Matrix Factoriz ation (PMF)

PMF uses an iterative weighted least squares m e thod to deco mpose a time-by-species m a trix to estim a te the num ber and com position of the so urces and th e contributio ns of each source to each m easured species. It will also c a l cula te e rror estim ates for these v a lue s . Selec t ed References: Paatero and Tappe r (1994), Paatero (1997); Xie et al. (1999).

Data Needed : A tim e series of conce n tra tions an d their uncer tain ties f o r s e vera l spec ies at a single m onitoring location. IMPROVE data can be used.

Model Assumptions : Concentrations are linear com b inations of an unknown num b er of sources of u nknown composition. Contribution s fr om sources are pos itive. Source com positions are approxim a tely constant in tim e.

Biggest Potential Problem s: Correlations in de tec tion lim its or uncer tain ties as well as in concentratio ns can inf l ue nce the results. For exam ple, PMF may detec t po sitiv e cor r elations between spe c ies e ithe r d

u e to sourc e activ ity (des irab le) o r measurem ent protoco l cha nges (undesirable).

2d. Enrichment Facto r s (EF)

The differences in ratios of elem ental con centrations between a reference sam p le and a

m easured sample are used to determ ine how sour ces m a y have “enriched” the concentrations of certain species. Som e exam ples inclu d e: high A l/Ca has been linked to Saharan dust, high Br/Pb

m a y indicate lead is linked to autos rather than industry, high Se is linke d to coal burning, heavy

m e tals are linked to sm elting, V and Ni are linked to residual oil com bustion. Selected References: Lawson and W i nchester (1979), Pare kh et al. (1989), Perru (1997), Roshid and Griffiths (1993).

Data Needed : Tim e series of concen trations of tr ace elem ents and the sp ecies of in te rest. Som e historical inform ation about the “standard” crusta l, sea salt, or other ratios for a region.

Model Assumptions : Ele m ental ratio s depend m o stly on en richm e nt of trace elem ents by a source and have less dependence on m e teor ology. The reference ratios are constant.

67

### Biggest Potential Problem s: Attributions are generally to so urce areas, not to single sources.

3a. Empirical Orthogonal Function Analysis (EOF)

A f e w (typically two to s i x) spa tia l p a tte rns th at explain m o st of the c ovariance in the s p atia l and tem poral patterns of a m easured species are o b tained by singular value decom position. Associations between the spatial patterns and source areas and/or tr ansport of air pollutants into the study area can often be infe rred, but are qualitative. The or iginal data m a trix can be approxim a tely reconstructed by linearly recom b in ing thes e few patterns. Selected Reference s : Gebhart and Malm (1997), Henry et al. (1991), Malm et al. ( 1990), Malm and Gebhart (1997).

Data Needed : Measurem ents of a single air pollutant of interest at sev e ral sites for several tim e periods. Typically used are c oncentrations m easured at fifteen to f o rty sites f o r th irty o r more tim e periods. There m u st be more tim e peri ods than sites. Data from special studies are often analyzed in this way.

Model Assumptions : On ly a f e w spatial pa tte rns a r e requ ir ed to explain a large m a jority of the covariance in the spa tial and tem poral patterns. These pa tterns have a physical m e aning that can be inferred, such as transport of em issions from a source into the study area or local stagnation.

Biggest Potential Problem s : Source attributions are qualit ative, not quantitative and inte rpre tatio n of the spatial pa tte rns is subjec tiv e. The m odel requires a si te by tim e matr ix with

no m i ssing values, so som e method of elim inating or filling in both m i ssing and below detection lim it values is neces sary.

3b. Receptor Model Applied to Patterns in Spa ce (RMAPS)

Determ ines the average attribution o f a single sp ecies am ong a few source areas by decom posing the tim e by site m a trix of concentr ations into a source m a trix and a time weighting

m a trix. Sim i lar to UNMIX, the edges in the s catterplots between s ources and non-negativity requirem e nts are used to constrain the identifi cation of sources. Selected References: Henry (1997 b, c, d), W h ite (1999).

Data Needed : Tim e series of concentrati ons of th e pollu tant o f interes t at severa l sites within a region. The m odel previously has been used in special studies such as Project MOHAVE and PREVENT where there are fifteen to forty sites within a one or two state region collecting data daily for several weeks or m onths.

Model Assumptions : Av erage con t ributions of each sourc e area can b e written as a n onnegativ e lin ear com b ination of the m a jor principal com ponents of the d a ta. The spa t ial s cale of the pollutan t is la rge co mpared to th e spacing of the sam p ling sites.

Biggest Potential Problem s : If the second m a jor assum p tion is violated, the concentrations of the pollutant at each s ite will have little correlation with the other s ites; therefore the m odel would not apply because it relies on the comm on variations am ong sites.

68

### 4a. Tracer Mass Balance Regress i on (TMBR) also called Multiple Linear Regression (MLR) on Marker Species

Estim ates th e attribu tion of the aeros ol specie s of interest by a sour ce or source type, which

em itted or e m its a unique tra cer. Un certainty esti m a tes are also genera ted if included in the regression. The m odel is a regressi on of the tracer, possibly weight ed by other factors against the species of interest. Selected Refe rences: Malm et al. (1989 a, b, c).

Data Needed : Tim e series of a m bient concentrations and the i r uncer tain ties f o r the ae rosol species being apportioned and also the tra cer species.

Model Assumptions : Th e tracer(s) are uniquely em itted by non-overlappin g groups of sources. Sou r ce em ission s are cons tant over the p e riod of am bient s a m p ling. Depositio n and conversion are constant f o r all sam p ling pe riods and can be estim ated by first-order approxim a tions. In the WHITEX a pplication, sulfate oxidation rates were assum e d to be related to RH, where RH was a surrogate for tim e the ai r m a ss spent in clouds. Measurem ent errors are random , unc orrelated, and norm a lly distributed.

Biggest Potential Problem s : Tracer concentration s are not of ten available. Source profiles, deposition, and conversion all vary in tim e and space.

4b. Differen tial Mass Balance (DMB)

DMB estimates the fraction of a spec ies of inte res t attribu t able to a single source that can be tagged with a unique tracer. The ratio of m easured tracer to m easured sulf ate or n itr a t e is

assum e d to be related to the fr actional contribution of the traced source. The ratio is adjusted based on the estim ated difference between the rati o at the sou r ce to the ratio at the receptor. Travel tim es between the source and recep tor ar e estim ated ba sed on winds, and then b y using sim p le estimates of dispersion, deposition and ox id ation, the tracer to seco ndary species ratio is adjusted. Selected Refe rences: Malm (1989b, c).

Data Needed : Tim e series of tracer concentratio ns and concentrations and em ission rates of the spec ies o f interes t an d its pr ecurs ors, f o r ex ample, sulfur dioxide a nd sulfate. Estim ates of wind speed and direction, m i xing height s, deposition and oxidation rates.

Model Assumptions : W i nd direction does not change dur ing transport time. The rates for deposition and conversion are firs t-order and in varian t in sp ace a nd tim e along the transport path between the source and the recep tor. The ratio of the em ission rates for the species of interes t or its parent species and the tracer is known.

Biggest Potential Problem s : Si m p le chem istry and m e te orology m a y not be adequate, especially for long transport tim e s, complex terr ain, and/or changing chem ical regimes. Tracer concentrations unique to a singl e sou r ce are often not available. The fraction of attribu t able concentration m a y only be calcula ble to within a range based on the reasonable ranges of rate coefficients.

69

### 4c. Tracer

- Aerosol Gr adient Inter p retive Tec hnique (TAGIT)

Results are the attribution of prim ary or s econdary species associated with the source “tagged” by a tracer release. TAGIT com putes attributions on a sam p le period-by-sam p le period basis. For each sam p le period, background concentrati on of the species of interest is determ ined by averag in g the concen trations of th e speci es at nearby sites th at do not have tracer concentrations and are significantly above background. These sites are presum ed to be unaffected by the tracer-tagged source and t hus represent the av erage background. This background for each sample period is then subtract ed from the concentration of the species of interest at impacted receptor s ites for corr esponding sam p le periods. The difference is the concentration attributable to th e tagged source. G r een (2001), K uhns et al. (1999), Pitchford et al. (2000).

Data Needed : Concentrations of a unique tracer from a source of interest and sim u ltaneous concentrations of a pollutant of in terest at several sites in a region.

Model Assumptions : There is no impact from the tagged so u r ce if the tra c er conc entr ation is less than the level considered to be “s ignificantly” above it s’ background. Background concentrations of the species of interest do not vary system atically in space.

Biggest Potential Problem s : Assum i ng no im pac t from the tagged source when tracer is not statistically above background can lead to an und erestim a tion of attribu tion. Measured tracer concentrations often have la rg e unce r ta inties. So m e sam p lin g periods will have a negative concentratio n attributed to the tagg ed source.

References :

Ashbaugh, Lowell L., W illiam C. Malm , W illy Z. Sadeh (1985) “A Residence T i me Probability Analysis of Sulfur Concentrati ons at Grand Canyon National Park,” Atmospheric Environment , 19, 1263-1270.

Gebhart, Kristi A., Sonia A. Kreidenweiss, and W illiam C. Malm (2001) “Back-Trajectory Analyses of Fine Particu l ate Matter Measured at Big Bend National Pa rk in the His t or ical Database and the 1996 Scoping Study” Science of the Total E n vironment , 276, 185-204.

Gebhart, Kristi A. and William C. Ma lm (1989) “Source Apportionm ent of Particulate Sulfate Concentrations at Three National Parks in th e Eastern United States, ” in Transactions of the A&WMA/EPA Specialty Conference- Visibility and Fine Particles , Estes Park, CO, Oct. 15-19, 1989, pp. 898-913, C.V. Mathai, Ed.

Gebhart, Kristi A. and William C. Ma lm (1997) “S patial and Tem poral Patterns in Particle Data Measured during the MOHAVE Study,” J. of the Air & Waste Managem e nt Assoc. , 47, 119-135

Green, Mark, 2001 (Inform al paper, BRAVO)

70

### Henry, R.S. (1997a) “History and fu ndam e ntals of m u ltivariate air quality recep t or models,” Chemometrics and Intelligent Laboratory Systems , 37 , 37-42.

Henry, R.C. (1997b) “Receptor Mod e l Applied to Patterns in S p ace (RMAPS) Part I – Model Description” JA&WMA , 47, 216-219.

Henry, R.C. (1997c) “Receptor Mod e l Applied to Patterns in S p ace (RMAPS) Part II – Apportionment of Airborne Particul ate Sulfur from Project MOHAVE” JA&WMA , 47, 220-225.

Henry, R.C. (1997d) “Receptor Mod e l Applied to Patterns in S p ace (RMAPS) Part III – Apportionment of Airborne Particulat e Sulfur W e stern W a shington State” JA&WMA , 47, 226-230.

Henry, R.C. (1999) “Comparing a new algorithm with the classic m e thods for estim ating the

num b er of factors,” Chemometrics a nd Intellig en t Laboratory Systems , 48, 91-97.

Lewis, C.W

. , R.C. Henry, and J.H. Shreffler (1998) “An Exploratory L ook at Hydrocarbon Data from the Photochem i cal Assessm en t Monitoring Stations Network” J. Air & Waste Management Assoc . 48, 71-76.

Henry, Ronald C., Yi-Jin W a ng, and Kristi A. Gebhart (1991) “The Relationship Between Em pirical O r thogonal Functions an d Sources of Air Pollution,” Atmospheric Environment , 25A, 503-509.

Kuhns et al. (1999)

Lawson, D.R. and J.W

. W i nchest er (1979) “A Standard crusta l aerosol as a reference for elem ental en richm e nt factors,” A t mospheric Environment , 13, 517-523.

Malm , W illiam C, Hari K. Iyer, and Kristi Gebh art (1989 a) “Application of Tracer M a ss Balance Regression to W H ITEX Data” in Trans actions of the A&W M A/EPA Spec ialty Conference: Visibility and Fine Particles, Estes Park, CO, Oct. 15-19, 1989, pp. 806-818, C.V. Mathai, Ed.

Malm , W illiam C., Hari K. Iyer, Joh n W a tson, and Douglas A. Latim er (1989b) “Survey of a Variety of Recepto r Mod e ling Techn i ques,” Trans action s of the A& W M A/EPA Specialty Conference-Visibility & Fi ne Particles, Estes Park, CO, Oct. 15-19, 1989, pp. 781-805, C.V. Mathai, Ed.

Malm , W illiam

, Kristi G e bhart, Dou g las Latim e r, Thom as Cahill, Robe rt Eldred, Rog e r Pie l ke, Roger Stocker, and John Watson (1989) “Natio nal Park Service Report On the W i nter Haze Inten s ive Tracer Experim e nt” Nationa l Park Service, A i r Quality Division, Research Branch, Fort C o llins, CO, Dec. 4, 1989

71

### Malm , W illiam C. and Kristi A. Gebhart (1997 ) “Source app o rtionm ent of sulfur and light extinction using receptor m odeling techniques,” Journal of the Air & Waste Management Association , 47, 250-258.

Malm , W illiam C., Kristi A. Gebhart, and Ronald C. Henry (1990) “An In vestig ation of the Dom i nant Source Regions of Fine Sulfur in th e Western United States an d their Areas of Influence,” Atmospheric Environment , 24A, 3047-3060.

Paatero, P. (1997) “Least squares formulati on of robust non-negative factor analysis,” Chemometrics and Intelligent Laboratory Systems , 37, 15-35.

Paatero, P. and U. Tapper (1994) “Po s itiv e Matrix Factorization – a Nonnegativ e Factor Model with Optim al Utiliza tion of Error-Estim ates of Data Values,” E n vironmetr i cs , 5, 111-126.

Parekh, P.P., B. Ghauri, and L. Husain (1989) “Identification of Pollution Sources of Anom alously Enriched Elem ents,” Atmospheric Environment , 23, 1435-1442.

Perru, K.D., T.A. Cahill, R.A. Eldred, and D.D. Dutcher (1997 ) “Long-ran g e Transport of North African dust to the eastern United States,” J. Geophys. Res ., 102, 11,225-11,238.

Pitchford, Marc, Mark Green, Ham p den Kuhns, and R obert J. Farber (2000) “Characterization of Regional Transport and Dispersion Using Project MOHAVE Tracer Data” J. Air & Waste Manage. Assoc. 50: 733-745. (This is not exactly TAGIT, but the 1999 reference

m a y be a conference paper.)

Poirot, Richard L. and Paul R. W i shinski ( 1986) “Visibility, Sulfat e and Air Mass history Associated with the Su mmertim e Aerosol in Northern Vermont,” Atmospheric Environment , 20, 1457-1469.

Roshid, M. and R.F. Griffiths (1993) “Am b ient K, S, and Si in fine and coarse aerosols of Kuala Lum pur, Malaysia,” Journal of Aerosol Science , 24, 597-601.

Stohl, A. (1998) “Com putation, Accuracy and A pplications of Traject ories - A Review and Bibliography,” Atmospheric Environ m ent , 32, 947-966.

Watson, John G., John A. Cooper, and Jam e s J. Huntzicker (1984) “The E ffective Variance Weighting for Least Squares Calculations Appl ie d to the M a s s Balance R ecepto r Mod e l,” Atmospheric Environment , 18, 1347-1355.

Watson, John G., Judith C. Chow and Eric M. Fujita (2001) “Review of volatile organic

com pound s ource apportionm ent by chem ical m a ss balance” Atmospheric Environment

, 35, 1567-1584.

White, W a rren H. (1999) “Phantom Spatial Factors: An Example,” J. o f

th e Air & Was t e Management Assoc. , 49, 345-349.

72

### Xie, Yu-Long, Philip K. Hopke, Pentti Paatero, L e onard A. Barrie, and Sh ao-Meng Li (1999) “Identification of Source Natu re and Seasonal Variations of Arctic Aerosol by Positive Matrix Factorization,” J. of the Atmospheric Sciences , 56, 249-260.

73

### 74Table 5. Observational Modeling TechniquesAnalyses of Back TrajectoriesCriteriaResidenceTime&Source ContributionFunctionConditionalProbabilityConcentrationStatistics byAir MassHistory (Mean,Max,Median)ClusterAnalysisHit–No HitTrajectory Mass BalanceQuantitative Source Attribution?NoNoNoNoNoYesNumberof sources that can bedistinguished?Typicallyonly about10 orfewertransportpatterns aredistinguishableMaximumof 10-151/grid cell,typically50x50 (2500),thoughusuallyonlyabout 5-20transport patterns aredistinguishable2-15120-30maxAveraging TimeofResult?Weeks toyearsWeeksto yearsWeeksto yearsWeeksto yearsDaily,possiblyhourlyMonths to yearsPrevious use at Class I Areas?(SeeText for References)YesYesYesYesYesYesMagnitude ofimpacts?NoNoYesNoNoYesFrequency ofimpacts?YesNoNoYesYesYesDuration ofimpacts?YesNoNoYesYesYesTimeof Day of impacts?Depends on particledataDepends on particledataDepends on particledataDepends onparticle dataYesDepends on particle dataTimeof Year of impacts?YesYesYesYesYesYesAppropriate forwhat source-receptordistances?Regional ScaleRegional ScaleRegional ScaleRegional ScaleRegionalScaleRegional ScaleAttribution of SecondarySpecies?YesYesYesYesYesYesCost torun?MinimalMinimalMinimalMinimalMinimalMinimalCode Available?NoNoNoNoNoNoEquations and/oralgorithmsavailable?YesYesYesYesNoneneededYesComputerHardware NeededPCPCPCPCPCPCAdditional softwarenecessary?Anyprogramminglanguage orstatisticalpackage and graphicsand/ormappingsoftware that allowsoverlayof data onamapAnyprogramminglanguage orstatistical packageand graphics and/ormapping softwarethat allows overlayof data on amapAnyprogramminglanguage orstatisticalpackage and graphicsand/ormappingsoftware that allowsoverlayof data onamapAnyprogramminglanguage orstatisticalpackage andgraphics and/ormappingsoftware thatallows overlayof data on amapGraphing ormappingsoftware thatallowsoverlayofdata on amapAnyprogramminglanguage orstatistical packageand graphicsand/ormapping softwarethatallows overlay of data on amapEPA Approved Model?NoNoNoNoNoNo75Observational Modeling Techniques(continued)Analyses of inter-species relationshipsAnalyses of Spatial and TemporalPatternsCriteriaCMBPMFUNMIXFactorAnalysisEOFRMAPSQuantitative SourceAttribution?YesYesYesNoNoYesNumberof sources that can bedistinguished?Usually <10Usually <107< Number of speciesanalyzedUsually4-8transport patternsUsually 4-8transportpatternsAveragingTimeofResult?SameasmonitoringdataSameasmonitoringdataSameasmonitoringdataSameasmonitoringdataSameasmonitoringdataPrevioususe atClass IAreas?(SeeTextforReferences)YesNo?No?YesYesYesMagnitude ofimpacts?YesYesYesNoNoYesFrequencyofimpacts?YesYesYesYesYesYesDuration ofimpacts?YesYesYesNoYesYesTimeofDay ofimpacts?Dependsoninput dataDepends oninput dataDepends oninputdataDepends oninputdataDepends oninputdataDepends oninputdataTimeofYearofimpacts?YesYesYesYesYesYesAppropriate forwhat source-receptordistances?Urban toregionalscalesUrban toregionalscalesUrban toregionalscalesUrban toregionalscalesRegional ScaleRegional ScaleAttribution ofSecondary Species?WithadditionalinformationWithadditionalinformationWithadditionalinformationYesYesYesCost torun?Free topurchase,minimal torun$700topurchase,minimal torunCurrently freetopurchase,minimal torun,$100(student)-1500(full)forMATLABMinimalMinimalMinimalCodeAvailable?YesYesYesNoNoNoEquationsand/oralgorithmsavailable?YesYesYesYesYesYesComputer HardwareNeededPCPCPCPCPCPCAdditionalsoftwarenecessary?NoNoMATLABwithoptimizationtoolboxAny statisticspackageAny statisticspackage withability todosingular valuedecompositionsAny statisticspackagewithability todosingular valuedecompositionsEPA Model?YesNo?Yes?NoNoNo76Observational Modeling Techniques (continued)Analyses of Unique Tracer DataCriteriaTMBRDMBTAGITQuantitativeSource Attribution?YesYesYesNumber of sources that can bedistinguished?1-31-31/tracerAveraging Timeof Result?Sameasparticulate dataSameas particulate dataPrevious use at Class I Areas? (SeeText for References)YesYesYesMagnitudeofimpacts?YesYesYesFrequency of impacts?YesYesYesDuration of impacts?YesYesYesTimeof Day of impacts?Depends on particulate dataDepends onparticulate dataDepends on particulate dataTimeofYearof impacts?YesYesYesAppropriate for what source-receptordistances?Urban to Regional ScaleUrban to RegionalScaleRegional ScaleAttribution of SecondarySpecies?YesYesYesCost to run?MinimalMinimalMinimalCode Available?NoNoNoEquations and/or algorithmsavailable?YesYesYesComputer Hardware NeededPCPCPCAdditional software necessary?Any programming language,spreadsheet,or statisticalpackageAny programminglanguage,spreadsheet,orstatistical packageAny programming language, spreadsheet,or statistical packageEPA Model?NoNoNo77

## Appendix A : RA BART Rul e (40 CFR 51.300-306)

Sec. 51.300 Purpose and applicability.

Authority: Secs. 110, 114, 121, 160-169, 169A, a nd 301 of the Clean Air Act, (42 U.S.C. 7410, 7414, 7421, 7470-7479, and 7601).

Source: 45 FR 80089, Dec. 2, 1980, unless otherwise noted.

(a) Purpose. The prim ary purposes of this s ubp art are to req u ire States to develop program s to assure reasonable progress toward meeting th e national goal of prev enting any future, and

rem e dying any existing, im pair m e nt of visibility in m a ndatory Class I Federal areas which im pair m e nt results from m a nmade air pollu tion ; a nd to es tablish neces sary additional procedures for new source perm it applicants, States and Fe deral Land Managers to use in conducting the visibility im pact analysis required for new sources under Sec. 51.166. This subpart sets forth requirem e nts addressing visibility im pairm e nt in its two principal form s: ``reasonably attributable' ' im pair m e nt (i.e., im pairm e nt attrib utable to a single source/sm a ll group of sources) and region al haze (i.e., widespread haze from a mu ltitude of s ources which im pairs visibility in every direction over a large area). (b) Applicability. (1) Gene ral Applicability. The provisions of this subpart pertaining to im ple m entation plan requirem ents for assuring re asonable progress in preventing any f u ture and

rem e dying any existing visibility im pairm e nt are applic able to: (i) Each State which has a m a ndatory Class I Federal area iden tified in part 81, subpart D, of this title, an d Each State in which th ere is any source the em issions from which m a y r easonably be anticipated to cause or contribute to any im pairm e nt of visibility in any such area. (ii)The provisions of this subpart pertaini ng to implem e ntation plans to address reasonably attributable visibility im pairm e nt are applic able to the following States : Alabam a, Alaska, Arizona, Arkansas, California, Colorado, Florida, Georgia, Hawaii, Idaho, Kentucky, Louisiana, Maine, Michigan, Minnesota, Missouri, Montan a, Nevada, New Ha m p s h ire, New Jersey, New Mexico, North Carolina, North Dakota, Okla hom a , Oregon, South Carolina, South Dakota, Tennessee, Texas, Utah, Verm ont, Virginia, Vi rgin Islands, Washington, W e st Virginia, Wyom ing. (3) The provisions of this subpart p e rtaini ng to implem e ntation plans to address regio n al haze visibility im pairm e nt are applicable to all States as defined in section 302( d) of the Clean Air Act (CAA) except Guam , Puerto Rico, A m erican Samoa, and the Northern Mariana Islands.

[45 FR 80089, Dec. 2, 1980, as am ended at 64 F R 35763, July 1, 1999]

Sec. 51.301 Definitions.

For purposes of this subpart: Adverse impact on visibility m eans, for purposes of section 307, visibility im pairm e nt which interferes with the m a nagem e nt, protection, pres ervation, or enjoym ent of the visitor' s visual experience o f the Federal Class I area. This dete rm ination m u st be m a de on a case-by-case basis taking into account the geographi c extent, intensity, duration, fr equency and tim e of visibility im pair m e nts, and how these factors correlate with (1) tim e s of visitor use of the Federal Class I

### area, and (2) the frequency and tim ing of natural conditions that reduce visibility. This term does not include effects on integral vistas. Agency means the U.S

. Environm e n tal Protection Agency. BART-eligible source m eans an existing stationary facility as defined in this section. Best Available Retrofit Technology (BAR T) m eans an em ission lim itation based on the degree of reduction achievable through the application of th e best system of continuous em ission reduction for each pollutant which is em itted b y an exis tin g stationary f acility. The em ission lim itation must be established, on a case-by -case basis, taking into consid eration the technology available, the costs of com p liance, the energy and nonair qu ality environm ental im pa cts of com p l i ance, any pollution control equipm ent in use or in ex isten ce at the sou r ce, th e rem a ining us ef ul lif e of the source, and the degree of im prove m e nt in visibi lity which m a y reasonably be anticipated to result from t h e use of such technology. Building, structure, or facility m eans all of the pollutant-emitt ing activities whic h belong to the

sam e industrial grouping, are located on one or more contiguous or adjacent properties, and are under the co ntrol of the s a m e person (or pe rsons under common contro l). Pollutan t -em itting activities must be considered as part of the sa m e industrial grouping if they belong to the sam e Major Group (i.e., which have the sam e two-digit code) as described in the Standard Industrial Classification Manual, 1972 as am ended by th e 1977 Supplem ent (U.S. Governm e nt Printing Office stock num b ers 4101-0066 an d 003-005-00176-0 respectively). Deciview m eans a m e asurem ent of visibility impairm ent. A deciview is a haze ind e x deriv e d from calculated light extinction, such that uniform changes in haziness correspond to uniform increm ental changes in p e rcep tion across the entir e range of conditions, from pristine to highly im paired. The deciv i ew haze index is calcu la ted based on the following equation (for the purposes of calculating deciview, th e atm o spheric light ex tin ction co efficient m u st be calcu lated from aerosol m easurem ents): Deciview haze index = 10 ln e 

### (b ext 

### /10Mm -1 

### ) W h ere b ext 

### = the atm o spheric light extinction coefficient, expressed in inverse m e gam e ters (Mm -1 

### ).

Existing stationary facility m eans any of the following stationary sources of air pollutants, including any reconstructed s ource, which was not in operati on prior to August 7, 1962, and was in existence on August 7, 1977, and ha s the potential to em it 250 tons per year or m o re of any air pollutant. In determ ining potential to em it, f ugitiv e em issions, to the ex ten t quantif iable, m u st be counted. Fossil-fuel fired steam electric plan ts of m o re th an 250 m illion British th erm a l units per hour heat input, Coal cleaning plants (therm al dryers), Kraf t pulp m ills, Portland cem e nt plants, Prim ary zinc sm elters, Iron and s t eel m ill plan ts, Prim ary alum inum ore reduction plants, Prim ary copper sm elters, Municipal incinerators capable of charging m o re than 250 tons of refuse per day, Hydrofluoric, sulfuric , and nitric acid plants, Petroleum refineries, Lim e plants, Phosphate rock processing plants,

### Coke oven batteries, Sulfur recovery plants, Carbon black plan ts (f urnace p r ocess), Prim ary lead sm elters, Fuel conversion plants, Sintering plants, Secondary m e tal production facilities, Che m ical process plants, Fossil-fuel boilers of more than 250 m illion British therm a l units per ho ur heat input, Petroleum storage and transfer facili ties with a capacity exceeding 300,000 barrels, Taconite ore processing facilities, Glass fiber pr ocessing plants, and Charcoal production facilities.

Federal Class I area m eans any Federal land that is clas sified or reclas s i fied Class I. Federal Land Manager m eans the Secretary of th e departm e nt with auth ority over the Federal Class I area (or the Secretary' s designee) or, with respect to R oosevelt- Campobello International Park, the Chairm an of the Roosevelt-Ca m pobello International Park Comm ission. Federally enforceab l e m eans all lim itations and conditi ons which are enforceable by the Adm i nistrator under the Clean Air Act including those requirem ents developed pursuant to parts 60 and 61 of this title, requirem e nts within a ny applicable State Im plem e n tation Plan, and any
perm it requirem e nts established pursuant to S ec. 52.21 of this chapter or under regulations approved pursuant to part 51, 52, or 60 of this title. Fixed cap ital cost m eans the capital needed to provide all of the depreciable com ponents. Fugitive Em issions m eans those em issions wh ich could not reasonably p a ss through a stack, chim ney, vent, or other func tionally equivalent opening.

Geographic enhancem ent for the purpose of Sec. 51.308 means a m e thod, procedure, or process to allow a broad regiona l strategy, such as an em issions trading program designed to achieve g r eater reasonab l e progress than BART for region al h aze, to acco mmodate BART for reasonably attributable impairm ent.

Implementation plan m eans, for the purposes of this part, any State Im pl em entation Plan, Federal Im plem entation Plan, or Tribal Im plem entation Plan. Indian tribe or tr ibe means any Indian tribe, band, na tion, or other organized group or community, including any Alaska Na tive v illage, which is f e derally re cog n ized as elig ible f o r th e special prog ram s and services prov id ed by the Unite d States to Indians b ecause of th eir s t atu s as Indians.

In exis t ence m eans that the owner o r operator ha s obtain e d all necess a ry preconstruction approvals or perm its required by Federal, S t ate, or local air pollution em issions and air quality laws or regulations and either has (1) begun, or caused to begin, a continuous program of physical on-site construction of th e facility or (2) entered into binding agreem ents or contractual obligations, which cannot be cancelled or m odifi e d without substantial loss to the owner or operator, to undertake a program of construction of the facility to be com p leted in a reasonable tim e.

In operation m eans engaged in activity related to the prim ary design function of the source. Installatio n m eans an identifiab l e p i ece of process equipm ent.

### Integral vista m eans a view perceived from wi thin th e m a ndatory Class I Federal area of a specific landm a rk or panoram a located outside the boundary of the m a ndatory Class I Federal

area.

Least impaired days m eans the average vis i bility im pair m e nt (m easured in deciv i ews ) for the twenty percent of m onit o red days in a calenda r year with the lowest am ount of visibility im pair m e nt. Major stationary source and m a jor modification m ean m a jor stationary source and m a jor modification, respectively, as defined in Sec. 51.166.

Mandatory Class I Federal Area m eans any area identified in part 81, subpart D of this title. Most impaired days m eans the average vis i bility im pair m e nt (m easured in deciv i ews ) for the twenty percent of m onit o red days in a calendar year with the highest am ount of visibility im pair m e nt. Natural co nditions includes naturally occurring phenom ena that reduce visibility as m easured in term s of l i ght extinction, visu al range, contrast, or coloration.

Potentia l to emit m eans the m a xi mum capacity of a sta tionary source to em it a pollutant under its physical and operational design. Any physical or operational lim itation on the capacity of the source to emit a pollutant includ ing air pollution control equipm en t and restrictions on hours of operation or on the type or am ount of m a terial combusted, stored, or processed, shall be treated as part of its design if the lim itation or the effect it would have on em issions is federally enforceable. Secondary em issions do not count in determ ining the potential to em it of a stationary source.

Reasonably attributable m eans attributable by visual obser vation or any other technique the State deem s appropriate. Reasona bly attributable visibility im pairm e nt m e ans visibility im pair m e nt that is caused by the em ission of air pollutants from one, or a sm all num b er of

sources.

Reconstru c tion will be presum ed to have taken place wh ere the fixed capital cost of the new

com ponent exceeds 50 percen t of the fixed capital co st of a com p arable entirely new source. Any final decisio n as to whether reconstruction has o ccurred m u st be m a de in accordan ce with the provisions of Sec. 60.15 (f) (1) through (3) of this title.

Regional haze m eans visibility im pairm e nt that is cause d by the em ission of air pollutants from

num e rous sources located over a wide geographic area. Such sources include, but are not lim ited to, m a jor and m i nor stationary sources, m obile sources, and area sources. Secondary emissions m eans em issions which o ccur as a re sult of the construction or operation of an existing stationary facility but do not com e from the ex isting stationary facility. S econdary

em issions may include, but are not lim ited to, emi ssions from ships or trains com i ng to or from the existing stationary facility. Significant impairment m eans, for purposes of Sec. 51.303, vi sibility im pairm e nt which, in the judgm ent of the Adm i nistrator, interf eres with the m a nagem e nt , protection, preservation, or enjoym ent of the visitor' s visual exp e rien ce of the m a ndatory Class I Federal area. This determ ination m u st be made on a case-by-case basis taking into account the geographic extent, intensity, duration, frequency and tim e of the vi sibility im pa irm e nt, and how these factors

corre late with (1) tim e s of vi sitor use of the m a ndatory Cla ss I Federal area, and (2) the frequency and tim ing of natural co nditions that reduce visibility.

State m eans ``State' ' a s defined in section 302(d) of the CAA. Stationary Source m eans any building, struct ure, facility, or insta llation which em its or m a y

em it any air pollutant.

### Visibility impairment m eans any hum anly perceptible change in visibility (light extinction, visual range, contrast, coloration) from that which would have existed under na tu ral c onditions. Visibility in any mandatory Class I Federal area includes any integral vista associated with that area.

[45 FR 80089, Dec. 2, 1980, as am ended at 64 F R 35763, 35774, July 1, 1999]

Sec. 51.302 Im ple m entation control strategies for r easonably attributable visibility im pairm e nt.

(a) Plan R e vision Procedures. (1) Each State identified in Sec. 51.300(b)(2) m u st have subm itted, not later than Septem ber 2, 1981, an imple m e ntation plan m eeting th e requ irem ents of this subpart pertaining to reasonably attributable visibility im pairm e nt. (2)(i) The State, prior to adoption of any im ple m entation plan to address reasonably attributable visibility im pairm e nt required by this subpart, m u st conduct one or m o re public hearings on such plan in accordan ce with Sec. 51 .102. (ii) In addition to the requirem e nts in S ec. 51.102, the State m u st pr ovide written notification of such hearings to each affected Federal La nd Manager, and other aff ected States, and m u st state where the public can inspect a s u mm ary prep ared by the Federal Land Managers of their conclusions and recommendations, if a ny, on the proposed plan revision. (3) Subm i ssion of plan s as requ ired by this subp art m u st be conducted in accordan ce with the procedures in Sec. 51.103. (b) State and Federal L a nd Manager Coordina tion. (1) The State m u st identify to the Federal Land Managers, in writing and with in 30 days of the date of pr om ulgation of these regulations, the title of the of f i cial to which the F e dera l La nd Manager of any m a ndatory Class I Federal area can subm it a recomm endation on the im ple m entation of this subpart including, but not lim ited to: (i) A list of integral vist as that are to be listed by the St ate for the purpose of im ple m enting section 304, (ii) Identification of impairm ent of visibil ity in any m a nda tory Class I Federal area(s), and (iii) Identification of elem ents for inclusi on in the visibility mon itoring strategy required by section 305. (2) The State m u st provide opportunity for c onsultation, in person and at least 60 days prior to holding any public hearing on the plan, with th e Federal Land Manager on the proposed SIP revision required by this subpart. This consultation m u st include the opportunity for the affected Federal Land Managers to discuss their: (i) Assessm e nt of i m pairm e nt of visibi lity in any m a ndatory Cl ass I Federal area, and (ii) Recommendations on the de velopm ent of the long-term strategy. (3) The plan m u st provide procedures for continuing consultation between the State and Federal Land Manager on the im plem entation of the visibility protection program required by this subpart. (c) General plan requirem e nts for reasonabl y attributable visibili ty im pairm e nt. (1) The affected Federal Land Manager m a y certify to the St ate, at an y tim e, that there ex ists reasonably attributable impairm ent of visibility in any m a nda tory Class I Federal area. (2) The plan m u st contain the following to addr ess rea s onab l y attribu t ab le im pairm e nt: (i) A long-term (10-15 years) strategy, as specif i ed in Sec. 51.305 and Sec. 51.306, including such em ission lim itations, schedules of com p liance, and such other m easures including schedules

### for the im plem entation of the elem ents of the lo ng-term strategy as m a y be necessary to m a ke reasonable progress toward the natio nal goal specified in Sec. 51.300(a). (ii) An assessm ent of visibi lity im pairm e nt and a discussion of how ea ch elem ent of the plan relates to the preventing of future or rem e dying of existing impairm e nt of visibility in any

m a ndatory Class I Fede ral a r ea with in the State. (iii) Em ission lim itations representing BART and schedules for com p l i ance with BART for each existin g stationary facility iden tified acco rding to parag r aph (c)(4) of this section. (3) The plan m u st require each source to m a intain control equipm ent required by this subpart and establish procedures to ensure such contro l equipm ent is properly operated and m a intained. (4) For any existing reasonably attributable visibility im pairm e nt the Federal Land Manager certifies to the State under para graph (c)(1) of this section, at least 6 m ont hs prior to plan subm ission or revision: (i) The S t ate m u st identify and an alyze for B A RT each existing stationary facility which m a y reasonab l y b e anticipated to cause or contribute to im pair m e nt of visibility in any m a ndatory Class I Fede ral a r ea whe r e the im pairm e nt in th e m a ndatory Class I Federal area is reasonably attributable to that ex isting stat ionary facility. The State need not consider any integral vista the Federal Land Manager did not identify pursuant to Sec. 51.304(b) at least 6 m onths before plan subm ission. (ii) If the State determ in es that technologicial or econom ic lim itations on the applicability of

m easure m ent m e thodology to a particular exis tin g stationary facility w ould m a ke the imposition of an e m ission standard infeasible it m a y instead prescribe a design, equipm ent, work practice, or other operational standard, or com b ination thereo f

, to require the application of BART. Such standard, to the degree possible, is to set f o rth the em issi on reduction to be achieved by im ple m entation of such design, equipm ent, work practice or operation, and m u st provide for

com p liance by m eans which achieve equivalent results. (iii) BART m u st be determ ined for fossil-fu el fired generating plants having a total generating capacity in excess of 750 m e gawatts pursuant to ``Guidelines for Determ ining Best Available Retrofit Technology for Coal-fired P o wer Plants and Other E x isting S t ationary Facilities' ' (1980), which is incorporated by reference, exclus ive of appendix E, which was published in the Federal Register on February 6, 1980 (45 FR 8210). It is EPA publication No. 450/3-80-009b and is for sale from the U.S. Departm e nt of Commerce, National Techn i cal Inform ation Serv ice, 5285 Port Royal Road, Springfield, Virginia 22161. It is also available for inspection at the Office of the Federal Register Informati on Center, 800 North Capitol NW ., suite 700, Washington, DC. (iv) The p l an m u st require that e a c h existi ng stationa ry f acility require d to install an d operate BART do so as expeditiously as practicable but in no case late r than five years after plan approval. (v) The plan m u st provide for a BART analysis of any existing stationa ry facility that m i ght cause or contribute to impairm e nt of visibility in any m a ndatory Class I Federal area identified under this paragraph (c)(4) at such tim es, as de term ined by the Adm i nistrator, as new technology for control of the pollutant becom e s reasonably available if: (A) The pollutant is e m itted by that existing stationa ry f acility, (B) Controls representing BA RT for the pollutant have not prev iously been required under this subpart, and (C) The impairm ent of visibility in a ny m a nda tory Class I Federal area is reasonably attributable to the em issions of that pollutant.

### [45 FR 80089, Dec. 2, 1980, as am ende d at 57 F R 40042, Sept. 1, 1992; 64 FR 35764, 35774, July 1, 1999]

Sec. 51.303 Exem ptions from control.

(a)(1 ) Any existing stationary facility sub j ect to the requ irem ent under Sec. 51.302 to install, operate, and m a intain B A RT m a y a pply to the Adm i nistrator for an exemption from that requirem e nt. (2) An application under th is section m u st include all availa ble docum entation relevant to the im pact of the source' s em issions on visibility in any m a ndatory Class I Federal area and a dem o nstration by the existing stationary f acility tha t it does not o r will not, by itse l f or in c o m b ination with othe r s ources, em it any air pollutant which m a y be reasonably anticipated to cause or co ntri bu te to a signif i can t impairm ent of visibility in any m a nd atory Class I Federal area. (b) Any fossil-fuel fired power plant with a total generating capaci ty of 750 m e ga watts or

more m a y re ceive an exemption from BART only if the owner or operato r of such power plant dem onstrates to the satisfaction of the Adm i nistrator that such pow er plant is lo cated at such a distan ce f r o m all m a ndatory Class I Federal area s that su ch p o wer plant d o es not or w ill no t, by itself or in com b ination with other sources, em it any air pollutant which m a y reasonably be anticipated to cause or contribu te to significant impairm ent of vi sibility in any such m a ndatory Class I Fede ral a r ea. (c) Application under this Sec. 51.303 m u st be accom p anied by a written concurrence from the State with regulatory authority over the source. (d) The existing stationary facility m u st gi ve prior wr itten notice to all affected Federal Land Managers of any application fo r exemption under this Sec. 51.303. (e) The F e deral Land Manager m a y provide an initial recommendation or comm ent on the disposition of such application. Such recomm endation, where provided, must be part of the

exem ption application. T h is recommendation is not to be construed as th e concurrence required under paragraph (h) of this section. (f) The Adm i nistrator, within 90 d a ys of recei p t of an application for ex em ption from control, will prov ide notice of receipt of an ex em ption application and notice of op portunity for public hearing on the application. (g) After notice and opport unity for public hearing, the Adm i nistrator m a y grant or deny the

exem ption. For purposes of judici al review, final EPA action on an application for an exem ption under th is Sec. 51.303 will no t occu r until EPA approves or d i sapproves the State Im ple m entation Plan revision. (h) An ex em ption granted by the Adm i nist rator under th is Sec. 51.303 will be effective on ly upon concurrence by all affected Federal Land Mana gers with the Adm i nistrator' s determ ination.

[45 FR 80089, Dec. 2, 1980, as am ended by 64 FR 35774, July 1, 1999]

Sec. 51.304 Identification of integral vistas.

(a) On or before December 31, 1985 the Federal Land Manager m a y identify any integral vista. The integral vista must be iden tif ied ac cord ing to c r iteria the Federal Land Manager

### develops. T h ese criteria must in clude, but are not lim ited to, wh ether th e integ r al v i sta is im portant to the vis ito r' s visual experience of the m a ndatory Cl ass I Federal area. Adoption of criteria m u st be preced ed by reasonab l e notice and opportunity for public comm ent on the proposed criteria. (b) The F e deral Land Manager m u st notify th e State of any integral vistas identified under paragraph (a) of this secti on, and the reasons therefor. (c) The State m u st list in its im plem entation plan any integral vista the Federal Land Manager identifies at least six m onths pr ior to plan subm ission, and must li st in its im ple m entation plan at its earliest opportunity, and in no case later than at th e tim e of the periodic review of the SIP required by Sec. 51.306(c), any integr al vista the Federal Land Mana ger identifies after that tim e

. (d) The State need no t in its im plem entation plan lis t any integra l vis t a the iden tif ic ation of which was not m a de in accordance with th e criteri a in paragraph (a) of this section. In m a king this finding, the State m u st carefully consider the expertise of the Federal Land Manager in

m a king the judgm e nts called for by the criteria for identification. W h ere the State and the Federal Land Manager disagree on the identification of any integral vista, the State m u st give the Federal Land Manager an opportunity to c onsult with the Gover nor of the State.

[45 FR 80089, Dec. 2, 1980, as am ended by 64 FR 35774, July 1, 1999]

Sec. 51.305 Monitoring for reasonab l y at tribu t ab le vis i bility impairm ent.

(a) For the purposes of a ddressing reasonably attributable vi sibility im pairm e nt, each State containing a m a ndatory Class I Fe deral area m u st include in the plan a strategy for evaluating reasonably attributable visibility im pairm e nt in any m a ndatory Class I Federal area by visual observation or other appropriate m onitoring techniques. Such stra tegy m u st take into account

curren t and anticipated vi sibility m o nitoring research, the ava ilab ility of appropria te monitoring techniques, and such guidance as is provided by the Agency. (b) The plan m u st provide for the consideratio n of available visibility data and m u st provide a

m echanis m for its use in deci sions required by this subpart.

[45 FR 80089, Dec. 2, 1980, as am ended at 64 F R 35764, July 1, 1999]

Sec. 51.306 Long-term strategy requirem ents for r easonably attributable visibility im pairm e nt.

(a)(1 ) For the purposes of addressing reasonab l y attributable visib i lity impairm ent, each plan must include a long-term (10-15 years) strate gy for m a king reasonable progress toward the national goal specified in Sec. 51.300(a). This strategy m u st cove r any existing im pairm e nt the Federal Land Manager certifies to the State at least 6 m onths pr ior to plan subm ission, and any integral vista of which the Federal Land Manager no tif ie s the State a t le as t 6 m onths prior to plan subm ission. (2) A lon g -term strategy m u st be develope d f o r each m a ndatory Cla s s I Federal area located within th e State and each m a ndatory Class I Fede ral area located outside the State which m a y be affected by sources with in the State. This does not preclude the de velopm ent of a single

com p rehensive plan for all such areas

.

### (3) The plan m u st set forth with reasonable specificity why the long-term strategy is adequate f o r m a king reasonable pr ogress towa r d the nation al vis i bility goal, inc l uding rem e dying existing and preventing future impairm e nt. (b) The State m u st coordinate its long-term strategy for an area with existing plans and goals, including those provided by the a ffected Federal Land Managers, th at may affect impairm e nt of visibility in any m a ndato ry Class I Federal area

. (c) The plan m u st provide for periodic revi ew and revision, as appr opriate, of the long-term strategy for addressing reasonably at tribu t able visibility im pairm e nt. The plan m u st provide for such period ic review and revis i on not less f r equen tly th an ever y 3 years un til the da te o f subm ission of the State' s first plan addressing re gional haze visibility im pairm e nt in accordan ce with Sec. 51.308(b) and (c). On or before this da te, the State must revise its plan to provide for review and revision of a coordi nated long-term strategy for addr essing reasonably attributable and region al haze vis i bility im pairm e nt, and the S t ate m u st su bm it the firs t such coord i nated long-term strategy. Fu tu re coord i nated long-term st rateg i es must be subm itted consistent with th e schedule for period ic pro g ress reports set forth in Sec. 51.308(g). Until the State revis e s its plan
to m eet this requirem e nt, the State must continue to com p ly with existing requirem e nts for plan review and revision, and with all em ission m a na gem e nt requirem e nts in the plan to address reasonably attributable impairm ent. This requir em ent does not affect any preexisting deadlines for State sub m ittal of a long-term strategy review (or elem ent thereof) b e tween August 30, 1999

, and the date required for subm ission of the State' s first region al haze p l an. In addition, the plan must provide for review of the long-term strate gy as it applies to reasonably attributable im pair m e nt, and revision as appropriate, within 3 years of State receip t of any certification of reasonab l y attributab le impairm ent from a Fede ral Land Manager. The review process m u st include cons ulta tion with the a ppropriate Federal Land Managers, and the State m u st provide a report to the public and the Adm i nistrator on p r o g ress towa rd the national goal. This report m u st include an assessm ent of: (1) The progress achieved in rem e dying existi ng im pair m e nt of visibility in any m a ndatory Class I Fede ral a r ea ; (2) The ability of the long-term strategy to prevent future impairm ent of visibility in any

m a ndatory Class I Federal area; (3) Any change in visibility since the last su ch report, o r , in the cas e of the first report, since plan approval; (4) Additional m easures, including the need fo r SIP revisions, that m a y be necessary to assure reasonab l e p r ogress towa rd the na tion a l vis i bility goal; (5) The progress achieved in im plem enting BA RT and m eeting other schedules set forth in the long-term strategy; (6) The impact of any exem ption granted under Sec. 51.303; (7) The need for BART to rem e dy existing visi bility im pair m e nt of any integ r al v i sta lis ted in the plan since the last su ch re port, or, in the case of the fi rst report, since plan approval. (d) The long-term strategy m u st provide for review of the impacts from any new m a jor stationary so urce or m a jor m odif i cations on visib i lity in any mandatory Class I Fede ral area. This review of major stationary sour ces o r m a jor m o difications must be in accordance with Sec. 51.307, Sec. 51.166, Sec. 51.160, and any other binding guidance provided by the Agency insofar as these provisions pertain to protection of visibility in any m a nda tory Class I Federal

areas.

### (e) The State m u st consider, at a m i nim u m , the following factors during the deve lop m ent of its long-term strategy: (1) Em ission reductions due to ongoing air pollution control program s, (2) Additional em ission lim itations and schedules for com p l i ance, (3) Mea s u r es to m itiga t e the im pacts of constru c tion a c tiv ities, (4) Source retirem e nt and replacement schedules, (5) Sm oke m a nagem e nt techniques for ag ricultural and forestry m a nagem e nt purposes including such plans as cu rrently ex is t within the State f o r th e s e purposes, and (6) Enforceability of em ission lim i t ations and control m easures. (f) The plan m u st discuss th e reasons why the above and other reason able m easures considered in the developm ent of the long-term strategy were or were not adopted as part of the long-term strategy. (g) The State, in developing the long-term st rategy, m u st take into account the effect of new sources, and the costs of com p liance, the tim e necessary for compliance, the energy and nonair quality environm ental im pacts of compliance, a nd the rem a ining useful life of any affected existing sou r ce and equ i pm ent therein.

[45 FR 80089, Dec. 2, 1980, as am ended at 64 F R 35764, 35774, July 1, 1999]Appendix A-9 – Mobile Sources Arizona Regional Haze SIP 

## APPENDIX A-9. MOBILE SOURCES

This appendix contains work products a nd references relied u pon by Arizona in the development of Chapter 9 of the Regional Haze SIP.Appendix A-9 – Mobile Sources Arizona Regional Haze SIP 

## Appendix A-9a. Arizona Mobile Source Work Group Findings and Recommendations Related to Mobile Source Emissions

## Arizona Regional Haze Mobile Source Working Group Mobile Source Significance Determination

INTRODUCTION

Statement of Purpose

This report presents the findings of t he Mobile Source Working Group (MSWG) regarding the significance of Arizona mobile source emissions on the visibility impairment for the 16 Class I areas on the Co lorado Plateau. The other Class I areas within the State will not be addr essed here but will be addressed under Section 309(g) of the Regional Haze Rule (RHR) later. The MSWG’s analysis was based on the regulatory requirements in 40 CFR 51.309(d )(5)(i-iii), the Grand Canyon Visibility Transport Commission (GCVTC) report that fo rmed the basis for t hose regulations, and information from the Western Regi onal Air Partnership (WRAP).

The MSWG provides this report to the Ar izona Department of En vironmental Quality (ADEQ) for their consideration in prep aring the Arizona R egional Haze State Implementation Plan (SIP).

Summary of Findings

Based on the analysis of available data, the MSWG finds that mob ile source emissions in Arizona do not significantly contribute to visibility impairm ent in any of the 16 GCVTC Class I areas on the Colorado Plateau.

In reaching that conclusion, the MSWG analyzed mobile source pollutant emissions data of volatile organ ic compounds (VOC), oxides of nitrogen (NO X 

### ), sulfur dioxide (SO 2 

### ), elemental carbon (EC), organic ca rbon (OC), and fine particulates (PM 2.5 

### ) for the years 2003 to 2018; air quality modeling and ot her technical information available from the WRAP; their approach in making the signi ficance determination for the region, and the Environmental Protection Agency (EPA) current and future programs and their potential benefits. This conclusion is based upon the findings listed below, and explained in this report.

1) Mobile source emi ssions of VOC, NOx, PM 2.5, 

### SO 2 

### , EC, and OC will decline from 2003 to 2018.

2) Year to year mobile sour ce emissions of VOC, NOx PM 2.5 

### , EC, and OC are expected to decline from 2003 to 2018.

3) Annual mobile sour ce emissions of SO 2 

### are expected to decline from 2003 to 2013 with a slight increase from 2013 to 2018 with proposed federal standards for non-road equipment and diesel fuel. T he minor increase is uncertain and cannot be accurately quantified and will be further addressed in the Technical

### Support Document (TSD). In the ev ent that the EPA proposed non-road standards are not adopt ed, Ariz ona will be required to submit a SIP revisio n as proposed by the WRAP, in their letter dated May 6, 2003 to ens ure reasonable progress prior to December 31, 2008.

4) Annual mobile source emissions of VOC, N O x PM 2.5 

### , EC, and OC are expe cted to have a minimal im pact on visibility.

5) Reasonable progress wil l be achieved over the planning per iod with the projected emission reductions.

6) The relativ e contribution of mobile sourc e SO 2 

### emissions is insignific ant compared to that of the emissi ons from stationary sources.

7) There is c onsiderable uncertainty in r egulations and projections of emissions. The projected increas e in SO 2 

### f o r the later part of t he planning period is not certain. By 2008, the emissions for 2013 can be better assessed with so me certainty.

REGULATORY REQUIREMENT

Regional Haze Rule

The federal RHR relies upon the GCVTC report as the basis for s t ates to submit a SIP under 40 CFR 51.309(d)(5).

Section 30 9 of the RHR requires states to evaluate mo bile so urce emissions, and if they are determined to significantly c ontribute to regional haze in the 16 Class I areas, then additional provisions apply.

SIPs developed under Section 309 must include the following elem ents:

• A statewide inv entory of current mobile source emi ssions and projected future emissions of VOC, N O X 

### , SO 2 

### , P M 2.5, 

### EC, and OC, for the years 2003 to 2018. The emiss i ons inv e ntory must also inc l ude projections for 2005, or an alternative year when the mobile source emissions are found to be at their lowest levels (40 CFR 51.309(d)(5)(i)).

• A determination of whether mobile sour ce emissions from any areas in the state “contribute sig n ificantly” to visib ilit y imp a irment at any of the 16 Class I areas (40 CFR 51. 309(d)(5)(ii)).

• If any area of the state is found to co ntribute significantly to visibility impairment at any of those 16 Class I ar eas, the SIP must also include:

2

### o An emiss i on budget (cap) and measur es to ensure that emissions do not increase beyond their lowest project ed levels for the planning period (40 CFR 51.30 9(d)(5)(iii)(A)).

o An emission tracking system to ensur e that mobile source emissions do not increase thereafter ( 40 CFR 51.309(d)(5)(iii)(B)).

• Progress reports to EPA on the im plementation of mobile source recommendations of the GCVTC (40 CFR 51.309(d)(5)(iv).

In the event that EPA finalizes the rule c hange as proposed, 51.30 9(d)(5)(ii) and (iii) above will then be removed (see below).

WRAP AP PROACH TO S IGNIFICANCE DETERMINATION

Recently, t he WRAP concluded that the attempt to measure mobile source s i gnific a nce is no longer necessary becaus e new federal programs will achiev e continual emission reductions as require d for significant areas in Section 309(d)(5)(iii). On May 6, 2003, the WRAP submitted a letter to EPA prop os ing ame ndments to the RHR t o elimin ate the requirement to conduct the mobile s ource significance determination, and to address non-road mobile sources of SO 2. 

### The WRAP letter is provided in Attachment A. The EPA has published these c hanges to the rule (Federal Re gister Vol.68, No. 128, July 3, 2003), along with a 30- day comment period. EPA has proposed a direct final for the rule. E v en if the rule is challenged it st ill could be finaliz ed by the end of the year.

Proposed WRAP Am endments: Significance Requirements

The GCVT C and the f i nal RHR a ssumed that mobile s ources wer e expected to decline from 2003-2005 and increase annually through 2018. As noted above, the rule required emission budgets in “signific ant ” areas to prevent the increas e in emissions. That goal is being achieved without emission caps because of new federal programs: Tier 1 gasoline s u lfur controls in January 2001, and Tier 2 motor vehicle controls in February 2000, and heavy-duty engine and v ehic l e s t andards and highway diesel sulfur controls in October 2000 and January 2001. New and updated emissions models predict dramatic emission reductions from th ese progr ams. Therefore, the WRAP recommended that EPA remove the requir e ments for the si gnificance determination in Sections 4 0 CFR 5 1 .309(d)(5)(ii) and (iii) and amen d the rule to require states to demonstrate and monitor a cont inuous reduc tion of mobile s ource emissions of each o f the pollutants.

Proposed WRAP Am endments: SO 2 

### Emission Reductions

The WRAP recommendation also specifically addresses the issue of the projected increase in SO 2 

### emissions from non-road mobile s ources in the late years of the plann ing p e riod (201 3-2018). Earlier this year, EPA proposed new stand ards for nonroad equip m ent and non-road d i esel fue l s that will dr amat ically reduce SO 2 

### emission

3

### and ens ure continued emission reductions for this pollutant (F ederal Register Vol.68, No. 100, May 23, 2003). Those rules will not be finalized before December 31, 2003, the deadline for states to subm it their Regional Haze SI Ps. Therefore, the WRA P proposed amendment would require states to submit SIP re visions by 2008 to assess whether reasonable progress is being made and if necessary take action to reduce nonroad SO 2 

### emissions if the EPA d oes not adopt t he proposed fede ral standard to ensure reasonable progress.

SIGNIFICANCE DETE RMINATION AND FINDINGS

The MSWG has determined that mobile sour ces emissions within areas in Arizona do not contribute signific antly to visibility deg radation at the 16 C l ass I areas. This conclus i on also supports the WRAP rec o mmendation that determination of mobile source emissions impact should be remov ed from the RHR and replaced with a requirement for states to demons trate continual mobile source emission reductions over the planning period, considering econo mic and technological reasonableness and applicable state authority of the strategy.

In making the significance det ermination, the MSWG analyzed the Ariz ona mobile

source em issions and the impact of the new federal progr ams to determine if continuous reductions were achieved for each of the pollutants throughout the planning period. T h e MSWG evaluated the technic a l data and r e cent modeling result s prepared by ENVIRON for the WRAP. The findings provided below are based upon that review.

Current and Projected Emissions from Mobile Sources

Inventor y

The WRAP developed comprehensive emis sion in ventories for mobile sources for the State of Ar izona and ot her western states in 5-year in crements. It is ass u med that interim years follow the 5-year trends. Th is inventory included the two major urban areas in the state (Phoenix region represented as Maricopa County, and Tucson region represented as Pima County). The emissions fr om these two counties follow that of the State totals, with their emissions continuing to decline over the planning period. The current and projected statewid e inv entories of emissions from mobile sources ar e shown in T able 1.

Table 1: Arizona Projected Em issions for Mobile Sources 2003 through 2018 T P D

AZ. Total

2003 989.1 2008 733.1 2013 582.2 2018 495.9 % Change -50 %



### 4

### Finding 1. Mobile source emissions of all pollu tant s (VOC, N O x, PM 2.5 

### , EC, OC, and SO 2 

### ) decline from 2003 to 2018.

The analys i s of the Arizona data parallels that of the regi onal analysis conducted by the WRAP. T he succes s of new mobile source control programs is demonstrated most clearly in the dramatic reductions of emission s from 2003 to 2018. During this period o f continued growth in population and vehic l e m iles traveled (VMT), all mobile source emissions are reduced. The total of all m obile source emissions decline 50% for the planning period. An analys is of the data for each po llutant during that same period shows that emissions of VO C and NOx steadily dec line (by 51% and 52% respectively), while PM 2. 5 

### shows a decrease of 22%. Additi onally , because both EC and OC are represented as a per centage of the PM 2.5 

### we can assume that both EC and OC will follow the reduction observed in PM 2.5 

### ; SO 2 

### also declines by 11% (Attachment B).

Finding 2. Year to y e ar mobile source emissions of VOC, NOx, PM 2.5 

### , EC, and OC are expected to decline from 2003 to 2018.

The GCVT C recommended that emissions show reasonable progress. The GCVTC defined reasonable pr ogress as st eady and continuing emission reductions t hat, in the long-term, lead to improvements in vis i bility. This is used as the m easure of r easonable progress under Section 309. T he WRAP and E PA interpretation of the rule requires that each pollutant must be measured separately in the demonstration of continual reductions.

Attachment B provides a demonstr ation that VOC, NOx, and PM 2.5 

### , and hence EC and OC, each s how annual reductions in the planning period and thus m eet the reasonab le progress goal in the RHR.

Finding 3. Annual mobile source emissions of SO 2 

### are expect ed to continuall y decline from 2003 to 2013 w i th a minor increase from 2013 to 2018 w i th proposed federal sulfur standards for non-road diesel.

Annual mobile source emissions of SO 2 

### s how an ov erall decline of 11% over the planning period with existing federal programs (Attachment B). The proposed non-road federal standards are expected to ensure annual emis sion reductions (Attachment C).

As noted in the WRAP letter of May 6, 200 3, the proposed federal non-road standards are critical to this progress. As l ong as EPA ad opts the proposed federal non-roa d standards, reasonable progress is achiev ed. Without these standards, the annua l emission r eductions for mobile sources are achiev ed only until 2013 when SO 2 

### emissions increase from 9.5 tons/day to 18. 6 tons/day (Attachment B). If the non-road standards are adopted , the overall SO 2 

### emissions will decline by 27% from 2003 t o 2018. The slight increase from 2013 to 2018 is uncertain and cannot be accurately quantified and will be further addr essed in the TSD. If EPA fails to adopt the proposed

5

### standards by 2008, Arizona will have adequate time to reassess the progress and adopt state standards if nec essary to account for any emiss i ons increase s in mobile s ourc e emissions. Even t hough some uncertainty ex ist s in these projections, the new standards would ens ure that annual emis sions would decline for SO 2 

### em i ssi ons and therefore all mobile source s emissions in the state.

The RHR clearly does not require a separate analysis of on-road and non-road emissions in making the significance determi nation. Ho wever, t he evaluation of the SO 2 

### emissions data demonstrates the importance of the feder al non-road rule (see Attachments B and C). A comparison of em issions in the year s 2003 and 2018 from Attachment B shows that on-road SO 2 

### emissions decr ease by 78%, while non-road SO 2 

### emissions decrease until 2013 and then inc r ease late in the pl anning period, resulting in a 46% increase overall. That increas e is without the pr oposed federal non-road standards. Assuming the pr opos ed federal standards are adopt ed (see Attachment C), the non-road SO 2 

### emissions decline by 27%.

The point is made even mo re dramatically in a co mparison of 2018 non-road SO 2 

### emissions in Attachments B and C, showing that 2018 SO 2 

### emissions will be 16. 5 tons/day without controls and 8.2 tons/day if the pr oposed federal standards are adopted. This will result in a 50% reduction in non-road SO 2 

### emissions.

Finding 4. Annual mobile source emissions of VOC, NOx, PM 2. 5 

### , EC, and OC are expected to have a minimal impact on visibility

. The WRAP performed a modeling analy sis to estimate the impact of mobile so urce emissions from Phoenix Metropol itan area at the GCVT C Class I in 2018. T he forecas t year 2018 was chosen sinc e it r epresents the year wit h the lowest emissions, and is at the end of the planning period. Table 2 summarizes the re lative impact of emission s from the Phoenix Met r opolitan area at the 16 GCVTC Class I areas, expressed as a percentage of the project ed WRAP 2018 Base Case light extinction. Based on WRAP modeling, by 2018 the impact of mobile sources from Arizona urban areas on the GCVTC class I areas will be bet ween 0% and 4% of the proj ected light extinc tion.

Table 2. C ontribution to Light Extincti on from Phoenix Mobile Source Emissions (Expressed as a % o f WRAP 2018 Base Case Light Extinction)

Class I Are a on the Colorado Plateau Phoenix
Arch es NP 0% Black Canyo n NP 0% Bryce Canyo n NP 0% Canyo n land s NP 0% Capitol Reef NP 0% Flat Tops Wil dern e ss 0% Gran d Ca nyo n NP 1% Maro on Bells Wilde r ne ss 0% Mesa Ve rde NP 1% Mount Baldy Wilde r ne ss 2%



### 6Petrified Fore st NP 4% San Pedro P a rks WA 1% Sycamore Ca nyon WA 2% We st Elk Wil dern e ss 0% W e minuc he W i lder ness 0% Zion NP 0%



### Source: Table 3. Percent change in ligh t extinction over 2018 WRAP Base Cas e Conditions at the 16 Class I areas on th e Colorado Plateau due to Mobile Sourc e Emissions from the 9 GC VTC States, California, Phoenix, and Las Vegas, “WRAP Technical memorandum from the Air Qualit y Modeling Forum to the Mobile Sour ce Forum ” , Novem ber 4, 2002.

Finding 5. Reason a ble progress w i ll be achieved over the planning period w i th the projected emission reductions fo r all mobile source pollutants.

The GCVT C definition of reas onable progress is thus met in findings 2 and 3 abov e, assuming the adoption of the pro posed federal non-road rules.

Finding 6. The relativ e contribution of mobile source SO 2 

### is insignificant compared to that of stationar y sources.

Based upon data from the WR AP Annex, the category of stationary sources is the primary source of SO 2 

### contributing to regional haz e in the GCVT C 16 c l ass I areas. In Arizona, the mobile s ource contributi on to the total concentration of SO 2 

### is relatively small. In 2003, it repres ents about 5.3% of the total; while in 2018, with EPA’s proposed rule, it is about 3.9% of total emi ssions. These data also show that the potential relative contribution of mob ile sources emissions to the total SO 2 

### would be decreasing at a greater rate than that of st ationary so urces with EPA’s new proposed non-road rule. This c ontinued improvement in m obile source emissions is the result of stringent federal progr ams created after t he 1995 GCVTC report. Therefore, the WRAP concluded that the Commission’s concer n about the potential impact from mobile sources has been addressed. Additional federal c ontrol programs for mobile source s will provide an even greater improvement in emissi ons in upcoming years.

Finding 7. The uncertaint y in regulations and projections in e m issions adds to the determination.

It is important to note that uncertainty exis t s in several areas: 1) the adoption of the proposed f ederal non-road standards as propos ed on May 23, 2003; 2) the projected benefits that might be achiev ed, and 3) the projections of em issions from the model for the later years. When looking at the data, the projections fo r the early years are likely to be more v a lid than t hose estim a ted for 2018. This uncertaint y can be addressed through periodic repor ting on the progress of t he reduction in mobile source emissions and then making adjus tments in the SIP.

7

### MSWG RECOMMENDATION TO ADEQ FO R SIGNIFICANCE DETERMINATION:

Based on this analys is, the MSWG concludes that mobile source emissions do not signific antly contribute to regional haze at any of the 16 GCVTC Class I areas. This finding does not attempt to address the other Class I areas in the State t hat will be addressed in the future under Section 309(g ) of the RHR.

In evaluating the impact of mobile source emissions in the 16 Class I areas, the MSWG considered a wide range of in formation from the WRAP anal ysis as well as Arizonaspecific data on total emissions as well as specific pollutants. The Working Group concludes that reductions in mobile source emissions will meet the GCVT C goal of continued reduction throughout the planning period based upon new and proposed federal pro g rams with the EPA adoption of the propo sed non -ro ad rules. In the even t that EPA’s proposed n on-road st andards are not realize d , t he WRAP recom m ends that states be required to file a SIP revision to ensure reasonabl e progress prior to December 31, 2008.

Based upon the findings above, the MSWG recommends that ADEQ consider this report in preparing the significanc e determinat ion for the Arizona Regional Haze SIP.

Should the proposed revisions to the RHR become effective pr ior to the submission of the Arizon a SIP und er Section 309, refer ences to 40 CFR 51. 309(d)(5)(ii-iii) will be eliminated.

List of Attachments:

Attachment A “WRAP Letter to EPA (Dated May 6, 2003)”

Attachment B “Total Ari z on a Mobile Sou r ce Emi s sion s by Pollutant Projecte d for 2003 thro ug h 2018 Assu mi ng No Ne w Regulatio ns”

Attachment C “Total Ari z on a Mobile Sou r ce Emi s sion s by Pollutant Projecte d for 2003 thro ug h 2018, Assumi ng a 15 ppm Sulfur No n-ro ad Die s el Sta ndard”



### 8

### Attachment A

9

### 10

### 11

### 12V OC NOx P M 2

. 5 S O 2 T ota l 2003 448.7 496.5 23.0 20.9 989.1 2008 319.9 381.2 22.0 14.6 737.7 2013 256.9 296.7 19.1 16.6 589.3 2018 222.0 237.3 18.0 18.6 495.9 % Ch an g e - 51%

- 52%

- 22%

- 11%

- 50%

V OC NOx P M 2

. 5 S O 2 * T o ta l 2003 112.1 150.2 14.2 11.3 287.8 2008 77.7 124.4 13.8 13.0 228.9 2013 70.3 111.1 13.3 14.8 209.5 2018 69.7 107.8 13.4 16.5 207.4 % Ch an g e - 38%

- 28%

- 6 % 46%

- 28%

*2003 and 2018 ar e ac tual m odel outpu ts ; 2008 and 2013 ar e ex tr apolated and a s s u m ed to be linear

.

V OC NOx P M 2

. 5 S O 2 T ota l 2003 336.6 346.3 8 .8 9.6 701.3 2008 242.2 256.8 8 .2 1.6 508.8 2013 186.6 185.6 5 .8 1.8 379.8 2018 152.3 129.5 4 .6 2.1 288.5 % Ch an g e - 55%

- 63%

- 48%

- 78%

- 59% Non-road

On -r oa d St at e T o t a l A

t t ach men t B T o t a l A r iz ona Emiss i on by Pollut a nt

P r ojections for 2003 through 2018 A

ssume No Ne w Regulations (T P D )



### Note: Both EC and OC are repres ented as a percent age of the PM 2.5 

### and we can

assume that both EC and OC will follo w the changes ob served in PM 2.5



### 13V OC NOx P M 2

. 5 S O 2 T ota l 2003 448.7 496.5 23.0 20.9 989.1 2008 319.9 381.2 22.0 10.0 733.1 2013 256.9 296.7 19.1 9 .5 582.2 2018 222.0 237.3 18.0 10.3 487.6 % Ch an g e - 51%

- 52%

- 22%

- 51%

- 51%

Note: As s u m e s all the r educ tions as s o c i ated w i th 15 ppm Standar d

c o m e betw een 2013 and 2 018

V OC NOx P M 2

. 5 S O 2 T ota l 2003 112.1 150.2 14.2 11.3 287.8 2008 77.7 124.4 13.8 8 .4 224.3 2013 70.3 111.1 13.3 7 .7 202.4 2018 69.7 107.8 13.4 8 .2 199.1 % Ch an g e - 38%

- 28%

- 6 %

- 27%

- 31%

V OC NOx P M 2

. 5 S O 2 T ota l 2003 336.6 346.3 8 .8 9.6 701.3 2008 242.2 256.8 8 .2 1.6 508.8 2013 186.6 185.6 5 .8 1.8 379.8 2018 152.3 129.5 4 .6 2.1 288.5 % Ch an g e - 55%

- 63%

- 48%

- 78%

- 59% Non-road

On -r oa d St at e T o t a l A

t t ach men t C T o t a l A r iz ona Emiss i on by Pollut a nt

P r ojections for 2003 through 2018 A

ssu me a 15 p p m Su lf u r No n - r o ad Diesel St an d a rd (T P D )



### Note: Both EC and OC are repres ented as a percent age of the PM 2.5 

### and we can

assume that both EC and OC will follo w the changes ob served in PM 2.5



### 14